renegotiation or nullification of existing contracts;
disputes and legal proceedings in international jurisdictions;
changing social, political and economic conditions;
imposition of wage and price controls, trade barriers, export controls or import-export quotas;
difficulties in collecting accounts receivable and longer collection periods;
fluctuations in currency exchange rates and restrictions on currency exchange;
regulatory or financial requirements to comply with foreign bureaucratic actions;
restriction or disruption of business activities;
limitation of our access to markets for periods of time;
travel limitations or operational problems caused by public health threats or changes in immigration policies;
difficulties in supplying, repairing or replacing equipment or transporting personnel in remote locations;
difficulties in obtaining visas or work permits for our employees on a timely basis; and
changing taxation policies and confiscatory or discriminatory taxation.
We are also subject to the regulations of the U.S. Treasury Department’s Office of Foreign Assets Control and other U.S. laws and regulations governing our international operations in addition to domestic and international anti-bribery laws and sanctions, trade laws and regulations, customs laws and regulations, and other restrictions imposed by other governmental or international authorities. Failure to comply with these laws and regulations could result in criminal and civil penalties, economic sanctions, seizure of shipments and/or the contractual withholding of monies owed to us, among other things. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the U.S. Foreign Corrupt Practices Act, the U.K. Bribery Act 2010 or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to substantial fines, sanctions, civil and/or criminal penalties and curtailment of operations in certain jurisdictions. In addition, international contract drilling operations are subject to various laws and regulations in countries in which we operate, including laws and regulations relating to the equipping and operation of drilling rigs; import-export quotas or other trade barriers; repatriation of foreign earnings or capital; oil and gas exploration and development; local content requirements; taxation of offshore earnings and earnings of expatriate personnel; and use and compensation of local employees and suppliers by foreign contractors.
Our consolidated effective income tax rate may vary substantially from one reporting period to another.
Our consolidated effective income tax rate is impacted by the mix between our domestic and internationalpre-tax earningsAny significant cyber attack or losses, as well as the mix of the international tax jurisdictionsother interruption in which we operate. We cannot provide any assurances as to what our consolidated effective income tax rate will be in the future due to, among other factors, uncertainty regarding the nature and extent of our business activities in any particular jurisdiction in the future and the tax laws of such jurisdictions, as well as potential changes in U.S. and foreign tax laws, regulations or treatiesnetwork security or the operation of critical information technology systems could materially disrupt our operations and adversely affect our business.
Our business has become increasingly dependent upon information technologies, computer systems and networks, including those maintained by us and those maintained and provided to us by third parties (for
interpretationexample,“software-as-a-service” and cloud solutions), to conductday-to-day operations, and we are placing greater reliance on information technology to help support our operations and increase efficiency in our business functions. We are dependent upon our information technology and infrastructure, including operational and financial computer systems, to process the data necessary to conduct almost all aspects of our business. Computer, telecommunications and other business facilities and systems could become unavailable or enforcement thereof, changesimpaired from a variety of causes including, among others, storms and other natural disasters, terrorist attacks, utility outages, theft, design defects, human error or complications encountered as existing systems are maintained, repaired, replaced or upgraded. In addition, it has been reported that known or unknown entities or groups have mountedso-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. Cybersecurity risks and threats to such systems continue to grow and may be difficult to anticipate, prevent, discover or mitigate. A breach or failure of our computer systems or networks, or those of our customers, vendors or others with whom we do business, could materially disrupt our business operations and our customers’ operations and could result in the administrative practices and precedentsalteration, loss, theft or corruption of tax authoritiesdata or any reclassificationunauthorized release of confidential, proprietary or other matter (such as changes in applicable accounting rules) that increases the amounts wesensitive data concerning our company, business activities, employees, customers or vendors. Any such breach or failure could have provided for income taxesa material adverse effect on our operations, business or deferred tax assets and liabilities in our consolidated financial statements. This variability may cause our consolidated effective income tax rate to vary substantially from one reporting period to another.reputation.
We may be required to accrue additional tax liability on certain of our foreign earnings.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC, a Cayman Islands subsidiary that we own. It is our intention to continue to indefinitely reinvest the earnings of DFAC and its foreign subsidiaries to finance our foreign activities. We do not expect to provide for U.S. taxes on any earnings generated by DFAC and its foreign subsidiaries, except to the extent that these earnings are immediately subjected to U. S. federal income tax (such as under the Tax Cuts and Jobs Act of 2017). Should a future distribution be made from any unremitted earnings of this subsidiary, we may be required to record additional U.S. income taxes and/or withholding taxes in certain jurisdictions; however, it is not practical to estimate this potential liability.
Acts of terrorism, piracy and political and social unrest could affect the markets for drilling services, which may have a material adverse effect on our results of operations.
Acts of terrorism and social unrest, brought about by world political events or otherwise, have caused instability in the world’s financial and insurance markets in the past and may occur in the future. Such acts could be directed against companies such as ours. In addition, acts of terrorism, piracy and social unrest could lead to increased volatility in prices for crude oil and natural gas and could adversely affect the market for offshore drilling services. Insurance premiums could increase and coverage may be unavailable in the future. Government regulations may effectively preclude us from engaging in business activities in certain countries. These regulations could be amended to cover countries where we currently operate or where we may wish to operate in the future.
Although we have paid cash dividends in the past, we did not pay any dividends in 2017 and we may not pay dividends in the future, and we can give no assurance as to the amount or timing of the payment of any future dividends.
We pay dividends at the discretion of our Board of Directors, or Board. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. The Board’s dividend policy may change from time to time, but there can be no assurance that we will declare any cash dividends at all or in any particular amounts. See “Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities — Dividend Policy” in Item 5 of this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources” in Item 7 of this report.
We rely on third-party suppliers, manufacturers and service providers to secure and service equipment, components and parts used in rig operations, conversions, upgrades and construction.
Our reliance on third-party suppliers, manufacturers and service providers to provide equipment and services exposes us to volatility in the quality, price and availability of such items. Certain components, parts and equipment that we use in our operations may be available only from a small number of suppliers, manufacturers or service providers. The failure of one or more third-party suppliers, manufacturers or service providers to provide equipment, components, parts or services, whether due to capacity constraints, production or delivery disruptions, price increases, quality control issues, recalls or other decreased availability of parts and equipment, is beyond our control and could materially disrupt our operations or result in the delay, renegotiation or cancellation of drilling contracts, thereby causing a loss of contract drilling backlog and/or revenue to us, as well as an increase in operating costs and an increased risk of additional asset impairments.
Additionally, our suppliers, manufacturers and service providers could be negatively impacted by current industry conditions or global economic conditions. If certain of our suppliers, manufacturers or service providers were to experience significant cash flow issues, become insolvent or otherwise curtail or discontinue their business as a result of such conditions, it could result in a reduction or interruption in supplies, equipment or services available to us and/or a significant increase in the price of such supplies, equipment and services.services,.
We must make substantial capital and operating expenditures to build, maintain, and upgrade our drilling fleet.
Our business is highly capital intensive and dependent on having sufficient cash flow and/or available sources of financing in order to fund our desired capital expenditure requirements. Our expenditures could increase as a result of changes in offshore drilling technology; the cost of labor and materials; customer requirements; the cost of replacement parts for existing drilling rigs; and industry standards. Changes in offshore drilling technology, customer requirements for new or upgraded equipment and competition within our industry may require us to make significant capital expenditures in order to maintain our competitiveness. In addition, changes in governmental regulations, safety or other equipment standards, as well as compliance with standards imposed by maritime self-regulatory organizations, may require us to make additional unforeseen capital expenditures. As a result, we may be required to take our rigs out of service for extended periods of time, with corresponding losses of revenues, in order to make such alterations or to add such equipment. We can provide no assurance that we will have access to adequate or economical sources of capital to fund our capital expenditures.
Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in pursuing other business opportunities.
Our business is highly capital intensive and dependent on having sufficient cash flow and/or available sources of financing in order to fund our capital expenditure requirements. As of December 31, 2017,2018, we had
outstanding approximately $2.0 billion of senior notes, maturing at various times from 2023 through 2043. As of February 9, 2018,8, 2019, we had no borrowings outstanding under our $325 million revolving credit facility maturing in 2020 or our $950 million revolving credit facility maturing in October 2023, and $1.5an aggregate $1.275 billion available under ourboth such credit facilityfacilities, subject to their respective terms, to meet our short-term liquidity requirements. WeAt various times in 2019, $100 million of the commitments under our $325 million revolving credit facility will mature, and the remaining $225 million of commitments will mature in October 2020.We may incur additional indebtedness in the future and borrow from time to time under our revolving credit facilityfacilities to fund working capital, capital expenditures or other needs, subject to compliance with itstheir covenants. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations –Liquidity and Capital Resources – Sources and Uses of Cash –Credit Agreements” in Item 7 of this report and Note 10 “Credit Agreements and Senior Notes” to our Consolidated Financial Statements in Item 8 of this report.
Our ability to meet our debt service obligations is dependent upon our future performance, which is subject to general economic conditions, industry cycles and financial, business and other factors affecting our operations, many of which are beyond our control.unpredictable. High levels of indebtedness could have negative consequences to us, including:
we may have difficulty satisfying our obligations with respect to our outstanding debt;
we may have difficulty obtaining financing in the future for working capital, capital expenditures, acquisitions or other purposes;
we may need to use a substantial portion of our available cash flow from operations to pay interest and principal on our debt, which would reduce the amount of money available to fund working capital requirements, capital expenditures, the payment of dividends and other general corporate or business activities;
our vulnerability to the effects of general economic downturns, adverse industry conditions and adverse operating results could increase;
our flexibility in planning for, or reacting to, changes in our business and in our industry in general could be limited;
we may not have the ability to pursue business opportunities that become available to us;
our amount of debt and the amount we must pay to service our debt obligations could place us at a competitive disadvantage compared to our competitors that have less debt; and
require us to maintain a specified ratio of our consolidated indebtedness to total capitalization;
In addition,
require us to maintain a specified ratio of (A) the aggregate value of certain of our $1.5 billionrigs to (B) the aggregate value of substantially all rigs owned by us;
require us to maintain a specified ratio of (A) the aggregate value of certain of our marketed rigs to (B) the sum of the commitments under our $950 million revolving credit facility, matures on October 22, 2020, except for $40 millionplus certain outstanding loans, letter of commitments that mature on March 17, 2019credit exposures and $60 millionother indebtedness; and
limit the ability of commitments that mature on October 22, 2019. Our abilityour subsidiaries to renew or replace our revolving credit facility is dependent on numerous factors, including our financial condition and prospects at the time and the then current state of the bank and capital markets in the U.S. Our liquidity may be adversely affected if we are unable to replace our revolving credit facility upon acceptable terms when it matures.incur debt.
In July 2017, Moody’s Investor Services downgraded our corporate credit rating to Ba3 with a negative outlook from Ba2 with a stable outlook. In October 2017,August 2018, S&P Global Ratings, or S&P, downgraded our corporate credit rating to B from B+ fromBB-;, and Moody’s Investor Services, or Moody’s, downgraded our corporate credit rating to B2 from Ba3. In October 2018, Moody’s downgraded our senior unsecured notes credit rating to B3 from B2. The rating outlook byfrom both S&P and Moody’s remains negative. These credit ratings are below investment grade and could raise our cost of financing. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.
Our revolving credit facility bearsfacilities bear interest at variable rates, based on our corporate credit rating and market interest rates. If market interest rates increase, our cost to borrow under our revolving credit facilityfacilities may also increase. Although we may employ hedging strategies such that a portion of the aggregate principal amount outstanding under our credit facilityfacilities would effectively carry a fixed rate of interest, any hedging arrangement put in place may not offer complete protection from this risk.
Any significant cyber attack or other interruptionChanges in network security or the operation of critical computer systemsaccounting principles and financial reporting requirements could materially disrupt our operations and adversely affect our business.results of operations or financial condition.
Our business has become increasingly dependent upon information technologies, systems and networksWe are required to conductday-to-day operations, andprepare our financial statements in accordance with accounting principles generally accepted in the U.S., or GAAP, as promulgated by the Financial Accounting Standards Board. It is possible that future accounting standards that we are placing greater reliance on technologyrequired to help supportadopt could change the current accounting treatment that we apply to our operationsconsolidated financial statements and increase efficiency in our business functions. We are dependent upon our information technology and infrastructure, including operational and financial computer systems, to process the data necessary to conduct almost all aspects of our business. Computer and other business facilities and systems could become unavailable or impaired from a variety of causes including, among others, storms and other natural disasters, terrorist attacks, utility outages, theft, design defects, human error or complications encountered as existing systems are maintained, repaired, replaced or upgraded. It has also been reported that known or unknown entities or groups have mountedso-called “cyber attacks” on businesses and other organizations solely to disable or disrupt computer systems, disrupt operations and, in some cases, steal data. A breach or failure of our computer systems or networks, or those of our customers, vendors or others with whom we do business, could materially disrupt our business operations and our customers’ operations and could result in the alteration, loss, theft or corruption of data or unauthorized release of confidential, proprietary or sensitive data concerning our company, business activities, employees, customers or vendors. Any such breach or failurechanges could have a material adverse effect on our results of operations business or reputation.and financial condition. For a description of recent accounting standards that we have not yet adopted and, if known, our estimates of their expected impact, see Note 1 “General Information –Recent Accounting Pronouncements Not Yet Adopted” to the Consolidated Financial Statements included under Item 8 of this report.
Failure to obtain and retain highly skilled personnel could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for our business. A well-trained, motivated and adequately-staffed work force has a positive impact on our ability to attract and retain business. As a result, our future success depends on our continuing ability to identify, hire, develop, motivate and retain skilled personnel for all areas of our organization. To the extent that demand for drilling services and/or the size of the active worldwide industry fleet increases, shortages of qualified personnel could arise, creating upward pressure on wages and
difficulty in staffing and servicing our rigs. Our continued ability to compete effectively depends on our ability to attract new employees and to retain and motivate our existing employees. Heightened competition for skilled personnel could materially and adversely limit our operations and further increase our costs.
We are controlled by a single stockholder, which could result in potential conflicts of interest.
Loews Corporation, which we refer to as Loews, beneficially owned approximately 53% of our outstanding shares of common stock as of February 9, 2018,8, 2019, and is in a position to control actions that require the consent of stockholders, including the election of directors, amendment of our Restated Certificate of Incorporation and any merger or sale of substantially all of our assets. In addition, three officers of Loews serve on our Board of Directors. We have also entered into a services agreement and a registration rights agreement with Loews, and we may in the future enter into other agreements with Loews.
Loews is a holding company, with principal subsidiaries (in addition to us) consisting of CNA Financial Corporation, a 90%an 89%-owned subsidiary engaged in commercial property and casualty insurance; Boardwalk Pipeline Partners, LP, a 51%-ownedwholly-owned subsidiary engaged in the transportation and storage of natural gas and natural gas liquids; Loews Hotels & Co, a wholly-owned subsidiary engaged in the operation of a chain of hotels; and Consolidated Container Company LLC, a 99%-owned subsidiary providing packaging solutions to end markets such as beverage, food and household chemicals. It is possible that potential conflicts of interest could arise in the future for our directors who are also officers of Loews with respect to a number of areas relating to the past and ongoing relationships of Loews and us, including tax and insurance matters, financial commitments and sales of common stock pursuant to registration rights or otherwise. Although the affected directors may abstain from voting on matters in which our interests and those of Loews are in conflict so as to avoid potential violations of their fiduciary duties to stockholders, the presence of potential or actual conflicts could affect the process or outcome of Board deliberations.
| Item 1B. |
Not applicable.
| Item 2. |
We own an office building in Houston, Texas, where our corporate headquarters are located. We also own offices and other facilities in New Iberia, Louisiana, Aberdeen, Scotland, Macae, Brazil and Ciudad del Carmen, Mexico. Additionally, we currently lease various office, warehouse and storage facilities in Australia, Louisiana, Malaysia, Singapore and the U.K. to support our offshore drilling operations.
| Item 3. |
See information with respect to legal proceedings in Note 1112 “Commitments and Contingencies” to our Consolidated Financial Statements in Item 8 of this report.
| Item 4. |
Not applicable.
| Item 5. | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities. |
Item 5. Market for the Registrant’s Common Equity, Related Stockholder MattersInformation and Issuer PurchasesHolders of Equity Securities.
Price Range of Common StockRecord
Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol “DO.” The following table sets forth, for the calendar quarters indicated, the high and low closing prices of our common stock as reported by the NYSE.
| Common Stock | ||||||||
| High | Low | |||||||
2017 | ||||||||
First Quarter | $ | 19.49 | $ | 14.70 | ||||
Second Quarter | 16.31 | 10.26 | ||||||
Third Quarter | 14.85 | 10.22 | ||||||
Fourth Quarter | 18.94 | 14.31 | ||||||
2016 | ||||||||
First Quarter | $ | 24.09 | $ | 15.55 | ||||
Second Quarter | 26.04 | 20.28 | ||||||
Third Quarter | 26.11 | 14.80 | ||||||
Fourth Quarter | 21.08 | 15.42 | ||||||
As of February 9, 2018,8, 2019, there were approximately 149138 holders of record of our common stock. This number represents registered stockholders and does not include stockholders who hold their shares through an institution.
Dividend Policy
We pay dividends at the discretion of our Board of Directors.Directors, or Board. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs, contractual obligations and other factors that our Board considers relevant at that time. The Board’s dividend policy may change from time to time, but there can be no assurance that we will declare any cash dividends at all or in any particular amounts. See “Risk Factors —Although weWe have not paid cash dividends in the past, we did not pay any dividends in 2017 and we may not pay dividends in the future, and we can give no assurance asa dividend to the amount or timing of the payment of any future dividends” in Item 1A of this report, which is incorporated herein by reference. We discontinued our regular cash dividend in 2016.stockholders since 2015.
CUMULATIVE TOTAL STOCKHOLDER RETURNCumulative Total Stockholder Return
The following graph shows the cumulative total stockholder return for our common stock, the Standard & Poor’s MidCap 400 MidCap Index and the Dow Jones U.S. Oil Equipment & Services index over the five yearfive-year period ended December 31, 2017.2018.
Comparison of Five-Year Cumulative Total Return(1)
| Dec. 31, 2012 | Dec. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2013 | Dec. 31, 2014 | Dec. 31, 2015 | Dec. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2018 | |||||||||||||||||||||||||||||||||||||
Diamond Offshore | 100 | 88 | 62 | 36 | 30 | 32 | $ | 100 | 70 | 41 | 34 | 36 | 18 | |||||||||||||||||||||||||||||||||||
S&P 400 MidCap Index | 100 | 133 | 146 | 143 | 173 | 201 | ||||||||||||||||||||||||||||||||||||||||||
S&P MidCap 400 Index | $ | 100 | 110 | 107 | 130 | 151 | 134 | |||||||||||||||||||||||||||||||||||||||||
Dow Jones U.S. Oil Equipment & Services | 100 | 128 | 106 | 82 | 105 | 87 | $ | 100 | 83 | 64 | 82 | 68 | 39 | |||||||||||||||||||||||||||||||||||
| (1) | Total return assuming reinvestment of dividends. Assumes $100 invested on December 31, |
Our dividend history forUnregistered Sales of Equity Securities and Use of Proceeds.
Items 2(a) and 2(b) are not applicable.
(c) During the periods reported above isthree months ended December 31, 2018, in connection with the vesting of restricted stock units held by our officers and certain of our employees, which were awarded under an equity incentive compensation plan, we acquired shares of our common stock in satisfaction of tax withholding obligations that were incurred on the vesting date. The date of acquisition, number of shares and average effective acquisition price per share were as follows:
Issuer Purchases of Equity Securities
| Q1 | Q2 | Q3 | Q4 | |||||||||||||||||||||||||||||
Year | Regular | Special | Regular | Special | Regular | Special | Regular | Special | ||||||||||||||||||||||||
2017 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
2016 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||
2015 | $ | 0.125 | $ | — | $ | 0.125 | $ | — | $ | 0.125 | $ | — | $ | 0.125 | $ | — | ||||||||||||||||
2014 | $ | 0.125 | $ | 0.75 | $ | 0.125 | $ | 0.75 | $ | 0.125 | $ | 0.75 | $ | 0.125 | $ | 0.75 | ||||||||||||||||
2013 | $ | 0.125 | $ | 0.75 | $ | 0.125 | $ | 0.75 | $ | 0.125 | $ | 0.75 | $ | 0.125 | $ | 0.75 | ||||||||||||||||
Period | Total Number of Shares Acquired | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs | Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs | ||||||||
October 1, 2018 through October 31, 2018 | 79 | $ | 20.10 | N/A | N/A | |||||||
November 1, 2018 through November 30, 2018 | — | — | N/A | N/A | ||||||||
December 1, 2018 through December 31, 2018 | 1,176 | $ | 12.60 | N/A | N/A | |||||||
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Total | 1,255 | $ | 20.86 | N/A | N/A | |||||||
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Item 6. Selected Financial Data.
The following table sets forth certain historical consolidated financial data relating to Diamond Offshore. We prepared the selected consolidated financial data from our consolidated financial statements as of and for the periods presented. The selected consolidated financial data below should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
| As of and for the Year Ended December 31, | As of and for the Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | 2018 | 2017 | 2016 | 2015 | 2014 | |||||||||||||||||||||||||||||||
| (In thousands, except per share and ratio data) | (In thousands, except per share and ratio data) | |||||||||||||||||||||||||||||||||||||||
Income Statement Data: | ||||||||||||||||||||||||||||||||||||||||
Total revenues | $ | 1,485,746 | $ | 1,600,342 | $ | 2,419,393 | $ | 2,814,671 | $ | 2,920,421 | $ | 1,083,215 | (1) | $ | 1,485,746 | $ | 1,600,342 | $ | 2,419,393 | $ | 2,814,671 | |||||||||||||||||||
Operating income (loss) | 123,879 | (1) | (356,884 | ) (1) | (294,074 | ) (1) | 572,562 | (1) | 801,606 | |||||||||||||||||||||||||||||||
Net income (loss) | 18,346 | (372,503 | ) | (274,285 | ) | 387,011 | 548,686 | |||||||||||||||||||||||||||||||||
Net income (loss) per share: | ||||||||||||||||||||||||||||||||||||||||
Operating (loss) income | (112,183 | )(2) | 123,879 | (2) | (356,884 | )(2) | (294,074 | )(2) | 572,562 | (2) | ||||||||||||||||||||||||||||||
Net (loss) income | (180,272 | ) | 18,346 | (372,503 | ) | (274,285 | ) | 387,011 | ||||||||||||||||||||||||||||||||
Net (loss) income per share: | ||||||||||||||||||||||||||||||||||||||||
Basic | 0.13 | (2.72 | ) | (2.00 | ) | 2.82 | 3.95 | (1.31 | ) | 0.13 | (2.72 | ) | (2.00 | ) | 2.82 | |||||||||||||||||||||||||
Diluted | 0.13 | (2.72 | ) | (2.00 | ) | 2.81 | 3.95 | (1.31 | ) | 0.13 | (2.72 | ) | (2.00 | ) | 2.81 | |||||||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||||||||||||||||||||||
Drilling and other property and equipment, net | $ | 5,261,641 | (1) | $ | 5,726,935 | (1) | $ | 6,378,814 | (1) | $ | 6,945,953 | (1) | $ | 5,467,227 | $ | 5,184,222 | (2) | $ | 5,261,641 | (2) | $ | 5,726,935 | (2) | $ | 6,378,814 | (2) | $ | 6,945,953 | (2) | |||||||||||
Total assets | 6,250,570 | 6,371,877 | 7,149,894 | (2) | 8,005,398 | (2) | 8,374,437 | (2) | 6,035,694 | 6,250,570 | 6,371,877 | 7,149,894 | (3) | 8,005,398 | (3) | |||||||||||||||||||||||||
Long-term debt (excluding current maturities) (3) | 1,972,225 | 1,980,884 | 1,979,778 | (2) | 1,978,635 | (2) | 2,227,192 | (2) | ||||||||||||||||||||||||||||||||
Long-term debt (excluding current | 1,973,922 | 1,972,225 | 1,980,884 | 1,979,778 | (3) | 1,978,635 | (3) | |||||||||||||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||||||||||||||
Capital expenditures, excluding accruals | $ | 139,581 | $ | 652,673 | $ | 830,655 | $ | 2,032,764 | (4) | $ | 957,598 | $ | 222,406 | $ | 139,581 | $ | 652,673 | $ | 830,655 | $ | 2,032,764 | (4) | ||||||||||||||||||
Cash dividends declared per share | — | — | 0.50 | 3.50 | 3.50 | — | — | — | 0.50 | 3.50 | ||||||||||||||||||||||||||||||
Ratio of earnings to fixed charges(5) | 0.91 | x | (3.21 | )x (6) | (2.45 | )x (6) | 4.64 | x | 7.79 | x | ||||||||||||||||||||||||||||||
| (1) | On January 1, 2018, we adopted Financial Accounting Standards Board Accounting Standards Update, or ASU,No. 2014-09,Revenue from Contracts with Customers(Topic 606), or ASU2014-09, which superseded previous 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 ASU2014-09, and its related amendments, or collectively Topic 606, using the modified retrospective implementation method, and, accordingly, 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. See Note 1—“General Information—Changes in Accounting Principles—Revenue Recognition” and Note 2 “Revenue from Contracts with Customers” to our Consolidated Financial Statements in Item 8 of this report for a discussion of the impact of adopting Topic 606. |
| (2) | During 2018, 2017, 2016, 2015 and 2014 we recorded impairment losses aggregating $27.2 million, $99.3 million, $678.1 million, $860.4 million and $109.5 million, respectively, to write down certain of our drilling rigs and related equipment with indicators of impairment to their estimated recoverable amounts. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations |
Historical data for the |
See Note |
| Item 7. |
|
The following discussion should be read in conjunction with Item 1A, “Risk Factors” and our Consolidated Financial Statements (including the Notes thereto) in Item 8 of this report.
We provide contract drilling services to the energy industry around the globe with a fleet of 17 offshore drilling rigs, consisting of four drillships and seven ultra-deepwater, four deepwater and twomid-water13 semisubmersible rigs. The semisubmersibleOcean Victorywas sold in January 2018 and thejack-upOcean Scepter is currently being marketed for sale. We have excluded both rigs from our current fleet total.
Market Overview
OilOver the past five years, crude oil prices have partially rebounded from the historical12-year lowbeen volatile, reaching a high of less than $30$115 per barrel in January 20162014 but dropping to $55 per barrel by the upper$60s-per-barrel rangeend of 2014. In 2015, oil prices continued to decline, closing at $37 per barrel at the end of January 2018. The increasethe year, and continuing to fall to a low of $28 per barrel during 2016 before recovering to nearly $57 per barrel by the end of 2016. While the price of crude oil continued to fluctuate in 2017 and 2018, as of the date of this report, the current spot price for Brent crude was in the $60 per barrel range. As a result of this volatility in commodity price isand its uncertain future, the offshore drilling industry has experienced a substantial decline in part due todemand for its services, as well as a significant decline in dayrates for contract drilling services. Although demand and offshore utilization increased during 2018, with industry-wide floater utilization averaging near 60% at the late December 2017 shutdownend of a major North Sea pipeline which led to production shutdowns at several offshore fields, and, production cuts by certain members of the Organization of Petroleum Exporting Countries, or OPEC, and others that went into effect in 2017 to reduce the oversupply of oil and raise and potentially stabilize oil prices. However,2018 based on analyst reports, dayrates remain low as the increase in oil prices from earlier lows has not yet resulted in a measurablesignificantly higher dayrates. If dayrates increase, offshore drillers with more available floaters and/or unpriced options for currently committed rigs will be better positioned to take advantage of the market recovery as it materializes.
Tendering activity has also increased. During 2018 and continuing into 2019, there has been an increase in demandcontract tenders for offshore contract drilling serviceslate 2019 and 2020 project commencements, primarily for work in the North Sea and Australia floater markets. Industry analysts also predict that there will be additional opportunities in the West Africa market in the near term. Reflective of the uncertainty in the market, many of these tenders have been limited to single-well jobs, with options for future wells. Although some geographic areas appear to be improving, other markets show little or higher dayrates as capital spending for offshore exploration and development remainsno sign of recovery at this time.
From a relatively low level at the start of 2018. As a consequence, the offshore contract drillingsupply perspective, industry remains weak.
Industry analysts have reported that in 2017, for the third consecutive year,during 2018, the global supply of floater rigs decreased for the fourth consecutive year, with 3020 floaters being scrapped during the year, for a total ofyear. Based on these reports, over 80200 drilling rigs, including 119 floaters, have been retired since 2015. Despite these events,2014. However, the oversupply of drilling rigs in theoffshore floater markets continues to persistmarket remains oversupplied, as there are drilling rigs across all water depth categories continue to bethat are not contracted or that are cold stacked as they come off contract with no immediate future work.of the date of this report. Industry reports also indicate that there remain approximately 40 newbuild floaters on order with scheduled deliveries betweenin 2019 and 2020, most of which have not yet been contracted for future work. In addition, several rig reactivations were announced during 2018 and 2021. Industry analysts predictin early 2019, including the ongoing reactivations of ourOcean Endeavor andOcean Onyx that the 2018 delivery dates may be deferred.
Given the oversupplyhave been brought out of rigs, competitioncold stack to fulfill newly-acquired contracts. These factors provide for the limited number ofa continued, challenging offshore drilling jobs remains intense. In some cases, dayrates have been negotiated at break-even or below-cost levels in order to enable the drilling contractor to recover a portion of operating costs for rigs that would otherwise be uncontracted or cold stacked. In addition, customers have indicated a preference for “hot” rigs rather than reactivated cold-stacked rigs. This preference incentivizes the drilling contractor to contract rigs at lower rates for the sole purpose of maintaining the rigs in an active state and allowing for at least partial cost recovery.
Our results of operations and cash flows for the three years ended December 31, 2017 have been materially impacted by continuing depressed market conditions in the offshore drilling industry. We currently expect that these adverse market conditions will continue for the near term, which could result in more of our rigs being without contracts, contracted at lower rates than the rigs are currently earning and/or cold stacked or scrapped. These events, if they were to occur, could further materially and adversely affect our financial condition, results of operations and cash flows. When we cold stack or elect to scrap a rig, we evaluate the rig for impairment. During 2017, 2016 and 2015, we recognized aggregate impairment losses of $99.3 million (three rigs), $678.1 million (eight rigs and related spares) and $860.4 million (17 rigs). See “— Results of Operations — Overview — 2017 Compared to 2016 — Impairment of Assets,” “— Results of Operations — Overview — 2016 Compared to 2015 — Impairment of Assets,” “Risk Factors — We may incur additional asset impairments and/or rig retirements as a result of reduced demand for certain offshore drilling rigs” in Item 1A of this report and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
Historically, the longer a drilling rig remains cold stacked, the higher the cost of reactivation and, depending on the age, technological obsolescence and condition of the rig, the lower the likelihood that the rig will be reactivated at a future date. As of January 29, 2018, five rigs in our fleet were cold stacked.term.
See “—“– Contract Drilling Backlog”for future commitments of our rigs during 20182019 through 2020.2022.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of January 1, 2018 (based on contract information known at that time), October 1, 2017 (the date reported in our Quarterly Report on Form10-Q for the quarter ended September 30, 2017), and January 1, 2017 (the date reported in our Annual Report on Form10-K for the year ended December 31, 2016). Contract drilling backlog, as presented below, includes only firm commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog.
See “Risk Factors —We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be ultimately realized” in Item 1A of this report, which is incorporated herein by reference.
The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 2 “Revenue from Contracts with Customers” to our Consolidated Financial Statements in Item 8 of this report. Contract drilling backlog includes only future dayrate revenue as described above, while the disclosure in Note 2 excludes dayrate revenue and only reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related tonon-distinct promises within our signed contracts.
The following table reflects our contract drilling backlog as of January 1, 2019 (based on information available at that time), October 1, 2018 (the date reported in our Quarterly Report on Form10-Q for the quarter ended September 30, 2018), and January 1, 2018 (the date reported in our Annual Report on Form10-K for the year ended December 31, 2017) (in thousands).
| January 1, 2018 | October 1, 2017 | January 1, 2017 | ||||||||||
| (In thousands) | ||||||||||||
Contract Drilling Backlog | ||||||||||||
Ultra-Deepwater Floaters | $ | 2,222,000 | $ | 2,413,000 | $ | 3,215,000 | ||||||
Deepwater Floaters | 90,000 | 86,000 | 197,000 | |||||||||
Other Rigs(1) | 105,000 | 118,000 | 152,000 | |||||||||
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Total | $ | 2,417,000 | $ | 2,617,000 | $ | 3,564,000 | ||||||
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| January 1, 2019(1) | October 1, 2018(1) | January 1, 2018 | ||||||||||
Contract Drilling Backlog | $ | 1,973,000 | $ | 2,040,000 | $ | 2,417,000 | ||||||
| (1) | Contract drilling backlog |
The following table reflects the amount of our contract drilling backlog by year as of January 1, 2018.2019 (in thousands).
| For the Years Ending December 31, | ||||||||||||||||
| Total | 2018 | 2019 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||||
Contract Drilling Backlog | ||||||||||||||||
Ultra-Deepwater Floaters | $ | 2,222,000 | $ | 1,062,000 | $ | 927,000 | $ | 233,000 | ||||||||
Deepwater Floaters | 90,000 | 45,000 | 45,000 | — | ||||||||||||
Other Rigs(1) | 105,000 | 42,000 | 45,000 | 18,000 | ||||||||||||
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Total | $ | 2,417,000 | $ | 1,149,000 | $ | 1,017,000 | $ | 251,000 | ||||||||
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| For the Years Ending December 31, | ||||||||||||||||||||
| Total | 2019 | 2020 | 2021 | 2022 | ||||||||||||||||
Contract Drilling Backlog(1) | $ | 1,973,000 | $ | 886,000 | $ | 798,000 | $ | 253,000 | $ | 36,000 | ||||||||||
| (1) | Contract drilling backlog as of January 1, 2019 excludes future gross margin commitments of $30.0 million for |
The following table reflects the percentage of rig days committed by year as of January 1, 2018.2019. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs, including cold-stacked rigs, multiplied by the number of days in a particular year).
| For the Years Ending December 31, | ||||||||||||
| 2018 | 2019 | 2020 | ||||||||||
Rig Days Committed(1) | ||||||||||||
Ultra-Deepwater Floaters | 71 | % | 59 | % | 17 | % | ||||||
Deepwater Floaters | 29 | % | 24 | % | — | |||||||
Other Rigs(2) | 37 | % | 33 | % | 12 | % | ||||||
| For the Years Ending December 31, | ||||||||||||||||
| 2019 | 2020 | 2021 | 2022 | |||||||||||||
Rig Days Committed(1) | 67 | % | 59 | % | 18 | % | 2 | % | ||||||||
| (1) | As of January 1, |
Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows
Operating Income.Our operating income is primarily a function of contract drilling revenue earned less contract drilling expenses incurred or recognized. The two most significant variables affecting our contract drilling revenue are the dayrates earned and utilization rates achieved by our rigs, each of which is a function of rig supply and demand in the marketplace. These factors are not entirely within our control and are difficult to predict. We generally recognize revenue from dayrate drilling contracts as services are performed. Consequently, when a rig is idle, no dayrate is earned and revenue will decrease as a result.
Effective January 1, 2018, we adopted Accounting Standards Update, or ASU,No. 2014-09,Revenue from Contracts with Customers(Topic 606), or ASU2014-09, which supersedes 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. Revenues for reporting periods beginning after January 1, 2018 are presented under ASU2014-09, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance.
Revenue recognition under ASU2014-09 differs from our previous revenue recognition pattern only as it relates to demobilization revenue. Such revenue, which was previously recognized upon completion of a contract, is now estimated at contract inception and recognized, to the extent not constrained, ratably over the initial term of the contract under the new revenue recognition guidance. See “– Critical Accounting Estimates” and Note 1 “General Information—Changes in Accounting Principles- Revenue Recognition” and Note 2 “Revenue from Contracts with Customers” to our Consolidated Financial Statements in Item 8 of this report.
Revenue is also affected by the acquisition or disposal of rigs, rig mobilizations, required surveys and shipyard projects. In connection with certain drilling contracts, we may receive fees for the mobilization and demobilization of equipment. In addition, some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements for which we may or may not be compensated. We earnrecognize these fees ratably as services are performed over the initial term of the related drilling contracts. We defer mobilization and contract preparation fees received (on either alump-sum or dayrate basis), as well as direct and incremental costs associated with the mobilization of equipment and contract preparation activities, and amortize each, on a straight-line basis, over the term of the related drilling contracts. Absent aAs noted above, demobilization revenue expected to be received upon contract mobilization costs arecompletion is estimated and is also recognized currently.ratably over the initial term of the contract.
Operating income also fluctuates due to varying levels of contract drilling expenses. Our operating expenses represent all direct and indirect costs associated with the operation and maintenance of our drilling equipment, which generally are not affected by changes in dayrates and short-term reductions in utilization. For instance, if a rig is to be idle for a short period of time, few decreases in operating expenses may actually occur since the rig is typically maintained in a prepared or “warm-stacked” state with a full crew. In addition, when a rig is idle, we
are responsible for certain operating expenses such as rig fuel and supply boat costs, which are typically costs of the operatorour customer when a rig is under contract. However, if a rig is expected to be idle for an extended period of time, we may reduce the size of a rig’s crew and take steps to “cold stack” the rig, which lowers expenses and partially offsets the impact on operating income. The cost of cold stacking a rig can vary depending on the type of rig. The cost of cold stacking a drillship, for example, is typically substantially higher than the cost of cold stacking ajack-up rig or an older floater rig.
The principal components of our operating costs are, among other things, direct and indirect costs of labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter rentals and insurance. Labor and repair and maintenance costs represent the most significant components of our operating expenses. In general, our labor costs increase primarily due to higher salary levels, rig staffing requirements and costs associated with labor regulations in the geographic regions in which our rigs operate. In addition, the costs associated with training employees can be significant. Costs to repair and maintain our equipment fluctuate depending upon the type of activity the drilling unit is
performing, as well as the age and condition of the equipment and the regions in which our rigs are working. See “—“– Contractual Cash Obligations — –Pressure Control by the Hour®.”
Regulatory Surveys and Planned Downtime.Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs istwo-and-one-half years. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs, which are recognized as incurred. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a special survey will vary from year to year, as well as from quarter to quarter.
During 2018,2019, we expect to spend approximately 20855 days for contract preparation, reactivation of rigs, mobilization of rigs, upgrades and 75surveys, including approximately 60 days for contract preparation for theOcean GreatWhiteand an aggregate of 425 days for reactivation activities and contract preparation for theOcean EndeavorandOcean Onyxprior to their contract commencements. We also expect to spend an aggregate of 230 days for special surveys and rig upgrades for theOcean PatriotBlackHawk,Ocean BlackHornetandOcean Valiant,BlackRhino,respectively. Additionally, we expect to spend approximately 3560 days for a special survey for theOcean ValorCourage in 2018, duringand an aggregate of 80 days for the paid contracted standby period.mobilization of theOcean Apex and theOcean Monarch. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyardthese projects. See “— “ – Contract Drilling Backlog.Backlog.”
Physical Damage and Marine Liability Insurance.We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our current insurance policy, which renewed effective May 1, 2017,2018, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retainloss-of-hire insurance policies to cover our rigs.
In addition, under our current insurance policy, which renewed effective May 1, 2017, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, and generally covering liabilities arising out of or relating to pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage related to insurable events arising due to named windstorms in the U.S. Gulf of Mexico isare $25.0 million for the first occurrence, with no aggregate deductible, 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. Our deductibles for other marine liability coverage, including personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, are $10.0 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.
2017 Reduction Plan. The contract drilling industry has experienced a severe downturn that began inmid-2014 with a dramatic decline in oil prices, resulting in a lack of demand for the services we provide, primarily in the area of deepwater drilling. This lack of demand, combined with a significant oversupply of drilling rigs, has caused our management to again review our organizational and operational structure, in an effort to further reduce our operating profile. In late 2017, we undertook a reorganization of our operational structure, including the identification of redundant positions and, among other things, negotiated the termination of our agency relationship in Brazil. For the year ended December 31, 2017, we recognized $14.1 million in “Restructuring and separation costs” in our Consolidated Statements of Operations primarily associated with the severance of certain executives and other employees and termination of our agency agreement in Brazil, the majority of which was unpaid at December 31, 2017. As we continue to position our organization to compete effectively in what we continue to expect to be a protracted downturn, we expect to continue our assessment of our organizational structure during 2018. For the first quarter of 2018, we expect to incur approximately $3 million in severance costs for additional redundant employees. If market conditions do not significantly improve in the near term and the market downturn remains protracted, additional actions may be required to further reduce our cost profile.
Impact of Changes in Tax Laws or Their Interpretation.We operate through our various subsidiaries in a number of countriesjurisdictions throughout the world. As a result, we are subject to highly complex tax laws, treaties and regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
On December 22, 2017, the President of the United States signed into law the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act amended the Internal Revenue Code in several areas that had a direct and immediate effect on our results of operations and statement of financial position as of and for the year ended December 31, 2017, including, among other items, aone-time mandatory deemed repatriation of accumulated earnings of our foreign subsidiaries as of December 31, 2017 and a reduction in the U.S corporate income tax rate from 35% to 21% beginning in January 2018. We have used our best judgment to estimate the impact of the Tax Reform Act on our reported results. Due to the timing of the enactment of the Tax Reform Act, there continues to be a significant amount of uncertainty as to the appropriate application of a number of the underlying provisions, pending further guidance and clarification from the relevant authorities. We will continue to monitor developments in this area and adjust our estimates throughout the year in 2018, as and if necessary, as additional guidance and clarification becomes available. See “—Critical Accounting Estimates— Income Taxes,” “Results of Operations — Overview — 2017 Compared to 2016 —Income Tax Benefit” and Note 15 “Income Taxes” to our Consolidated Financial Statements in Item 8 of this report.
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 “General Information” to our Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates by our management are inherent in the preparation of our financial statements and the application of our significant accounting policies. We believe that our most critical accounting estimates are as follows:
Property, Plant and Equipment.We carry our drilling and other property and equipment at cost, less accumulated depreciation. Maintenance and routine repairs are charged to income currently while replacements and betterments that upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the years ended December 31, 20172018 and 2016,2017, we capitalized $69.4$243.6 million and $177.6$69.4 million, respectively, in replacements and betterments of our drilling fleet.
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near 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:
dayrate by rig;
utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);
the per day operating cost for each rig if active, warm stacked or cold stacked;
the estimated annual cost for rig replacements and/or enhancement programs;
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 forre-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 onoil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different.
During 2018, 2017 in response to continued depressed market conditions for the offshore contract drilling industry and our expectations that a market recovery is not likely to occur in the near term,2016, we evaluated ten of our drilling rigs with indications that their carrying values may not be recoverable. As a result of these evaluations, we determined that the carrying values of one ultra-deepwater semisubmersible, one deepwater semisubmersible and onejack-up rig were impaired and recorded impairment losses of $71.3$27.2 million, $99.3 million and $28.0 million during the second and fourth quarters of 2017, respectively.
During 2016, we evaluated 15 of our drilling rigs with indications that their carrying amounts may not be recoverable and recorded an aggregate impairment loss of $678.1 million, related to eight rigs including an $8.1 million impairment of rig spares and supplies. During 2015, we evaluated 25 of our drilling rigs with indications that their carrying amounts may not be recoverable and recorded an aggregate impairment loss of $860.4 million related to 17 drilling rigs.respectively. See “—“– Results of Operations —– Overview — 20172018 Compared to 20162017 — –Impairment of Assets” and “—“– Results of Operations —–Overview — 20162017 Compared to 20152016 —–Impairment of Assets” and Note 23 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
Personal Injury Claims.Under our current insurance policies, which renewed effective May 1, 2017,2018, 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 Gulf of Mexico, are $10.0 million for the first occurrence, with no aggregate deductible, 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 deductibledeductibles for personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico isare $25.0 million for the first occurrence, with no aggregate deductible, 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. 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.
The models used in estimating our aggregate reserve for personal injury claims include actuarial assumptions such as:
claim emergence, or the delay between occurrence and recording of claims;
settlement patterns, or the rates at which claims are closed;
development patterns, or the rate at which known cases develop to their ultimate level;
average, potential frequency and severity of claims; and
effect ofre-opened claims.
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.
Income Taxes. We account for income taxes in accordance with accounting standards that require the recognition of the amount of taxes payable or refundable for the current year and an asset and liability approach in recognizing the amount of deferred tax liabilities and assets for the future tax consequences of events that have been currently recognized in our financial statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset or liability for the estimated future tax effects attributable to temporary differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if necessary, which is determined by the amount of any tax benefits that, based on available evidence, are not expected to be realized under a “more likely than not” approach. We do not establish deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely reinvest to finance foreign activities. However, if these earnings become subject to U.S. federal tax, any required provision could have a material adverse impact on our financial results. We make judgments regarding future events and related estimates especially as they pertain to the forecasting of our effective tax rate, the potential realization of deferred tax assets such as net operating loss carryforwards, utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax returns upon audit.
Certain of our international rigs are owned and operated, directly or indirectly, by DFAC. As of December 31, 2017, all unremitted earnings of DFAC have been deemed repatriated as a result of the Tax Reform Act, and U.S. taxes have been provided for them. We intend to indefinitely reinvest earnings of DFAC and its foreign subsidiaries to finance our foreign activities.
The Tax Reform Act requires a U.S. shareholder of a foreign corporation to include in income its global intangiblelow-taxed income, or GILTI. Due to the fact that the GILTI computation is dependent on contingent or future events that cannot reasonably be known, we have made the accounting policy decision, as permitted by U.S. GAAP, to account for U.S. tax on GILTI, should it be applicable, as a period cost in the period in which the tax would be incurred, as opposed to recognizing deferred taxes on the basis differences that are expected to affect the amount of GILTI.
In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the arm’s length amount to be charged for providing the services and equipment, and utilize outside consultants to assist us in the development of such transfer pricing methodologies. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts.
Results of Operations
Although we performOur operating results for contract drilling services with different types of drilling rigsare dependent on three primary metrics or key performance indicators: revenue-earning days, rig utilization and in many geographic locations, there is a 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. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with applicable accounting standards on segment reporting. However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet to enhance the reader’s understanding of our financial condition, changes in financial condition and results of operations.
Keyaverage daily revenue. The following table presents these three key performance indicators by equipment type are listed below.and other comparative data relating to our revenues and operating expenses (in thousands, except days, daily amounts and percentages).
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
REVENUE-EARNING DAYS(1) | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | 2,546 | 2,074 | 2,690 | |||||||||
Deepwater | 874 | 844 | 1,339 | |||||||||
Mid-Water | 445 | 727 | 1,433 | |||||||||
Jack-ups | 282 | 149 | 909 | |||||||||
UTILIZATION(2) | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | 59 | % | 51 | % | 64 | % | ||||||
Deepwater | 41 | % | 34 | % | 52 | % | ||||||
Mid-Water | 27 | % | 30 | % | 36 | % | ||||||
Jack-ups | 61 | % | 8 | % | 42 | % | ||||||
AVERAGE DAILY REVENUE(3) | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | $ | 428,200 | $ | 477,000 | $ | 497,700 | ||||||
Deepwater | 231,600 | 304,600 | 409,800 | |||||||||
Mid-Water | 309,500 | 342,000 | 270,500 | |||||||||
Jack-ups | 74,900 | 202,700 | 93,400 | |||||||||
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
REVENUE-EARNING DAYS(1) | ||||||||||||
Floaters | 3,192 | 3,865 | 3,645 | |||||||||
Jack-ups | — | 282 | 149 | |||||||||
UTILIZATION(2) | ||||||||||||
Floaters | 51 | % | 48 | % | 41 | % | ||||||
Jack-ups | — | 61 | % | 8 | % | |||||||
AVERAGE DAILY REVENUE(3) | ||||||||||||
Floaters | $ | 329,400 | $ | 370,100 | $ | 410,200 | ||||||
Jack-ups | — | 74,900 | 202,700 | |||||||||
REVENUE RELATED TO CONTRACT DRILLING SERVICES | $ | 1,059,973 | $ | 1,451,219 | $ | 1,525,214 | ||||||
REVENUE RELATED TO REIMBURSABLE EXPENSES | 23,242 | 34,527 | 75,128 | |||||||||
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|
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|
|
| |||||||
TOTAL REVENUES | $ | 1,083,215 | $ | 1,485,746 | $ | 1,600,342 | ||||||
|
|
|
|
|
| |||||||
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION | $ | 722,834 | $ | 801,964 | $ | 772,173 | ||||||
REIMBURSABLE EXPENSES | $ | 22,917 | $ | 33,744 | $ | 58,058 | ||||||
OPERATING (LOSS) INCOME | ||||||||||||
Contract drilling services, net | $ | 337,139 | $ | 649,255 | $ | 753,041 | ||||||
Reimbursable expenses, net | 325 | 783 | 17,070 | |||||||||
Depreciation | (331,789 | ) | (348,695 | ) | (381,760 | ) | ||||||
General and administrative expense | (85,351 | ) | (74,505 | ) | (63,560 | ) | ||||||
Bad debt recovery | — | — | 265 | |||||||||
Impairment of assets | (27,225 | ) | (99,313 | ) | (678,145 | ) | ||||||
Restructuring and separation costs | (5,041 | ) | (14,146 | ) | — | |||||||
(Loss) gain on disposition of assets | (241 | ) | 10,500 | (3,795 | ) | |||||||
|
|
|
|
|
| |||||||
Total Operating (Loss) Income | $ | (112,183 | ) | $ | 123,879 | $ | (356,884 | ) | ||||
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| |||||||
Other income (expense): | ||||||||||||
Interest income | 8,477 | 2,473 | 768 | |||||||||
Interest expense, net of amounts capitalized | (123,240 | ) | (113,528 | ) | (89,934 | ) | ||||||
Foreign currency transaction gain | (379 | ) | (1,128 | ) | (11,522 | ) | ||||||
Loss on early extinguishment of senior notes | — | (35,366 | ) | — | ||||||||
Other, net | 700 | 2,230 | (10,727 | ) | ||||||||
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|
|
|
|
| |||||||
Loss before income tax benefit | (226,625 | ) | (21,440 | ) | (468,299 | ) | ||||||
Income tax benefit | 46,353 | 39,786 | 95,796 | |||||||||
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|
|
|
|
| |||||||
NET (LOSS) INCOME | $ | (180,272 | ) | $ | 18,346 | $ | (372,503 | ) | ||||
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| |||||||
| (1) | A revenue-earning day is defined as a24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days. |
| (2) | Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all specified rigs in our fleet (including three, five and ten cold-stacked floater rigs |
| (3) | Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per revenue-earning day. |
2018 Compared to 2017
We recorded a net loss of $180.3 million in 2018 compared to net income of $18.3 million in 2017. The $198.6 million decrease in net results was primarily due to lower revenue from our contract drilling services and higher interest expense and certain other charges. These negative factors were partially offset by the favorable impact of reduced depreciation expense and a lower impairment charge in 2018, combined with the absence of a $35.4 million loss on the early extinguishment of our senior notes in 2017. Contract drilling services contributed operating income of $337.1 million in 2018, compared to operating income of $649.3 million in 2017, reflecting the challenging contract drilling market during 2018.
Operating Results.Contract drilling revenue decreased $391.2 million during 2018 compared to 2017, primarily due to 955 fewer revenue-earning days ($334.0 million), combined with the effect of lower average daily revenue earned ($65.6 million). Revenue-earning days decreased during 2018, primarily due to fewer revenue-earning days for previously-owned rigs that operated during 2017 (437 days), incremental downtime for planned shipyard projects, including associated mobilization days (392 days), incremental downtime attributable to the warm stacking of rigs between contracts (86 days) and an increase innon-productive days (40 days). Average daily revenue decreased during 2018 compared to 2017, primarily due to lower dayrates earned by several of our rigs as a result of the renegotiation of existing contracts under mutually favorable terms and new contracts at lower dayrates than previously contracted during 2017. The decrease in revenue was partially offset by $8.4 million inloss-of-hire insurance proceeds received during 2018 related to contract terminations for twojack-up rigs in a prior year.
Contract drilling expense, excluding depreciation, decreased $79.1 million during 2018 compared to 2017, primarily due to reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense in 2017 ($52.4 million), combined with decreased costs for our current rig fleet ($26.7 million). The decrease in contract drilling expense for our current fleet resulted from lower labor and personnel costs, agency fees, shorebase support costs and overheads, primarily as a result of our continuing cost control initiatives, including termination of our Brazilian agency agreement at the end of 2017, and the deferral of costs associated with contract preparation activities for rigs as they prepare for new contracts in 2019. These reductions were partially offset by increased costs for repairs and maintenance, inspections and equipment rentals. Depreciation expense decreased $16.9 million in 2018 compared to 2017, primarily due to a lower asset base in 2018 as a result of the sale of rigs and asset impairments.
General and administrative expense increased $10.8 million during 2018 compared to 2017, primarily due to a $17.5 million charge for settlement of a previously pending legal claim, partially offset by the favorable effect of lower administrative payroll costs resulting from restructuring initiatives.
Impairment of Assets. During the second quarter of 2018, we recorded an impairment loss of $27.2 million to recognize a reduction in fair value (less costs to sell) of theOcean Scepter, ajack-up rig that was reported in “Assets held for sale” in our audited Consolidated Balance Sheets at December 31, 2017 and which was sold in July 2018. In 2017, we recorded an aggregate impairment loss of $99.3 million with respect to the carrying values of three rigs. See “– Critical Accounting Estimates –Property, Plant and Equipment” and Note 1 “General Information –Assets Held for Sale” and Note 3 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
Restructuring and Separation Costs.During the fourth quarter of 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our
Comparative data relatingcorporate facilities and onshore bases. As a result, we recognized $14.1 million in 2017 in restructuring and other employee separation related costs, including $11.5 million related to a negotiated termination of our agency agreement in Brazil. During 2018, we recognized $5.0 million in restructuring and other employee separation related costs for additional workforce reduction in 2018.
Interest Expense, Net of Amounts Capitalized.Interest expense increased $9.7 million during 2018 compared to 2017, primarily as a result of interest charges related to foreign customs and payroll tax assessments ($4.0 million) combined with incremental interest expense associated with our senior notes issued in August 2017 ($6.5 million) and amendment of our credit facility in October 2018 ($1.9 million). See “– Liquidity and Capital Resources –Sources and Uses of Cash–Credit Agreements” and Note 10 “Credit Agreements and Senior Notes” to our revenuesConsolidated Financial Statements in Item 8 of this report. These incremental interest costs were partially offset by the reversal of accrued interest on assessments due to the expiration of statutes of limitations onnon-income based taxes in certain tax jurisdictions.
Loss on Extinguishment of Senior Notes.During the third quarter of 2017, we recorded a $35.4 million loss on extinguishment of $500.0 million aggregate principal amount of our senior notes that were to mature in 2019. See Note 10 “Credit Agreements and operating expensesSenior Notes” to our Consolidated Financial Statements in Item 8 of this report.
Income Tax Benefit.During 2018 and 2017, we recorded net income tax benefits of $46.4 million and $39.8 million, respectively, on net losses of $226.6 million and $21.4 million, respectively. The variance in the income tax benefit recognized between years is due to differences in the mix of our domestic and internationalpre-tax earnings and losses, including asset impairments taken during both 2018 and 2017 in various jurisdictions, as well as discrete tax items recorded in each period as a result of, among other things, tax audits or assessments and filed or amended tax returns.
As a result of the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act, which was signed into law on December 22, 2017, we recorded an incremental income tax expense of $1.1 million in 2017, consisting of (i) a $75.4 million charge related to the immediate deemed repatriation of the previously deferred accumulated earnings of ournon-U.S. subsidiaries and (ii) a $74.3 million benefit resulting from the remeasurement of our net U.S. deferred tax liability at the lower corporate income tax rate. Subsequently, in 2018, the U.S. Department of the Treasury and the Internal Revenue Service, or IRS, issued additional guidance which clarified certain tax positions taken in 2017 pursuant to the Tax Reform Act. Consequently, we reversed a $43.3 million liability for an uncertain tax position related to the deemed repatriation of accumulatednon-U.S. earnings in 2017. In addition, based on proposed regulations issued by equipment type are listed below.the IRS in the fourth quarter of 2018, which we believe may impact the utilization of certain tax attributes to offset the deemed repatriation ofnon-U.S. earnings, we recorded an uncertain tax position in the amount of $20.1 million. See Note 16 “Income Taxes” to our Consolidated Financial Statements in Item 8 of this report.
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands) | ||||||||||||
CONTRACT DRILLING REVENUE | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | $ | 1,090,139 | $ | 989,158 | $ | 1,339,059 | ||||||
Deepwater | 202,329 | 256,997 | 548,667 | |||||||||
Mid-Water | 137,607 | 248,846 | 387,549 | |||||||||
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| |||||||
Total Floaters | 1,430,075 | 1,495,001 | 2,275,275 | |||||||||
Jack-ups | 21,144 | 30,213 | 84,909 | |||||||||
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Total Contract Drilling Revenue | $ | 1,451,219 | $ | 1,525,214 | $ | 2,360,184 | ||||||
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REVENUES RELATED TO REIMBURSABLE EXPENSES | $ | 34,527 | $ | 75,128 | $ | 59,209 | ||||||
CONTRACT DRILLING EXPENSE | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | $ | 561,505 | $ | 494,510 | $ | 620,122 | ||||||
Deepwater | 115,350 | 148,992 | 277,779 | |||||||||
Mid-Water | 69,050 | 84,194 | 230,606 | |||||||||
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| |||||||
Total Floaters | 745,905 | 727,696 | 1,128,507 | |||||||||
Jack-ups | 25,428 | 17,854 | 65,699 | |||||||||
Other | 30,631 | 26,623 | 33,658 | |||||||||
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Total Contract Drilling Expense | $ | 801,964 | $ | 772,173 | $ | 1,227,864 | ||||||
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REIMBURSABLE EXPENSES | $ | 33,744 | $ | 58,058 | $ | 58,050 | ||||||
OPERATING INCOME (LOSS) | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | $ | 528,634 | $ | 494,648 | $ | 718,937 | ||||||
Deepwater | 86,979 | 108,005 | 270,888 | |||||||||
Mid-Water | 68,557 | 164,652 | 156,943 | |||||||||
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| |||||||
Total Floaters | 684,170 | 767,305 | 1,146,768 | |||||||||
Jack-ups | (4,284 | ) | 12,359 | 19,210 | ||||||||
Other | (30,631 | ) | (26,623 | ) | (33,658 | ) | ||||||
Reimbursable expenses, net | 783 | 17,070 | 1,159 | |||||||||
Depreciation | (348,695 | ) | (381,760 | ) | (493,162 | ) | ||||||
General and administrative expense | (74,505 | ) | (63,560 | ) | (66,462 | ) | ||||||
Bad debt recovery | — | 265 | — | |||||||||
Impairment of assets | (99,313 | ) | (678,145 | ) | (860,441 | ) | ||||||
Restructuring and separation costs | (14,146 | ) | — | (9,778 | ) | |||||||
Gain (loss) on disposition of assets | 10,500 | (3,795 | ) | 2,290 | ||||||||
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| |||||||
Total Operating Income (Loss) | $ | 123,879 | $ | (356,884 | ) | $ | (294,074 | ) | ||||
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Other income (expense): | ||||||||||||
Interest income | 2,473 | 768 | 3,322 | |||||||||
Interest expense | (113,528 | ) | (89,934 | ) | (93,934 | ) | ||||||
Loss on extinguishment of senior notes | (35,366 | ) | — | — | ||||||||
Foreign currency transaction (loss) gain | (1,128 | ) | (11,522 | ) | 2,465 | |||||||
Other, net | 2,230 | (10,727 | ) | 873 | ||||||||
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| |||||||
(Loss) income before income tax benefit | (21,440 | ) | (468,299 | ) | (381,348 | ) | ||||||
Income tax benefit | 39,786 | 95,796 | 107,063 | |||||||||
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NET INCOME (LOSS) | $ | 18,346 | $ | (372,503 | ) | $ | (274,285 | ) | ||||
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Overview
2017 Compared to 2016
Operating Income (Loss).OperatingDuring 2017, we recorded net income of $18.3 million, compared to a net loss of $372.5 million in 2016. Our net results for 2017 increased $480.8$390.8 million compared to 2016, primarily due to lower impairment charges and a lower aggregate impairment loss recognizedreduction in 2017 ($578.8 million), combined with reduced depreciation expense ($33.1 million). Depreciation expense decreased compared to 2016, primarily due to a lower depreciable asset base, as a result of asset impairments in 2016 and 2017.expense. These favorable variancesfactors were partially offset by lower contract drilling results, higher interest expense and a $99.8lower tax benefit recorded in 2017, combined with a $35.4 million net reduction in rigloss on early extinguishment of our senior notes. Contract drilling services contributed operating results for our floater andjack-up rigs, $14.1income of $649.3 million in restructuring and severance costs recognized in 2017, and the absencecompared to operating income of $14.6$753.0 million in net reimbursable revenue earned by theOcean Endeavorin 2016.
Operating Results.Contract drilling revenue decreased $74.0 million during 2017 compared to 2016, primarily as a result of a lower average daily revenue earned by all rig types,($216.0 million), partially offset by the favorable impact of an aggregate 353 incremental revenue-earning days.days ($142.0 million). Average daily revenue decreased primarily due to several of our rigs having worked under new contracts in 2017 at lower dayrates than those
previously contracted. Revenue-earning days increased during 2017, primarily due to incremental revenue-earning days for theOcean GreatWhite (351 days), which began its first contract during the first quarter of 2017, less planned downtime for shipyard projects (211 days) and fewer days attributable to the warm stacking of rigs between contracts (164 days). These favorable impacts were partially offset by fewer revenue-earning days related to cold-stacked and sold rigs that worked in 2016 (344 days) and an increase innon-productive days (31 days). Total contractrevenue in 2016 also included $14.6 million in net reimbursable revenue earned by theOcean Endeavorupon completion of its demobilization from the Black Sea.
Contract drilling expense, for 2017excluding depreciation, increased $29.8 million in 2017 compared to 2016, reflecting higher amortized rig mobilization expense ($25.4 million) and incremental costs associated with the Pressure Control by the Hour® program, or the PCbtH program, on our drillships ($27.8 million), partially offset by lower repair and maintenance costs ($15.2 million) and a net reduction in other rig operating and overhead costs ($8.2 million). Depreciation expense decreased $33.1 million compared to 2016, primarily due to a lower depreciable asset base, as a result of asset impairments in 2016 and 2017.
General and administrative expense increased $10.9 million in 2017 compared to 2016, primarily due to higher administrative payroll costs and incremental advisory and consulting costs incurred in relation to various corporate initiatives.
Interest Expense, Net of Amounts Capitalized.Interest expense increased $23.6 million during 2017 compared to 2016, primarily as a result of a $20.7 million reduction in interest capitalized during 2017 due to the completion of construction projects in 2016. Interest expense for 2017 also included incremental interest expense associated with our newly-issued debtsenior notes and subsequent debt redemption of existing debt in August 2017senior notes ($4.0 million), which was partially offset by reduced interest expense associated with lower borrowings under our revolving credit agreement ($2.8 million). See “— Liquidity and Capital Resources — Senior Notes.”
Impairment of Assets. During 2017, we determined that the carrying valuesrecorded an aggregate impairment charge of one ultra-deepwater semisubmersible, one deepwater semisubmersible, and onejack-up rig were impaired. As a result, we recorded impairment losses of $71.3$99.3 million and $28.0 million during the second and fourth quarters of 2017, respectively. The deepwater semisubmersible rig was sold for scrap in January 2018, and thejack-up rig is being marketed for sale.related to three drilling rigs. During the second quarter of 2016, we recognized an aggregate impairment charge of $678.1 million with respect to the carrying values of twomid-water, three deepwater, and three ultra-deepwater semisubmersibleeight drilling rigs, including related rig spares and supplies. See “—“– Critical Accounting Estimates — –Property, Plant and Equipment” and Note 1 “General Information —Assets Held for Sale” and Note 23 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
Restructuring and Separation Costs.During the fourth quarter of 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our corporate facilities and onshore bases. DuringAs a result, during 2017, we recognized $14.1 million in restructuring and other employee separation related costs, including $11.5 million related to a negotiated termination of our agency agreement in Brazil. See “Important Factors that May Impact Our Operating Results, Financial Condition or Cash Flows — 2017 Reduction Plan.”
Gain on Disposition of Assets.During 2017, we sold one ultra-deepwater floater, one deepwater floater, threemid-waterfive floaters and onejack-up rig for scrap and recognized an aggregatepre-tax gain of $8.9 million on the sale of these rigs. In 2016, we sold one deepwater rig, three midwater rigsfour floaters and fourjack-ups for a netpre-tax loss of $4.0 million.
Loss on Extinguishment of Senior Notes.During the third quarter of 2017, we recorded a $35.4 million loss on extinguishment of $500.0 million aggregate principal amount of our senior notes that were to mature in 2019. See “— Liquidity and Capital Resources — Senior Notes.”
Other, net.During 2016, we sold our investment in privately-placed corporate bonds for a total recognized loss of $12.1 million.
Income Tax Benefit.During 2017 and 2016, we recorded net income tax benefits of $39.8 million and $95.8 million, respectively, on netpre-tax losses of $21.4 million and $468.3 million, respectively. The variance in the income tax benefit
recognized between years is due to differences in the mix of our domestic and internationalpre-tax earnings and losses, including asset impairments taken during both 2017 and 2016 in various jurisdictions, as well as discrete tax items recorded in each period as a result of, including but not limited to,among other things, tax audits or assessments and filed or amended tax returns.
In addition, as a result of the Tax Reform Act, that was signed into law on December 22, 2017, we recorded incremental income tax expense of $1.1 million consisting of (i) a $75.4 million charge related to the immediate deemed repatriation of the previously deferred accumulated earnings of ournon-U.S. subsidiaries and (ii) a $74.3 million benefit resulting from the remeasurement of our net U.S. deferred tax liability at the lower corporate income tax rate.in 2017. During 2016, we recorded a $43.0 million reduction in income tax expense, primarily related to our Egyptian tax liability for uncertain tax positions related to the devaluation of the Egyptian Pound. See “Important Factors that May Impact Our Operating Results, Financial Condition or Cash Flows —Impact of Changes in Tax Laws or Their Interpretation” and Note 1516 “Income Taxes” to our Consolidated Financial Statements in Item 8 of this report.
2016 Compared to 2015
Operating Income (Loss).Operating results for 2016 decreased $62.8 million compared to 2015, primarily due to lower utilization of our rig fleet, which reduced both contract drilling revenue and expense. Our operating results for 2016 reflected an aggregate impairment charge of $678.1 million compared to impairment charges aggregating $860.4 million in 2015. As a result of the impairment charges in 2015 and 2016 and resulting lower depreciable asset base, depreciation expense decreased $111.4 million in 2016 compared to 2015.
Contract drilling revenue decreased $835.0 million, during 2016, compared to 2015, due to depressed market conditions in all floater markets and for ourjack-up rig. Operating results for 2016 reflected an aggregate of 2,577 fewer revenue-earning days compared to 2015, and lower average daily revenue earned by our ultra-deepwater and deepwater floater fleets. Average daily revenue increased for ourmid-water andjack-up fleets primarily due to the favorable settlement of a contractual dispute and receipt ofloss-of-hire insurance proceeds, each in 2016.
Total contract drilling expense for 2016 decreased $455.7 million compared to 2015, reflecting our lower cost structure due to additional rigs idled, cold stacked or retired during 2015 and 2016, as well as the favorable impact of our cost control initiatives. The reduction in contract drilling expense during 2016 included lower costs associated with labor and personnel ($222.9 million), repairs and maintenance ($63.1 million), mobilization ($71.3 million), shorebase and operational support ($48.1 million), freight ($17.4 million), revenue-based agency fees ($16.1 million), inspections ($8.9 million), and other rig operating expenses ($7.9 million), including rig stacking costs and late start penalties recognized in 2015.
Impairment of Assets. During 2016, we recognized an aggregate impairment charge of $678.1 million related to the carrying values of eight rigs, including related rig spares and supplies. In 2015, we recorded an aggregate impairment loss of $860.4 million related to 17 of our rigs, consisting of two ultra-deepwater, one deepwater and ninemid-water floaters and fivejack-up rigs. See “— Critical Accounting Estimates —Property, Plant and Equipment” and Note 2 “Asset Impairments” to our Consolidated Financial Statements in Item 8 of this report.
Restructuring and Separation Costs.During the first quarter of 2015, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, which resulted in the recognition of $9.8 million in restructuring and other employee separation related costs in 2015.
Income Tax Expense.Our effective tax rate for 2016 was 20.5% compared to a 28.1% effective tax rate for 2015. The variance in the tax rate was due to differences in the mix of our domestic and internationalpre-tax earnings and losses, including asset impairments taken during both 2016 and 2015 in various jurisdictions, with differing tax consequences. The 2016 period was also favorably impacted by a $43.0 million adjustment, primarily related to our Egyptian tax liability for uncertain tax positions related to the devaluation of the Egyptian Pound.
Contract Drilling Revenue and Expense by Equipment Type
2017 Compared to 2016
Ultra-Deepwater Floaters.Revenue generated by our ultra-deepwater floaters increased $101.0 million during 2017 compared to 2016, primarily as a result of 472 incremental revenue-earning days ($225.2 million), partially offset by lower average daily revenue earned ($124.2 million). Revenue-earning days increased primarily due to incremental revenue-earning days for theOcean GreatWhite (351 days), which went on contract during the first quarter of 2017, and theOcean BlackRhino,which was warm-stacked for much of 2016 (275 days) before commencing its current contract, and fewer days associated with downtime for repairs (89 days). The increase in 2017 revenue-earning days was partially offset by incremental downtime for theOcean Monarch, which was in the shipyard for a survey and contract modifications during the first half of 2017 (168 days), and the absence of revenue-earning days for two cold-stacked rigs that had worked in 2016 (78 days). Average daily revenue decreased during 2017, primarily due to the absence of $40.0 million in demobilization revenue recognized in 2016 for theOcean Endeavor and the effect of lower dayrates earned under new contracts for both theOcean Monarchand Ocean BlackRhino during 2017, compared to 2016.
Contract drilling expense for our ultra-deepwater floaters increased $67.0 million during 2017, compared to 2016, primarily due to incremental contract drilling expense for theOcean GreatWhite($37.0 million), incremental costs associated with the PCbtH program on our drillships ($27.8 million), higher costs for rig mobilization ($14.0 million) and labor and personnel ($5.9 million), combined with a net increase in other rig operating costs ($2.5 million). These increased costs for our ultra-deepwater floaters were partially offset by a reduction in repair and maintenance expenses ($5.6 million) and costs associated with international shorebases and overhead costs ($14.5 million).
Deepwater Floaters.Revenue generated by our deepwater floaters decreased $54.7 million in 2017, compared to 2016, primarily due to a reduction in average daily revenue earned ($63.8 million), partially offset by the effect of 30 incremental revenue-earning days ($9.2 million). Average daily revenue decreased during 2017, primarily as a result of a lower dayrate being earned by theOcean Valiant under its current contract in the North Sea that commenced in the fourth quarter of 2016. Revenue-earning days increased primarily due to 218 incremental days for our active deepwater floaters, partially offset by 188 fewer days for theOcean Victory, which had been under contract during 2016.
Contract drilling expense for our deepwater floaters decreased $33.6 million during 2017, compared to 2016, primarily due to a net reduction in costs associated with labor and personnel ($14.2 million), maintenance and repairs ($11.2 million), equipment rental ($2.6 million), freight ($1.4 million) and other rig operating and overhead costs ($4.2 million) attributable to various factors, including the cold stacking of rigs and implementation of cost control initiatives for our working rigs and shorebase operations in 2016.
Mid-Water Floaters.Revenue and contract drilling expense during 2017 for ourmid-water floaters decreased $111.2 million and $15.1 million, respectively, compared to 2016. The decrease in revenue during 2017 resulted from 282 fewer revenue-earning days ($96.5 million), combined with a lower average daily revenue earned ($14.4 million). The decrease in revenue-earning days primarily related to the completion of the final contract for theOcean Ambassador in March 2016 (78 days) and fewer days for both theOcean Guardian, which was warm stacked between contracts for much of 2017 (166 days), and theOcean Patriot(38 days),which commenced a shipyard project and survey in late 2017. The decrease in contract drilling expense was primarily due to reduced costs related to theOcean Ambassador ($8.1 million), and a reduction in labor and personnel ($5.6 million) and other costs ($1.5 million) for the remainder of ourmid-water rigs. Only two rigs remain in ourmid-water fleet, both of which operated under contract for portions of 2017 and 2016, while the remainder of ourmid-water fleet was cold stacked and has now been sold.
Jack-ups.Contract drilling revenue attributable to our current and previously-ownedjack-up rigs decreased $9.1 million during 2017, compared to 2016. TheOcean Scepter, which had been idle since completion of its previous contract in 2016, returned to Mexico for a new contract in early 2017 and operated until November 2017 at a lower dayrate than previously earned ($4.1 million). The rig was relocated to the Gulf of Mexico in late 2017 and is currently being
marketed for sale. The decrease in contract drilling revenue also reflected the absence of $4.9 million inloss-of-hire insurance proceeds recognized in 2016.
Contract drilling expense for ourjack-up rigs increased $7.6 million during 2017, compared to 2016, primarily due to higher costs incurred by theOcean Scepter for labor and personnel ($6.4 million) and repairs ($1.7 million), partially offset by reduced costs associated with sold rigs ($0.5 million).
2016 Compared to 2015
Ultra-Deepwater Floaters.Revenue generated by our ultra-deepwater floaters during 2016 decreased $349.9 million compared to 2015, primarily as a result of 616 fewer revenue-earning days ($306.8 million), combined with lower average daily revenue earned ($43.1 million). Revenue-earning days for 2016 decreased primarily due to fewer revenue-earning days for cold-stacked rigs that had operated during 2015 (716 days) and theOcean Clipper,which was sold in late 2015 (245 days), and unplanned downtime for repairs (22 days). The aggregate decrease in revenue-earning days was partially offset by incremental revenue-earning days for our drillships (185 days), and theOcean Monarch, which was warm stacked for the first half of 2015 (182 days). Average daily revenue decreased in 2016 primarily due to lower amortized mobilization and contract preparation revenue compared to 2015.
Contract drilling expense for our entire ultra-deepwater floater fleet decreased $125.6 million during 2016, compared to 2015 and was net of incremental contract drilling expense of $74.9 million attributable to our four drillships and theOcean GreatWhite,which was placed in service in late 2016. Contract drilling expense for our other ultra-deepwater floaters decreased $200.5 million during 2016, compared to 2015, reflecting lower expense for labor and personnel ($92.7 million), maintenance and inspections ($38.5 million), mobilization ($26.8 million), shorebase and operational support ($16.2 million), freight ($9.8 million), revenue-based agency fees ($8.2 million), and other rig operating and overhead costs ($8.3 million). These reductions in contract drilling expense were primarily due to lower costs for our cold-stacked rigs and theOcean Clipper, as well as other cost reduction initiatives.
Deepwater Floaters.Revenue generated by our deepwater floaters decreased $291.7 million in 2016, compared to 2015, primarily due to 495 fewer revenue-earning days ($202.9 million), combined with a lower average daily revenue earned ($88.7 million). The net reduction in revenue-earning days in 2016 reflected 782 fewer days for cold-stacked rigs that had operated in 2015, partially offset by incremental revenue-earning days for other deepwater rigs with contracts that commenced inmid-2015 and in 2016. Average daily revenue decreased primarily as a result of lower amortized mobilization and contract preparation fees ($21.9 million), combined with lower dayrates earned by theOcean Valiant andOcean Apex during 2016 compared to 2015.
Contract drilling expense incurred by our deepwater floaters decreased $128.8 million during 2016, compared to 2015, primarily due to lower costs associated with cold-stacked rigs and cost control initiative in our onshore bases and corporate facilities. Compared to 2015, contract drilling expense in 2016 for our deepwater floaters reflected reductions in costs for labor and personnel ($51.3 million), mobilization of rigs ($29.5 million), repairs, maintenance and inspections ($18.7 million), shorebase and operational support ($15.1 million), revenue-based agency fees ($4.4 million), freight ($4.1 million) and other operating costs ($5.7 million).
Mid-Water Floaters.Revenue generated by ourmid-water floaters during 2016 decreased $138.7 million compared to 2015, primarily due to 706 fewer revenue-earning days ($191.0 million), partially offset by higher average daily revenue earned ($52.0 million), which included a $36.0 million settlement received in connection with a contractual dispute with a former customer. Revenue-earning days decreased in 2016, primarily due to fewermid-water floaters operating under contracts during 2016 (three rigs) compared to 2015 (nine rigs).
Contract drilling expense for ourmid-water floaters decreased $146.4 million in 2016, compared to 2015, reflecting a reduction in costs attributable to rigs that have been retired ($109.0 million). Other cost reductions in 2016, compared to 2015, include lower costs for labor and personnel ($19.1 million), maintenance, repairs and inspections ($9.9 million),
shorebase and operational support ($6.1 million) and other ($2.3 million), primarily due to lower activity and cost control initiatives.
Jack-ups.Contract drilling revenue and expense for ourjack-up fleet decreased $54.7 million and $47.8 million, respectively, during 2016 compared to 2015. Revenue-earning days decreased by 760 days due to the cold stacking of three rigs that operated under contract during 2015 and an early contract termination for theOcean Scepter in 2016.
Liquidity and Capital Resources
We principally rely on our cash flows from operations and cash reserves to meet our liquidity needs. We may also utilize borrowings under our $1.5credit agreements that provide for maximum borrowings of up to $1.275 billion, syndicated revolving credit agreement, or all of which was available to us as of February 8, 2019. See “–Sources and Uses of Cash –Credit Agreement. See “— Credit Agreement.Agreements.”
Based on our cash available for current operations and contractual backlog of $2.4 billion, In addition, as of January 1, 2018,2019, our contractual backlog was $2.0 billion, of which $1.2$0.9 billion is expected to be realized during 2019.
Previously, we have asserted that the earnings of our foreign subsidiaries were indefinitely reinvested to finance our foreign activities, and, as such, these earnings were not available to our stockholders or to finance our domestic activities. As a result of the Tax Reform Act and the deemed repatriation of the accumulated earnings of our foreign subsidiaries in 2017, we have determined that we will no longer permanently reinvest our foreign earnings. Accordingly, our earnings and cash are available to finance both our domestic and foreign activities. We expect to record the withholding income tax impact associated with the potential distribution of earnings of our foreign subsidiaries; however, we have not provided income tax on the outside basis difference of our international subsidiaries as management does not intend to dispose of these subsidiaries and structuring alternatives exist to mitigate any potential liability should a disposition take place.
At December 31, 2018, we had cash available for current operations of $154.1 million and investments in U.S. Treasury bills of $299.8 million, all of which matured at various times during January 2019.
We have historically invested a significant portion of our cash flows in the enhancement of our drilling fleet. The amount of cash required to meet our capital commitments is determined by evaluating the need to upgrade our rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments to them if required.
Based on our cash available and contractual backlog, we believe futureour 2019 capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement,credit agreements, as needed. See “— “–Sources and Uses of Cash — –Rig Reactivation, Upgrade and Other Capital Expenditures.” and “Risk Factors —We can provide no assurance that our drilling contracts will not be terminated early or that our current backlog of contract drilling revenue will be ultimately realized” in Item 1A of this report.
To the extent available, we expect to utilize the operating cash flows generated by and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each entity’s respective working capital requirements and capital commitments. At December 31, 2017, 2016 and 2015, we had cash available for current operations as follows:
| December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
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Cash and cash equivalents | $ | 376,037 | $ | 156,233 | $ | 119,028 | ||||||
Marketable securities | — | 35 | 11,518 | |||||||||
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Total cash available for current operations | $ | 376,037 | $ | 156,268 | $ | 130,546 | ||||||
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A substantial portion of our cash flows has historically been invested in the enhancement of our drilling fleet, including $1.6 billion since 2015 for the construction of two newbuild rigs and other capital enhancement projects. We determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We also make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments thereto if required. See “— Sources and Uses of Cash — Capital Expenditures.”
We pay dividends at the discretion of our Board of Directors, or Board, and any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. Our dividend policy may change from time to time, and there can be no assurance that we will declare any cash dividends at all or in any particular amounts. See “Risk Factors —Although we have paid cash dividends in the past, we did not pay any dividends in 2017 and we may not pay dividends in the future and we can give no assurance as to the amount or timing of the payment of any future dividends” in Item 1A of this report, which is incorporated herein by reference. We did not pay any dividends in 2017 or 2016. We paid regular cash dividends in the aggregate amount of $68.6 million during 2015.
Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any shares of our outstanding common stock during 2018, 2017 2016 or 2015.
During 2016, we entered into foursale-and-leaseback transactions for certain well control equipment on our drillships and received proceeds of $210.0 million. See “— Contractual Cash Obligations —Pressure Control by the Hour®.”2016.
We may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control.
Sources and Uses of Cash
OurDuring 2018, our primary sources of cash flowwere $232.1 million generated by operating activities and proceeds of $70.1 million from operationsthe disposition of assets, primarily from the sale of theOcean Victory andOceanScepter. Excluding a net $296.0 million investment in U.S. Treasury bills, we funded capital expenditures for each of the years$222.4 million during 2018 and incurred $5.7 million in the three-year period ended December 31, 2017 was as follows:fees associated with our credit facilities.
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
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Cash flow from operations | $ | 493,808 | $ | 646,554 | $ | 736,427 | ||||||
Capital expenditures: | ||||||||||||
Drillship construction | $ | — | $ | 55,426 | $ | 454,093 | ||||||
Construction of ultra-deepwater floater | — | 503,172 | 55,805 | |||||||||
Rig equipment and replacement program | 139,581 | 94,075 | 320,757 | |||||||||
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Total capital expenditures | $ | 139,581 | $ | 652,673 | $ | 830,655 | ||||||
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Cash Flowfrom OperationsOperations.. Cash flow from operations for 2018 decreased approximately $152.7$261.8 million during 2017, compared to 2016,2017, primarily due to lower cash receipts fromfor contract drilling services ($245.0 million) and higher income taxes paid, net of refunds ($26.3312.2 million), partially offset by a $118.6 million net decrease in cash paymentsexpenditures for contract drilling and general and administrative expenses, including personnel-related, repairs and maintenance, shorebase, overheadsservices and other rig operating costs.working capital requirements ($8.3 million) and lower income tax payments, net of refunds ($42.2 million). The declinedecrease in both cash receipts and cash payments relatedflow from operations in 2018, compared to 2017, is primarily the performanceresult of reduced demand for our contract drilling services, reflectswhich continued depressed market conditions in the offshore drilling industry, as well as the positive results of our focus on controlling costs.
Cash flow from operations decreased approximately $89.9 million during 2016, compared to 2015, primarily due to lower cash receipts from contract drilling services ($704.9 million),into 2018, partially offset by a $584.8 million net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, maintenance, mobilization, shorebase and operational support and other rig operating costs and lower income taxes paid, net of refunds ($30.2 million). The decline in both cash receipts from and cash payments related to contract drilling services reflects an aggregate decline in our contract drilling operations, as well as a lower cost structure and implementation of our cost control initiatives.
See “— Results of Operations — Years Ended December 31, 2017, 2016Rig Reactivation, Upgrades and 2015.”
Other Capital Expenditures.Expenditures. As of the date of this report, we expect total capital expenditures in 2019 to be approximately $340 million to $360 million. Projects for 2018 to aggregate2019 include (i) $110 million in capitalized costs associated with the reactivation and upgrade of theOcean Onyx, (ii) approximately $220.0$20 million forassociated with the reactivation of theOcean Endeavor, and (iii) other capital expenditures under our ongoing capital maintenance and replacement programs. We expect to fundprograms, including equipment upgrades for theOcean BlackHawk andOcean BlackHornet.
Credit Agreements.In October 2018, we amended our 2018 capital spending from our operating cash flows and our cash reserves.existing5-year
Credit Agreement
Our Credit Agreement provides for a $1.5 billion senior unsecured revolving credit facilityagreement, reducing the maximum availability under the agreement to $325.0 million, of which $40.0 million of the commitments mature in March 2019, $60.0 million of the commitments mature in October 2019 and $225.0 million of the commitments mature in October 2020. Concurrently, we entered into a new senior5-year revolving credit agreement in the amount of $950.0 million that may be used for general corporate purposes, maturing onincluding investments, acquisitions and capital expenditures. The new facility, which matures in October 22, 2020, except2023, provides for $40a swingline subfacility of $100.0 million and a letter of commitments that mature on March 17, 2019 and $60 millioncredit subfacility in the amount of commitments that mature on October 22, 2019.$250.0 million. As of December 31, 2017, we had2018, there were no borrowings
amounts outstanding under the Credit Agreement,credit agreements.
We are subject to various restrictive covenants and we were in compliance with all covenant requirements. As of February 9, 2018, we had no borrowings outstanding and $1.5 billion availableborrowing limitations under our Credit Agreementcredit agreements, and repayment of borrowings under our credit agreements is subject to provide short-term liquidity for our payment obligations.acceleration upon the occurrence of an event of default.
Senior Notes
Notes.As of December 31, 2017,2018, we had an aggregate $2.0 billion in long-term, unsecured senior notes outstanding which will mature at various times beginning in 2023 through 2043.
During 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 deducting underwriting discounts, commissions and expenses. The 2025 Notes bear interest at 7.875% per year and mature on August 15, 2025. Interest on the 2025 Notes is payable semiannually in arrears on February 15 and August 15 of each year, beginning February 15, 2018. We used the net proceeds from the 2025 Notes, together with cash on hand, to fund the redemption of our 5.875% senior notes due 2019 at a redemption price of $543.0 million. See Note 910 “Credit AgreementAgreements and Senior Notes” to our Consolidated Financial Statements in Item 8 of this report.report, which is incorporated herein by reference.
During 2015, we repaid maturing senior notes of $250.0 million.
Credit Ratings
In July 2017, Moody’s Investor Services downgraded our corporate credit rating to Ba3 with a negative outlook from Ba2 with a stable outlook. In October 2017,August 2018, S&P Global Ratings, or S&P, downgraded our corporate credit rating to B from B+ fromBB-;, and Moody’s Investor Services, or Moody’s, downgraded our corporate credit rating to B2 from Ba3. In October 2018, Moody’s downgraded our senior unsecured notes credit rating to B3 from B2. The rating outlook byfrom both S&P and Moody’s remains negative. These credit ratings are below investment grade. Market conditionsgrade and other factors, many of which are outside of our control, could cause our credit ratings to be lowered further. Any further downgrade in our credit ratings could adversely impactraise our cost of issuing additional debt and the amount of additional debt that we could issue, and could further restrict our access to capital markets and our ability to raise funds by issuing additional debt.financing. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.
Contractual Cash Obligations
The following table sets forth our contractual cash obligations at December 31, 2017.2018 (in thousands).
| Payments Due By Period | Payments Due By Period | |||||||||||||||||||||||||||||||||||||||
Contractual Obligations (1) | Total | Less than 1 year | 1–3 years | 4–5 years | After 5 years | Total | Less than 1 year | 1 – 3 years | 4 – 5 years | After 5 years | ||||||||||||||||||||||||||||||
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Long-term debt (principal and interest) | $ | 3,944,375 | $ | 113,063 | $ | 226,125 | $ | 226,125 | $ | 3,379,063 | $ | 3,831,313 | $ | 113,063 | $ | 226,125 | $ | 476,125 | $ | 3,016,000 | ||||||||||||||||||||
PCbtH program | 550,000 | 65,000 | 130,000 | 130,000 | 225,000 | 485,000 | 65,000 | 130,000 | 130,000 | 160,000 | ||||||||||||||||||||||||||||||
Property leases | 2,587 | 1,733 | 762 | 92 | — | 3,172 | 2,093 | 1,079 | — | — | ||||||||||||||||||||||||||||||
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Total obligations | $ | 4,496,962 | $ | 179,796 | $ | 356,887 | $ | 356,217 | $ | 3,604,063 | $ | 4,319,485 | $ | 180,156 | $ | 357,204 | $ | 606,125 | $ | 3,176,000 | ||||||||||||||||||||
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| (1) | The above table excludes |
Tax Reform Act.At December 31, 2017, we had no current income tax liability with respect to the deemed repatriation of earnings or other provisions of the Tax Reform Act. See “Important Factors that May Impact Our Operating Results, Financial Condition or Cash Flows —Impact of Changes in Tax Laws or Their Interpretation” and Note 15 “Income Taxes” to our Consolidated Financial Statements in Item 8 of this report.
Pressure Control by the Hour®. In 2016, we entered into aten-year agreement with a subsidiary of GE Oil & Gas, or GE, to provide services with respect to certain blowout preventer and related well control equipment on our four drillships. Such services include management of maintenance, certification and reliability with respect to such equipment. In connection with the services agreement with GE, we sold the equipment to a GE affiliate for an aggregate $210.0 million and are leasing back such equipment over separateten-year operating leases. Collectively, we refer to the services agreement with GE and the lease agreements with the GE affiliate as the “PCbtH program.” See Note 1213 “Sale and Leaseback Transactions” to our Consolidated Financial Statements in Item 8 of this report.
Except for our contractual requirements under the PCbtH program discussed above, we had no other purchase obligations for major rig upgrades or any other significant obligations at December 31, 2017,2018, except for those related to our direct rig operations, which arise during the normal course of business.
Other Commercial Commitments —– Letters of Credit
We were contingently liable as of December 31, 20172018 in the amount of $20.4$25.7 million under certain performance, tax, supersedeas, bidVAT and customs bonds and letters of credit. Agreements relating to approximately $14.8$17.1 million of supersedeas, tax and customs bonds can require collateral at any time. As of December 31, 2017,2018, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.expiration (in thousands).
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| Total | 2018 | 2019 | ||||||||||
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Other Commercial Commitments | ||||||||||||
Performance bond | $ | 1,000 | $ | — | $ | 1,000 | ||||||
Supersedeas bond | 9,189 | 9,189 | — | |||||||||
Tax bond | 5,408 | 5,408 | — | |||||||||
Bid bond | 3,200 | 3,200 | — | |||||||||
Other | 1,649 | 1,649 | — | |||||||||
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Total obligations | $ | 20,446 | $ | 19,446 | $ | 1,000 | ||||||
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Other Commercial Commitments | ||||||||||||||||
Customs bonds | $ | 9,243 | $ | 8,954 | $ | 106 | $ | 183 | ||||||||
Tax bonds | 9,119 | 5,814 | — | 3,305 | ||||||||||||
Performance bonds | 7,100 | 1,000 | — | 6,100 | ||||||||||||
Other | 229 | 229 | — | — | ||||||||||||
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Total obligations | $ | 25,691 | $ | 15,997 | $ | 106 | $ | 9,588 | ||||||||
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Off-Balance Sheet Arrangements
At December 31, 20172018 and 2016,2017, we had nooff-balance sheet debt or otheroff-balance sheet arrangements.
Other
Operations Outside the U.S.Our operations outside the U.S. accounted for approximately 41%, 58% and 69% of our total consolidated revenues for the years ended December 31, 2018, 2017 and 2016, respectively. See “Risk Factors –Significant portions of our operations are conducted outside the U.S. and involve additional risks not associated with U.S. domestic operations” in Item 1A of this report.
Currency Risk.Some of our subsidiaries conduct a portion of their operations in the local currency of the country where they conduct operations, resulting in foreign currency exposure. Currency environments in which
we currently have or previously had significant business operations include Australia, Brazil, Egypt, Malaysia, Mexico, Trinidad and Tobago and the U.K., creating exposure to certain monetary assets and liabilities denominated in currencies other than the U.S. dollar. These assets and liabilities are revalued based on currency exchange rates at the end of the reporting period.
To reduce our currency exchange risk, we may, if possible, arrange for a portion of our international contracts to be payable to us in local currency in amounts equal to our estimated operating costs payable in local currency, with the balance of the contract payable in U.S. dollars. At present, however, only a limited number of our contracts are payable both in U.S. dollars and the local currency. Historically, to the extent that we have not been able to cover our local currency operating costs with customer payments in the local currency, we have also utilized foreign currency forward exchange, or FOREX, contracts to reduce our currency exchange risk. WeAs of the date of this report, we currently have no outstanding FOREX contracts.
We record currency transaction gains and losses and gains and losses arising from the settlement of our FOREX contracts that have been designated as cash flow hedges as “Foreign currency transaction (loss) gain” and “Contract drilling, excluding depreciation” expense, respectively, in our Consolidated Statements of Operations. The revaluation of liabilities denominated in currencies other than the U.S. dollar related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, is reported as a component of “Income tax benefit,”benefit” in our Consolidated Statements of Operations.
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:
market conditions and the effect of such conditions on our future results of operations;
sources and uses of and requirements for financial resources and sources of liquidity;
contractual obligations and future contract negotiations;
interest rate and foreign exchange risk;
operations outside the United States;
business strategy;
growth opportunities;
competitive position including, without limitation, competitive rigs entering the market;
expected financial position;
cash flows and contract backlog;
| • | future |
idling drilling rigs or reactivating stacked rigs;
outcomes of litigation and legal proceedings;
declaration and payment of dividends;
financing plans;
market outlook;
tax planning and effects of the Tax Reform Act;
debt levels and the impact of changes in the credit markets and credit ratings for our debt;
budgets for capital and other expenditures;
timing and duration of required regulatory inspections for our drilling rigs;
timing and cost of completion of capital projects;
delivery dates and drilling contracts related to capital projects or rig acquisitions;
| • | the reactivation of and future contracts for theOcean EndeavorandOcean Onyx; |
plans and objectives of management;
scrapping retired rigs;
asset impairments and impairment evaluations;
our internal controls and internal control over financial reporting;
performance of contracts;
purchases of our securities;
compliance with applicable laws; and
availability, limits and adequacy of insurance or indemnification.
These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:
those described under “Risk Factors” in Item 1A;
general economic and business conditions and trends, including recessions and adverse changes in the level of international trade activity;
worldwide supply and demand for oil and natural gas;
changes in foreign and domestic oil and gas exploration, development and production activity;
oil and natural gas price fluctuations and related market expectations;
the ability of OPEC to set and maintain production levels and pricing, and the level of production innon-OPEC countries;
policies of various governments regarding exploration and development of oil and gas reserves;
the cancellation of contracts included in our reported contract backlog;
advances in exploration and development technology;
the worldwide political and military environment, including, for example, inoil-producing regions and locations where our rigs are operating or are in shipyards;
casualty losses;
operating hazards inherent in drilling for oil and gas offshore;
the risk that dividends may not be declared or paid;
the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico;
industry fleet capacity;
market conditions in the offshore contract drilling industry, including, without limitation, dayrates and utilization levels;
competition;
changes in foreign, political, social and economic conditions;
risks of international operations, compliance with foreign laws and taxation policies and seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of equipment and assets;
risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time;
customer or supplier bankruptcy, liquidation or other financial difficulties;
the ability of customers and suppliers to meet their obligations to us and our subsidiaries;
collection of receivables;
foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital;
risks of war, military operations, other armed hostilities, sabotage, piracy, cyber attack, terrorist acts and embargoes;
changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness;
reallocation of drilling budgets away from offshore drilling in favor of other priorities such as shale or other land-based projects;
regulatory initiatives and compliance with governmental regulations including, without limitation, regulations pertaining to climate change, greenhouse gases, carbon emissions or energy use;
compliance with and liability under environmental laws and regulations;
uncertainties surrounding deepwater permitting and exploration and development activities;
development and exploitation of alternative fuels;
customer preferences;
risks of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts;
cost, availability, limits and adequacy of insurance;
invalidity of assumptions used in the design of our controls and procedures and the risk that material weaknesses may arise in the future;
business opportunities that may be presented to and pursued or rejected by us;
the results of financing efforts;
adequacy and availability of our sources of liquidity;
risks resulting from our indebtedness;
public health threats;
negative publicity; and
impairments of assets.
The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we may refer to reports published by third parties that purport to describe trends or developments in energy production or drilling and exploration activity. While we believe that each of these reports is reliable, we have not independently verified the information included in such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.
New Accounting Pronouncements
For a discussion of recent accounting pronouncements, which are not yet effective, and their effect on our financial position, results of operations and cash flows, see Note 1 “General Information —Information—Recent Accounting Pronouncements Not Yet Adopted” to our Consolidated Financial Statements in Item 8 of this report.
| Item 7A. |
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The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations —– Forward-Looking Statements” in Item 7 of this report.
Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 20172018 and 2016,2017, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.
Exposure to market risk is managed and monitored by our senior management. Senior management approves the overall investment strategy that we employ and has responsibility to ensure that the investment positions are consistent with that strategy and the level of risk acceptable to us. We may manage risk by buying or selling instruments or entering into offsetting positions.
Interest Rate Risk. We have exposure to interest rate risk arising from changes in the level or volatility of interest rates. Historically, ourOur investments in marketable securities were primarilyare in fixed maturity securities. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. Our exposureThe evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such risk was minimala change in 2017rates would have on the recorded market value of our investments and 2016 asthe resulting effect on stockholders’ equity. The analysis provides the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we had no investmentsbelieve are reasonably possible over aone-year period.
The sensitivity analysis estimates the change in marketable securities atthe market value of our interest sensitive assets and liabilities that were held on December 31, 2018 and 2017, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant.
The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the fair valueanalysis may not be indicative of, such securities was immaterial asis not intended to provide, and does not provide a precise forecast of December 31, 2016.the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.
Our long-term debt, as of December 31, 20172018 and 2016,2017, is denominated in U.S. dollars. Our existing debt has been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts. The impact of a100-basis point increase in interest rates on fixed rate debt would result in a decrease in market value of $145.1$94.9 million and $125.3$145.1 million as of December 31, 20172018 and 2016,2017, respectively. A100-basis point decrease would result in an increase in market value of $168.9$108.6 million and $147.3$168.9 million as of December 31, 2018 and 2017, and 2016, respectively.
We are also subject to risk exposure related to the variable interest rates charged on our revolving credit arrangement,agreements, which are calculated on a base rate as defined in the respective credit agreement.
Our marketable securities at December 31, 2018, included investments in U.S. Treasury bills with a fair value of $299.8 million. The impact of a100-basis point increase in interest rates would result in a decrease in market value of these securities of $0.1 million, while a100-basis point decrease in interest rates would result in an increase in market value of $0.1 million at December 31, 2018. We had no such investments outstanding as of December 31, 2017.
| Item 8. | Financial Statements and Supplementary Data. |
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of Diamond Offshore Drilling, Inc. and Subsidiaries
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and subsidiaries (the “Company”) as of December 31, 20172018 and 2016,2017, the related consolidated statements of income,operations, comprehensive income shareholders’or loss, stockholders’ equity, and cash flows, for each of the three years in the period ended December 31, 2017,2018, and the related notes (collectively referred to as “the financialthe “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172018 and 2016,2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017,2018, in conformity with the accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2017,2018, based on criteria established inInternal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 13, 2018,2019, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. 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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 13, 20182019
We have served as the Company’s auditor since 1989.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Stockholders and the Board of Directors of Diamond Offshore Drilling, Inc. and Subsidiaries
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc. and subsidiaries’subsidiaries (the “Company”) as of December 31, 2017,2018, based on criteria established inInternal 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, 2017,2018, based on criteria established inInternal 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, 2017,2018, of the Company and our report dated February 13, 2018,2019, expressed an unqualified opinion on those financial statements.
Basis for Opinion
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.
Definition and Limitations of Internal Control over Financial Reporting
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.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
February 13, 20182019
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
(In thousands, except share and per share data)
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2018 | 2017 | |||||||||||||
| ASSETS | ||||||||||||||||
Current assets: | ||||||||||||||||
Current assets: | ||||||||||||||||
Cash and cash equivalents | $ | 376,037 | $ | 156,233 | $ | 154,073 | $ | 376,037 | ||||||||
Marketable securities | 299,849 | — | ||||||||||||||
Accounts receivable, net of allowance for bad debts | 256,730 | 247,028 | 168,620 | 256,730 | ||||||||||||
Prepaid expenses and other current assets | 157,625 | 102,146 | 163,396 | 157,625 | ||||||||||||
Assets held for sale | 96,261 | 400 | — | 96,261 | ||||||||||||
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Total current assets | 886,653 | 505,807 | 785,938 | 886,653 | ||||||||||||
Drilling and other property and equipment, net of accumulated depreciation | 5,261,641 | 5,726,935 | 5,184,222 | 5,261,641 | ||||||||||||
Other assets | 102,276 | 139,135 | 65,534 | 102,276 | ||||||||||||
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Total assets | $ | 6,250,570 | $ | 6,371,877 | $ | 6,035,694 | $ | 6,250,570 | ||||||||
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| LIABILITIES AND STOCKHOLDERS’ EQUITY | ||||||||||||||||
Current liabilities: | ||||||||||||||||
Accounts payable | $ | 38,755 | $ | 30,242 | $ | 43,933 | $ | 38,755 | ||||||||
Accrued liabilities | 154,655 | 182,159 | 172,228 | 154,655 | ||||||||||||
Taxes payable | 29,878 | 23,898 | 20,685 | 29,878 | ||||||||||||
Short-term borrowings | — | 104,200 | ||||||||||||||
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| |||||||||||||
Total current liabilities | 223,288 | 340,499 | 236,846 | 223,288 | ||||||||||||
Long-term debt | 1,972,225 | 1,980,884 | 1,973,922 | 1,972,225 | ||||||||||||
Deferred tax liability | 167,299 | 197,011 | 104,380 | 167,299 | ||||||||||||
Other liabilities | 113,497 | 103,349 | 135,893 | 113,497 | ||||||||||||
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| |||||||||||||
Total liabilities | 2,476,309 | 2,621,743 | 2,451,041 | 2,476,309 | ||||||||||||
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Commitments and contingencies (Note 11) | — | — | ||||||||||||||
Commitments and contingencies (Note 12) | — | — | ||||||||||||||
Stockholders’ equity: | ||||||||||||||||
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding) | — | — | — | — | ||||||||||||
Common stock (par value $0.01, 500,000,000 shares authorized; 144,085,292 shares issued and 137,227,782 shares outstanding at December 31, 2017; 143,997,757 shares issued and 137,169,663 shares outstanding at December 31, 2016) | 1,441 | 1,440 | ||||||||||||||
Common stock (par value $0.01, 500,000,000 shares authorized; | 1,444 | 1,441 | ||||||||||||||
Additionalpaid-in capital | 2,011,397 | 2,004,514 | 2,018,143 | 2,011,397 | ||||||||||||
Retained earnings | 1,964,497 | 1,946,765 | 1,769,415 | 1,964,497 | ||||||||||||
Accumulated other comprehensive gain (loss) | (5 | ) | 1 | 21 | (5 | ) | ||||||||||
Treasury stock, at cost (6,857,510 and 6,828,094 shares of common stock at December 31, 2017 and 2016, respectively) | (203,069 | ) | (202,586 | ) | ||||||||||||
Treasury stock, at cost (6,945,309 and 6,857,510 shares of common stock at December 31, 2018 and 2017, respectively) | (204,370 | ) | (203,069 | ) | ||||||||||||
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Total stockholders’ equity | 3,774,261 | 3,750,134 | 3,584,653 | 3,774,261 | ||||||||||||
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Total liabilities and stockholders’ equity | $ | 6,250,570 | $ | 6,371,877 | $ | 6,035,694 | $ | 6,250,570 | ||||||||
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The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | |||||||||||||||||||
Revenues: | ||||||||||||||||||||||||
Contract drilling | $ | 1,451,219 | $ | 1,525,214 | $ | 2,360,184 | $ | 1,059,973 | $ | 1,451,219 | $ | 1,525,214 | ||||||||||||
Revenues related to reimbursable expenses | 34,527 | 75,128 | 59,209 | 23,242 | 34,527 | 75,128 | ||||||||||||||||||
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Total revenues | 1,485,746 | 1,600,342 | 2,419,393 | 1,083,215 | 1,485,746 | 1,600,342 | ||||||||||||||||||
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Operating expenses: | ||||||||||||||||||||||||
Contract drilling, excluding depreciation | 801,964 | 772,173 | 1,227,864 | 722,834 | 801,964 | 772,173 | ||||||||||||||||||
Reimbursable expenses | 33,744 | 58,058 | 58,050 | 22,917 | 33,744 | 58,058 | ||||||||||||||||||
Depreciation | 348,695 | 381,760 | 493,162 | 331,789 | 348,695 | 381,760 | ||||||||||||||||||
General and administrative | 74,505 | 63,560 | 66,462 | 85,351 | 74,505 | 63,560 | ||||||||||||||||||
Impairment of assets | 99,313 | 678,145 | 860,441 | 27,225 | 99,313 | 678,145 | ||||||||||||||||||
Bad debt recovery | — | (265 | ) | — | — | — | (265 | ) | ||||||||||||||||
Restructuring and separation costs | 14,146 | — | 9,778 | 5,041 | 14,146 | — | ||||||||||||||||||
(Gain) loss on disposition of assets | (10,500 | ) | 3,795 | (2,290 | ) | |||||||||||||||||||
Loss (gain) on disposition of assets | 241 | (10,500 | ) | 3,795 | ||||||||||||||||||||
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Total operating expenses | 1,361,867 | 1,957,226 | 2,713,467 | 1,195,398 | 1,361,867 | 1,957,226 | ||||||||||||||||||
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Operating income (loss) | 123,879 | (356,884 | ) | (294,074 | ) | |||||||||||||||||||
Operating (loss) income | (112,183 | ) | 123,879 | (356,884 | ) | |||||||||||||||||||
Other income (expense): | ||||||||||||||||||||||||
Interest income | 2,473 | 768 | 3,322 | 8,477 | 2,473 | 768 | ||||||||||||||||||
Interest expense, net of amounts capitalized | (113,528 | ) | (89,934 | ) | (93,934 | ) | (123,240 | ) | (113,528 | ) | (89,934 | ) | ||||||||||||
Foreign currency transaction (loss) gain | (1,128 | ) | (11,522 | ) | 2,465 | |||||||||||||||||||
Loss on extinguishment of senior notes | (35,366 | ) | — | — | — | (35,366 | ) | — | ||||||||||||||||
Foreign currency transaction loss | (379 | ) | (1,128 | ) | (11,522 | ) | ||||||||||||||||||
Other, net | 2,230 | (10,727 | ) | 873 | 700 | 2,230 | (10,727 | ) | ||||||||||||||||
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Loss before income tax benefit | (21,440 | ) | (468,299 | ) | (381,348 | ) | (226,625 | ) | (21,440 | ) | (468,299 | ) | ||||||||||||
Income tax benefit | 39,786 | 95,796 | 107,063 | 46,353 | 39,786 | 95,796 | ||||||||||||||||||
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Net income (loss) | $ | 18,346 | $ | (372,503 | ) | $ | (274,285 | ) | ||||||||||||||||
Net (loss) income | $ | (180,272 | ) | $ | 18,346 | $ | (372,503 | ) | ||||||||||||||||
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Earnings (loss) per share: | ||||||||||||||||||||||||
(Loss) earnings per share: | ||||||||||||||||||||||||
Basic | $ | 0.13 | $ | (2.72 | ) | $ | (2.00 | ) | $ | (1.31 | ) | $ | 0.13 | $ | (2.72 | ) | ||||||||
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Diluted | $ | 0.13 | $ | (2.72 | ) | $ | (2.00 | ) | $ | (1.31 | ) | $ | 0.13 | $ | (2.72 | ) | ||||||||
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Weighted-average shares outstanding: | ||||||||||||||||||||||||
Shares of common stock | 137,213 | 137,168 | 137,157 | 137,399 | 137,213 | 137,168 | ||||||||||||||||||
Dilutive potential shares of common stock | 52 | — | — | — | 52 | — | ||||||||||||||||||
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Total weighted-average shares outstanding | 137,265 | 137,168 | 137,157 | 137,399 | 137,265 | 137,168 | ||||||||||||||||||
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The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME OR LOSS
(In thousands)
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
Net income (loss) | $ | 18,346 | $ | (372,503 | ) | $ | (274,285 | ) | ||||
Other comprehensive (losses) gains, net of tax: | ||||||||||||
Derivative financial instruments: | ||||||||||||
Unrealized holding loss | — | — | (1,574 | ) | ||||||||
Reclassification adjustment for (gain) loss included in net income (loss) | (6 | ) | (5 | ) | 5,084 | |||||||
Investments in marketable securities: | ||||||||||||
Unrealized holding loss on investments | — | (6,559 | ) | (4,940 | ) | |||||||
Reclassification adjustment for loss included in net income (loss) | — | 11,600 | — | |||||||||
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Total other comprehensive (loss) gain | (6 | ) | 5,036 | (1,430 | ) | |||||||
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Comprehensive income (loss) | $ | 18,340 | $ | (367,467 | ) | $ | (275,715 | ) | ||||
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| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
Net (loss) income | $ | (180,272 | ) | $ | 18,346 | $ | (372,503 | ) | ||||
Other comprehensive gains (losses), net of tax: | ||||||||||||
Derivative financial instruments: | ||||||||||||
Reclassification adjustment for gain included in net (loss) income | (6 | ) | (6 | ) | (5 | ) | ||||||
Investments in marketable securities: | ||||||||||||
Unrealized holding gain (loss) on investments | 69 | — | (6,559 | ) | ||||||||
Reclassification adjustment for (gain) loss included in net (loss) income | (37 | ) | — | 11,600 | ||||||||
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Total other comprehensive gain (loss) | 26 | (6 | ) | 5,036 | ||||||||
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Comprehensive (loss) income | $ | (180,246 | ) | $ | 18,340 | $ | (367,467 | ) | ||||
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The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(In thousands, except number of shares)
Common Stock | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Gains (Losses) |
Treasury Stock | Total Stockholders’ Equity | Accumulated Other Comprehensive Gains (Losses) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | Additional Paid-In Capital | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
January 1, 2015 | 143,960,260 | 1,440 | 1,993,898 | 2,661,999 | (3,605 | ) | 6,812,361 | (202,169 | ) | 4,451,563 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| Common Stock | Retained Earnings | Accumulated Other Comprehensive Gains (Losses) | Treasury Stock | |||||||||||||||||||||||||||||||||||||||||||||||||||||
Net loss | — | — | — | (274,285 | ) | — | — | — | (274,285 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Dividends to stockholders ($0.50 per share) | — | — | — | (68,578 | ) | — | — | — | (68,578 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation, net of tax | 18,617 | — | 5,736 | — | — | 7,810 | (236 | ) | 5,500 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net gain on derivative financial instruments | — | — | — | — | 3,510 | — | — | 3,510 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net loss on investments | — | — | — | — | (4,940 | ) | — | — | (4,940 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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| Shares | Amount | Additional Paid-In Capital | Retained Earnings | Shares | Amount | Accumulated Other Comprehensive Gains (Losses) | Total Stockholders’ Equity | |||||||||||||||||||||||||||||||||||||||||||||||||
December 31, 2015 | 143,978,877 | 1,440 | 1,999,634 | 2,319,136 | (5,035 | ) | 6,820,171 | (202,405 | ) | 4,112,770 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
January 1, 2016 | 143,978,877 | $ | 1,440 | $ | 2,319,136 | $ | (5,035 | ) | 6,820,171 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Net loss | — | — | — | (372,503 | ) | — | — | — | (372,503 | ) | — | — | — | (372,503 | ) | — | — | — | (372,503 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Anti-dilution adjustment | — | — | — | 132 | — | — | — | 132 | — | — | — | 132 | — | — | — | 132 | ||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation, net of tax | 18,880 | — | 4,880 | — | — | 7,923 | (181 | ) | 4,699 | 18,880 | — | 4,880 | — | — | 7,923 | (181 | ) | 4,699 | ||||||||||||||||||||||||||||||||||||||||||||||
Net loss on derivative financial instruments | — | — | — | — | (5 | ) | — | — | (5 | ) | — | — | — | — | (5 | ) | — | — | (5 | ) | ||||||||||||||||||||||||||||||||||||||||||||
Net gain on investments | — | — | — | — | 5,041 | — | — | 5,041 | — | — | — | — | 5,041 | — | — | 5,041 | ||||||||||||||||||||||||||||||||||||||||||||||||
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December 31, 2016 | 143,997,757 | $ | 1,440 | $ | 2,004,514 | $ | 1,946,765 | $ | 1 | 6,828,094 | $ | (202,586 | ) | $ | 3,750,134 | 143,997,757 | �� | $ | 1,440 | $ | 2,004,514 | $ | 1,946,765 | $ | 1 | 6,828,094 | $ | (202,586 | ) | $ | 3,750,134 | |||||||||||||||||||||||||||||||||
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Impact of change in accounting policy | — | — | 634 | (634 | ) | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Impact of change in accounting principle | — | — | 634 | (634 | ) | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Adjusted balance at December 31, 2016 | 143,997,757 | $ | 1,440 | $ | 2,005,148 | $ | 1,946,131 | $ | 1 | 6,828,094 | $ | (202,586 | ) | $ | 3,750,134 | |||||||||||||||||||||||||||||||||||||||||||||||||
Adjusted balance at January 1, 2017 | 143,997,757 | $ | 1,440 | $ | 2,005,148 | $ | 1,946,131 | $ | 1 | 6,828,094 | $ | (202,586 | ) | $ | 3,750,134 | |||||||||||||||||||||||||||||||||||||||||||||||||
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Net income | — | — | — | 18,346 | — | — | — | 18,346 | — | — | — | 18,346 | — | — | — | 18,346 | ||||||||||||||||||||||||||||||||||||||||||||||||
Anti-dilution adjustment | — | — | — | 20 | — | — | — | 20 | — | — | — | 20 | — | — | — | 20 | ||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation, net of tax | 87,535 | 1 | 6,249 | — | — | 29,416 | (483 | ) | 5,767 | 87,535 | 1 | 6,249 | — | — | 29,416 | (483 | ) | 5,767 | ||||||||||||||||||||||||||||||||||||||||||||||
Net loss on derivative financial instruments | — | — | — | — | (6 | ) | — | — | (6 | ) | — | — | — | — | (6 | ) | — | — | (6 | ) | ||||||||||||||||||||||||||||||||||||||||||||
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December 31, 2017 | 144,085,292 | $ | 1,441 | $ | 2,011,397 | $ | 1,964,497 | $ | (5 | ) | 6,857,510 | $ | (203,069 | ) | $ | 3,774,261 | 144,085,292 | $ | 1,441 | $ | 2,011,397 | $ | 1,964,497 | $ | (5 | ) | 6,857,510 | $ | (203,069 | ) | $ | 3,774,261 | ||||||||||||||||||||||||||||||||
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Impact of change in accounting principle | — | — | — | (14,812 | ) | — | — | — | (14,812 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Adjusted balance at January 1, 2018 | 144,085,292 | $ | 1,441 | $ | 2,011,397 | $ | 1,949,685 | $ | (5 | ) | 6,857,510 | $ | (203,069 | ) | $ | 3,759,449 | ||||||||||||||||||||||||||||||||||||||||||||||||
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Net loss | — | — | — | (180,272 | ) | — | — | — | (180,272 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Anti-dilution adjustment | — | — | — | 2 | — | — | — | 2 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock options exercised | 3,773 | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Stock-based compensation, net of tax | 294,597 | 3 | 6,746 | — | — | 87,799 | (1,301 | ) | 5,448 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net loss on derivative financial instruments | — | — | — | — | (6 | ) | — | — | (6 | ) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net gain on investments | — | — | — | — | 32 | — | — | 32 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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December 31, 2018 | 144,383,662 | $ | 1,444 | $ | 2,018,143 | $ | 1,769,415 | $ | 21 | 6,945,309 | $ | (204,370 | ) | $ | 3,584,653 | |||||||||||||||||||||||||||||||||||||||||||||||||
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The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | |||||||||||||||||||
Operating activities: | ||||||||||||||||||||||||
Net income (loss) | $ | 18,346 | $ | (372,503 | ) | $ | (274,285 | ) | ||||||||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||||
Net (loss) income | $ | (180,272 | ) | $ | 18,346 | $ | (372,503 | ) | ||||||||||||||||
Adjustments to reconcile net (loss) income to net cash provided by operating activities: | ||||||||||||||||||||||||
Depreciation | 348,695 | 381,760 | 493,162 | 331,789 | 348,695 | 381,760 | ||||||||||||||||||
Loss on impairment of assets | 99,313 | 678,145 | 860,441 | 27,225 | 99,313 | 678,145 | ||||||||||||||||||
Loss on extinguishment of senior notes | 35,366 | — | — | — | 35,366 | — | ||||||||||||||||||
Restructuring and separation costs | 14,146 | — | — | 1,478 | 14,146 | — | ||||||||||||||||||
(Gain) loss on disposition of assets | (10,500 | ) | 3,795 | (2,290 | ) | |||||||||||||||||||
Loss (gain) on disposition of assets | 241 | (10,500 | ) | 3,795 | ||||||||||||||||||||
Loss on sale of marketable securities, net | — | 12,146 | — | — | — | 12,146 | ||||||||||||||||||
Loss on foreign currency forward exchange contracts | — | — | 8,364 | |||||||||||||||||||||
Deferred tax provision | (72,127 | ) | (106,263 | ) | (242,034 | ) | (75,993 | ) | (72,127 | ) | (106,263 | ) | ||||||||||||
Stock-based compensation expense | 6,250 | 4,880 | 4,856 | 6,749 | 6,250 | 4,880 | ||||||||||||||||||
Deferred income, net | 8,676 | (29,108 | ) | (45,383 | ) | |||||||||||||||||||
Deferred expenses, net | 46,337 | (20,155 | ) | (26,405 | ) | |||||||||||||||||||
Contract liabilities, net | 183 | 8,676 | (29,108 | ) | ||||||||||||||||||||
Contract assets, net | (6,221 | ) | — | — | ||||||||||||||||||||
Deferred contract costs, net | 22,765 | 46,337 | (20,155 | ) | ||||||||||||||||||||
Other assets, noncurrent | (326 | ) | (4,914 | ) | 2,483 | (1,307 | ) | (326 | ) | (4,914 | ) | |||||||||||||
Other liabilities, noncurrent | (963 | ) | (31 | ) | (3,890 | ) | (3,217 | ) | (963 | ) | (31 | ) | ||||||||||||
Payments of settlement of foreign currency forward exchange contracts designated as accounting hedges | — | — | (8,364 | ) | ||||||||||||||||||||
Other | 7,708 | 5,691 | 858 | 1,560 | 7,708 | 5,691 | ||||||||||||||||||
Changes in operating assets and liabilities: | ||||||||||||||||||||||||
Accounts receivable | (11,049 | ) | 159,098 | 58,872 | 87,970 | (11,049 | ) | 159,098 | ||||||||||||||||
Prepaid expenses and other current assets | (1,291 | ) | 6,187 | 19,195 | 6,211 | (1,291 | ) | 6,187 | ||||||||||||||||
Accounts payable and accrued liabilities | 19,803 | (71,085 | ) | (180,872 | ) | (7,587 | ) | 19,803 | (71,085 | ) | ||||||||||||||
Taxes payable | (14,576 | ) | (1,089 | ) | 71,719 | 20,484 | (14,576 | ) | (1,089 | ) | ||||||||||||||
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Net cash provided by operating activities | 493,808 | 646,554 | 736,427 | 232,058 | 493,808 | 646,554 | ||||||||||||||||||
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Investing activities: | ||||||||||||||||||||||||
Capital expenditures (including rig construction) | (139,581 | ) | (652,673 | ) | (830,655 | ) | (222,406 | ) | (139,581 | ) | (652,673 | ) | ||||||||||||
Proceeds from disposition of assets, net of disposal costs | 15,196 | 221,722 | 13,049 | 70,067 | 15,196 | 221,722 | ||||||||||||||||||
Proceeds from sale and maturities of marketable securities | 35 | 4,614 | 51 | 1,600,000 | 35 | 4,614 | ||||||||||||||||||
Purchase of marketable securities | (1,895,997 | ) | — | — | ||||||||||||||||||||
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Net cash used in investing activities | (124,350 | ) | (426,337 | ) | (817,555 | ) | (448,336 | ) | (124,350 | ) | (426,337 | ) | ||||||||||||
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Financing activities: | ||||||||||||||||||||||||
Repayment of long-term debt | (500,000 | ) | — | (250,000 | ) | |||||||||||||||||||
Redemption of senior notes | — | (500,000 | ) | — | ||||||||||||||||||||
Payment of debt extinguishment costs | (34,395 | ) | — | — | — | (34,395 | ) | — | ||||||||||||||||
Proceeds from issuance of senior notes | 496,360 | — | — | — | 496,360 | — | ||||||||||||||||||
(Repayment of) proceeds from short-term borrowings, net | (104,200 | ) | (182,389 | ) | 286,589 | |||||||||||||||||||
Repayment of short-term borrowings, net | — | (104,200 | ) | (182,389 | ) | |||||||||||||||||||
Debt issuance costs and arrangement fees | (7,263 | ) | (215 | ) | (624 | ) | (5,651 | ) | (7,263 | ) | (215 | ) | ||||||||||||
Payment of dividends and anti-dilution payments | (156 | ) | (408 | ) | (69,432 | ) | ||||||||||||||||||
Other | (35 | ) | (156 | ) | (408 | ) | ||||||||||||||||||
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Net cash used in financing activities | (149,654 | ) | (183,012 | ) | (33,467 | ) | (5,686 | ) | (149,654 | ) | (183,012 | ) | ||||||||||||
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Net change in cash and cash equivalents | 219,804 | 37,205 | (114,595 | ) | (221,964 | ) | 219,804 | 37,205 | ||||||||||||||||
Cash and cash equivalents, beginning of year | 156,233 | 119,028 | 233,623 | 376,037 | 156,233 | 119,028 | ||||||||||||||||||
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Cash and cash equivalents, end of year | $ | 376,037 | $ | 156,233 | $ | 119,028 | $ | 154,073 | $ | 376,037 | $ | 156,233 | ||||||||||||
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The accompanying notes are an integral part of the consolidated financial statements.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
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 17 offshore drilling rigs, consisting of four drillships and seven ultra-deepwater, four deepwater and twomid-water13 semisubmersible rigs. Two rigs, the semisubmersibleOcean Victoryandjack-upOcean Scepter, are reported as “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2017 and have been excluded from our current fleet. TheOcean Victory was sold in January 2018. 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 9, 2018,8, 2019, 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
Revenue Recognition. In May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU,No. 2014-09,Revenue from Contracts with Customers(Topic 606), or ASU2014-09, 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 ASU2014-09 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 ASU2014-09 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 ASUNo. 2016-16,Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory, or ASU2016-16. ASU2016-16 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 ASU2016-16 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 16.
The aggregate impact of the changes in accounting principles, as discussed above, to our Consolidated Balance Sheets on January 1, 2018 was as follows (in thousands):
| Retained Earnings | Prepaid Expenses and Other Current Assets | Other Assets | Deferred Tax Liability | |||||||||||||
Balance as of January 1, 2018 before adoption | $ | 1,964,497 | $ | 157,625 | $ | 102,276 | $ | 167,299 | ||||||||
Adjustments for adoption of: | ||||||||||||||||
Topic 606 | 2,589 | 610 | 2,107 | 128 | ||||||||||||
ASU2016-16 | (17,401 | ) | — | — | 17,401 | |||||||||||
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Balance as of January 1, 2018 after adoption | $ | 1,949,685 | $ | 158,235 | $ | 104,383 | $ | 184,828 | ||||||||
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Other Recently Adopted Accounting Pronouncements
In August 2018, the FASB issued ASUNo. 2018-13,Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement, or ASU2018-13. ASU2018-13 modified the disclosure requirements for fair value measurements, including the (i) removal of certain disclosure requirements regarding transfers between Levels 1 and 2 of the fair value hierarchy and timing thereof and the valuation processes for Level 3 fair value measurements and (ii) a requirement to provide additional information regarding the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. We early adopted the disclosure modifications in ASU2018-13.
In February 2018, the FASB issued ASUNo. 2018-02, Income Statement – Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, or ASU2018-02. ASU2018-02 provides for entities to make aone-time election to reclassify the income tax effects of the Tax Cuts and Jobs Act enacted in December 2017, or the Tax Reform Act, on items within accumulated other comprehensive income to retained earnings. The guidance of ASU2018-02 is effective for fiscal years beginning after December 15, 2018,including interim periods within that reporting period. Early adoption of ASU2018-02 is permitted. We early adopted ASU2018-02 and have reclassified the effect of the change in the U.S. federal corporate income tax rate on deferredtax-related items remaining in accumulated other comprehensive loss. The impact of adoption of ASU2018-02 was not significant.
In August 2016, the FASB issued ASUNo. 2016-15,Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, or ASU2016-15. ASU2016-15 provides specific guidance on eight cash flow classification issues not specifically addressed by GAAP: debt prepayment or debt extinguishment costs; settlement ofzero-coupon debt instruments; contingent consideration payments; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The adoption of ASU2016-15 did not have a significant impact on the presentation of cash receipts and cash payments within our consolidated statements of cash flows.
Recent Accounting Pronouncements Not Yet Adopted
In February 2016, the FASB issued ASUNo. 2016-02, Leases (Topic 842), or ASU2016-02, which (i) requires lessees to recognize a right of use asset and a lease liability on the balance sheet for virtually all 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 the entity’s leasing arrangements. This update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. We adopted ASU2016-02 effective January 1, 2019 and elected the optional transition method whereby initial application of the new standard begins on the date of adoption and comparative periods are not restated. This transition method allows for the initial recognition of a cumulative effect adjustment to retained earnings in the year of adoption, however, we do not expect that such an adjustment will be required based on our analysis of current lease arrangements. We also expect to elect the transition practical expedient package available in the ASU whereby we will 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.
During our evaluation of ASU2016-02, we concluded that our drilling contracts contain a lease component based on the updated definition of a lease. Our typical drilling contracts qualify for a practical expedient, which is available to lessors under certain circumstances, to combine the lease andnon-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. We intend to apply this practical expedient and will combine the lease and service components of our standard drilling contracts and continue to account for the combined component under Topic 606,Revenue from Contracts with Customers.
With respect to leases whereby we are the lessee, we expect to recognize lease liabilities and offsetting right of use assets of between $120 million and $130 million, primarily related to certain leased subsea equipment. However, we are still finalizing our evaluation of the overall impact.
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, 2018, 2017 2016 and 2015.2016.
Provision for Bad Debts
We record a provision for bad debts on acase-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible. In establishing these reserves, we consider historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. Such provision is reported as a component of “Operating expense” in our Consolidated Statements of Operations. See Note 3.4.
Assets Held Forfor Sale
We reported the $96.3 million and $0.4 million carrying valuesvalue of certaintwo of our rigs, being marketed for saletheOcean Scepter andOcean Victory, as “Assets held for sale” in our Consolidated Balance Sheets at December 31, 2017 and 2016, respectively.2017. TheOcean Victory,, which was reported as “Assets held for sale” at December 31, 2017 withhad a carrying value of $1.2 million, was sold in January 2018. We also reported theTheOcean Scepter, awas sold in July 2018, subsequent to recognizing an additional impairment loss in the second quarter of 2018. As both rigs had previously been impaired, the aggregate netjack-uppre-tax rig, as held forgain on the sale atof these rigs during the year ended December 31, 2017, based upon management’s2018 was not significant. See Note 3.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
decision to sell the rig after receipt of an unsolicited bid for the rig in November 2017. The sale of the rig has not yet been negotiated; however, management is actively marketing the rig for sale and expects to complete a sale during 2018. TheOcean Spur, which was reported as “Assets held for sale” at December 31, 2016, was sold in 2017.
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, 20172018 and 2016,2017, we capitalized $69.4$243.6 million and $177.6$69.4 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 constructionwork-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 included in our results of operations as “(Gain) loss 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 or upgrades, as well asand other qualifying projects. During the three years ended December 31, 2017, we capitalized interest on qualifying expenditures, primarily related to our rig construction 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:follows (in thousands):
| For the Year Ended December 31, | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | For the Year Ended December 31, | |||||||||||||||||||||
| (In thousands) | 2018 | 2017 | 2016 | |||||||||||||||||||||
Total interest cost including amortization of debt issuance costs | $ | 113,618 | $ | 110,748 | $ | 110,242 | $ | 123,816 | $ | 113,618 | $ | 110,748 | ||||||||||||
Capitalized interest | (90 | ) | (20,814 | ) | (16,308 | ) | (576 | ) | (90 | ) | (20,814 | ) | ||||||||||||
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Total interest expense as reported | $ | 113,528 | $ | 89,934 | $ | 93,934 | $ | 123,240 | $ | 113,528 | $ | 89,934 | ||||||||||||
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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
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
dayrate by rig;
utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates);
the per day operating cost for each rig if active, warm stacked or cold stacked;
the estimated annual cost for rig replacements and/or enhancement programs;
the estimated maintenance, inspection or other reactivation costs associated with a rig returning to work;
salvage value for each rig; and
estimated proceeds that may be received on disposition of each rig.
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we 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 forre-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 onoil-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 2.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 7.8.
Debt Issuance Costs
Deferred costs associated with our credit facilities are presented in “Other assets” in our Consolidated Balance Sheets at December 31, 2018 and 2017 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, 20172018 and 20162017 as a reduction in the related long-term debt and are amortized over the respective terms of the related debt. See Note 9.10.
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 interest related to accrued unrecognized tax positions in “Interest expense, net of amounts capitalized” and recognize penalties associated with uncertain tax positions in “Income tax benefit” in our Consolidated Statements of Operations. Liabilities for uncertain tax positions, including any penalty, 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 15.16.
Treasury Stock
In connection with the vesting of restricted stock units held by certain individuals, we acquired 29,41687,799 and 7,92329,416 shares of our common stock during 20172018 and 2016,2017, respectively (valued at $1.3 million in 2018 and $0.5 million in 2017 and $0.2 million in 2016)2017), in satisfaction of tax withholding obligations that were incurred on the vesting date. See Note 4.5.
Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We account for the purchase of treasury stock using the cost method, which reports the cost of the shares acquired in “Treasury stock” as a deduction from stockholders’ equity in our Consolidated Balance Sheets. We did not repurchase any shares of our outstanding common stock during 2018, 2017 2016 or 2015.2016.
Comprehensive (Loss) Income (Loss)
Comprehensive (loss) income (loss) 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
owners. Comprehensive (loss) income (loss) for the three years ended December 31, 2018, 2017 2016 and 20152016 includes net (loss) income (loss) and unrealized holding gains and losses on marketable securities and financial derivatives designated as cash flow accounting hedges. See Note 10.11.
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 and may also include, when applicable, unrealized gains and losses to record the carrying value of foreign currency forward exchange, or FOREX, contracts not designated as accounting hedges and realized gains and losses from the settlement of such contracts.Operations. The revaluation of assets and liabilities related to foreign income taxes, including deferred tax assets and liabilities and uncertain tax positions, including any penalty, is reported in “Income tax benefit (expense)” in our Consolidated Statements of Operations.
2. Revenue Recognitionfrom Contracts with Customers
The activities that primarily drive the revenue earned from our drilling contracts include (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 recognize revenue from dayrateaccount for these integrated services provided within our drilling contracts as servicesa 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 performed. In connection with such drillingnot distinct within the context of our contracts we may receive fees (on eitherand do not correspond to alump-sum or dayrate basis) for distinct time increment within the mobilization of equipment. We earn these fees as servicescontract term are performedallocated across the single performance obligation and recognized ratably over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each, on a straight-line basis, over the term of the related drilling contractscontract (which is the period we estimate to be benefited from the mobilization activity)corresponding activities and generally ranges from two to 60 months). Straight-line amortization of mobilization revenuesConsideration 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 related costsvariable 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 arere-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 fixedlump-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, (which generally range from twothere is uncertainty as to 60 months)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 consistent withpayable or the timing of net cash flows generatedamount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently. Upon completionwellsite. 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 a drilling contract, we recognize in earnings any demobilization fees receivedreceiving such revenue based on our past experience and costs incurred.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 fixedlump-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 are generally earned as services are performedreceived, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contracts. We defer contract preparation fees received, as well as direct and incremental costs associated with the contract preparation activities and amortize each, on a straight-line basis, over the term of the related drilling contracts (which we estimate to be benefited from the contract preparation activity).contract.
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 fixedlump-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 deferrecord a contract liability for such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basisthem ratably as contract drilling revenue over the periodinitial term of the related drilling contract.
Revenues Related to Reimbursable Expenses. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.
We recordgenerally receive reimbursements receivedfrom our customers for the purchase of supplies, equipment, personnel services and other services provided at thetheir request of our customers in accordance with a drilling contract or agreement, forother 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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Recent Accounting Pronouncements
In October 2016, Such amounts are recognized ratably over the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU,No. 2016-16,Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory, or ASU2016-16. ASU2016-16 amendsperiod within the guidance in Topic 740 with respect tocontract term during which the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. This guidance is effective for interimcorresponding goods and annual reporting periods beginning after December 15, 2017. We have evaluated our historical intra-group transactions for possible impact under the provisions of ASU2016-16. The guidance in ASU2016-16 will be applied effective January 1, 2018 using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard as an adjustment to opening retained earnings with an offset to a deferred income tax liability. We expect to reduce opening retained earnings by approximately $18 million upon adoption of the standard on January 1, 2018.
In August 2016, the FASB issued ASUNo. 2016-15,Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, or ASU2016-15. ASU2016-15 provides specific guidance on eight cash flow classification issues not specifically addressed by GAAP: debt prepayment or debt extinguishment costs; settlement ofzero-coupon debt instruments; contingent consideration payments; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The amendments in ASU2016-15 are effective for interim and annual periods beginning after December 15, 2017. ASU2016-15 should be applied using a retrospective transition method, unless it is impracticable to do so for some of the issues. In such case, the amendments for those issues would be applied prospectively as of the earliest date practicable. We do not expect ASU2016-15 to have a significant impact on the presentation of cash receipts and cash payments within our consolidated statements of cash flows.
In February 2016, the FASB issued ASUNo. 2016-02,Leases (Topic 842), or ASU2016-02, which requires an entity to separate the lease components from thenon-lease components in a contract. The lease componentsservices are to be accounted for under ASU2016-02, which, underconsumed.
Contract Balances
Accounts receivable are recognized when the guidance, may require recognitionright to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances consist primarily of lease assetsdemobilization revenue that we expect to receive and lease liabilities by lessees for most leases and derecognitionis recognized ratably throughout the contract term, but invoiced upon completion of the leased asset and recognition of a net investment indemobilization activities. Once the lease by the lessor. ASU2016-02 also provides for additional disclosure requirements for both lessees and lessors.Non-lease components would be accounted for under ASU2014-09. We have determined that under the new standard, our drilling contracts contain a lease component and therefore we will be required to separately recognize revenues associated with the lease and services components. Additionally, for transactions in which we are considered lessees, we will recognize a lease liability and right of use asset based on our portfolio of leases as of the time of adoption. The guidance of ASU2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of ASU2016-02 is permitted. We expect to adopt ASU2016-02 on January 1, 2019 using the modified retrospective approach. We are currently reviewing the requirements of the accounting standard with regard to arrangements under which we are either the lessor or lessee, to determine the impact of ASU2016-02, including any newly issued guidance, on our financial position, results of operations, cash flows and disclosures contained in the notes to our consolidated financial statements.
In May 2014, the FASB issued ASUNo. 2014-09,Revenue from Contracts with Customers (Topic 606), or ASU2014-09, which is effective for annual reporting periods beginning after December 15, 2017. The new standard supersedes the industry-specific standards that currently exist under GAAP and provides a framework to address revenue recognition issues comprehensively for all contracts with customers regardless of industry-specific or transaction-specific fact patterns. Under the new guidance, companies recognize revenue to depict the transfer of promised goods or services to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. ASU2014-09 provides a five-step analysis of transactions to determine when and howdemobilization revenue is invoiced, the corresponding contract asset is transferred to accounts receivable. Contract assets may also include amounts recognized and requires enhanced disclosures about revenue. When applyingin advance of amounts invoiced due to the new standard, we plan to account for the integrated services provided within our drilling contracts asblending of rates when a single performance obligation composed of a series of distinct time increments, which will be satisfied over time. We will determine the total transaction price for each individual contract by estimating both fixed and variable consideration expected to be earnedhas operating dayrates that increase over the term ofinitial contract term. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the contract. Consideration that does not relate to a distinct good or service, such as mobilization, demobilization, and contract preparation revenue, will be allocated across the singleoverall performance obligation and recognized ratably over the initial term of the contract. All other componentsContract liabilities may also include amounts invoiced in advance of consideration withinamounts recognized due to the blending of rates when a contract includinghas operating dayrates that decrease over the dayrateinitial 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, 2018 | January 1, 2018 | |||||||
Trade receivables | $ | 160,478 | $ | 247,453 | ||||
Current contract assets (1) | 6,832 | 611 | ||||||
Noncurrent contract assets (1) | 2,107 | 2,107 | ||||||
Current contract liabilities (deferred revenue) (1) | (2,803 | ) | (11,371 | ) | ||||
Noncurrent contract liabilities (deferred revenue) (1) | (17,723 | ) | (8,972 | ) | ||||
| (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, 2018. |
Significant changes in the contract assets and the contract liabilities balances during the period are as follows (in thousands):
| Net Contract Balances | ||||
Contract assets at January 1, 2018 | $ | 2,718 | ||
Contract liabilities at January 1, 2018 | (20,343 | ) | ||
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Net balance at January 1, 2018 | (17,625 | ) | ||
Decrease due to amortization of revenue that was included in the beginning contract liability balance | 19,026 | |||
Increase due to cash received, excluding amounts recognized as revenue during the period | (19,353 | ) | ||
Increase due to revenue recognized during the period but contingent on future performance | 7,114 | |||
Decrease due to transfer to receivables during the period | (893 | ) | ||
Adjustments | 144 | |||
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Net balance at December 31, 2018 | $ | (11,587 | ) | |
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Contract assets at December 31, 2018 | $ | 8,939 | ||
Contract liabilities at December 31, 2018 | (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 continuebe 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 $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 year ended December 31, 2018, the amount of amortization of such costs was $67.7 million. 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 periodfuture related to unsatisfied performance obligations as of December 31, 2018 (in thousands):
| For the Years Ending December 31, | ||||||||||||||||||||
| 2019 | 2020 | 2021 | 2022 | Total | ||||||||||||||||
Mobilization and contract preparation revenue | $ | 5,671 | $ | 391 | $ | 511 | $ | 83 | $ | 6,656 | ||||||||||
Capital modification revenue | 10,441 | 4,725 | — | — | 15,166 | |||||||||||||||
Other deferred revenue | — | 7,626 | 9,799 | — | 17,425 | |||||||||||||||
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Total | $ | 16,112 | $ | 12,742 | $ | 10,310 | $ | 83 | $ | 39,247 | ||||||||||
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The revenue included above consists primarily 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 servicesinitial contract term is also included. The amounts are performed.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, 2018. The actual timing of recognition of such amounts may vary due to factors outside of our control. We expecthave applied the disclosure practical expedient in Accounting Standards Codification606-10-50-14A(b) 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.
Impact of Topic 606 on Financial Statement Line Items
Our revenue recognition pattern under Topic 606 is similar to revenue recognition under ASU2014-09 to differ from our current revenuethe previous guidance, except for the recognition pattern only as it relates toof demobilization revenue. Such revenue, which iswas recognized upon completion of a contract under current GAAP, will bethe previous guidance, is now estimated at contract inception and recognized ratably as contract drilling revenue over the initial term of the contract with an offset to a contract asset under Topic 606.
The following tables summarize the new guidance. We plan to adopt ASU2014-09 effective January 1, 2018 using the modified retrospective approach whereby we will record the cumulative effectimpacts of applying the new standard to all outstanding contractsadopting Topic 606 on our selected Consolidated Balance Sheets, Consolidated Statements of Operations and Consolidated Statements of Cash Flows information, as of January 1,and for the year ended December 31, 2018 as(in thousands, except per share data):
| December 31, 2018 | ||||||||||||
| Balances as reported | Adjustments | Balances without adoption of Topic 606 | ||||||||||
Consolidated Balance Sheets | ||||||||||||
Prepaid and other current assets | $ | 163,396 | $ | (3,785 | ) | $ | 159,611 | |||||
Other assets | 65,534 | (2,107 | ) | 63,427 | ||||||||
Deferred tax liability | 104,380 | (795 | ) | 103,585 | ||||||||
Retained earnings | 1,769,415 | (5,097 | ) | 1,764,318 | ||||||||
Consolidated Statements of Operations | ||||||||||||
Contract drilling revenues | $ | 1,059,973 | $ | (3,174 | ) | $ | 1,056,799 | |||||
Income tax benefit | 46,353 | 666 | 47,019 | |||||||||
Loss per share, basic and diluted | (1.31 | ) | (0.02 | ) | (1.33 | ) | ||||||
Consolidated Statements of Cash Flows | ||||||||||||
Cash flow from operating activities: | ||||||||||||
Net loss | $ | (180,272 | ) | $ | (2,508 | ) | $ | (182,780 | ) | |||
Adjustments to reconcile net loss to net cash | ||||||||||||
Deferred tax provision | (75,993 | ) | (666 | ) | (76,659 | ) | ||||||
Contract assets, net | (6,221 | ) | 3,174 | (3,047 | ) | |||||||
3. Asset Impairments
2018 Impairment.During 2018, we recorded an adjustmentimpairment loss of $27.2 million to opening retained earnings.recognize a reduction in fair value of theOcean Scepter. We do not expectestimated 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 consider this adjustmentvaluation approach to be significanta Level 3 fair value measurement due to the level of estimation involved as it will primarily consistthe sale had not yet been completed at the time of our analysis.
At December 31, 2018, we evaluated one drilling rig with indicators of impairment. Based on our assumptions and analysis at that time, we determined that the undiscounted probability-weighted cash flow of the impactrig was in excess of its carrying value. As a result, we concluded that no impairment of the timing difference relatedrig had occurred at December 31, 2018.
As of December 31, 2018, there were 12 rigs in our drilling fleet not previously written down to recognition of demobilization revenuescrap, for affected contracts. Not all contracts include a demobilization provision.
2017 Impairments. During 2017,which there were no current indicators that their carrying amounts may not be recoverable and, thus, were not evaluated for impairment. If market fundamentals in response to continued depressed market conditions for the offshore contract drillingoil and gas industry our expectations thatdeteriorate further or a projected market recovery is not likelyfurther delayed, we may be required to occurrecognize additional impairment losses in the near term, as well as decisions by our management to market certain rigs for sale,future periods.
2017 Impairments.During 2017, we evaluated ten of our drilling rigs with indications that their carrying values may not be recoverable. Based on our analyses, weindicators of impairment and determined that the carrying values of three rigs were impaired including one rig that had previously been impaired in a prior year and two rigs that were classified as held for sale at December 31, 2017. We(we collectively refer to these three rigs as the “2017 Impaired Rigs.” The 2017 Impaired Rigs consist of one ultra-deepwater semisubmersible, one deepwater semisubmersible and onejack-up rig.Rigs).
We estimated the fair value of two of the 2017 Impaired Rigs using an income approach, in whichwhereby the fair value of each rig was estimated based on a calculation of the rig’s discounted future net cash flows over its remaining economic life, whichflows. These calculations utilized significant unobservable inputs, including but not limited to, assumptions related to estimated dayrate revenue, rig utilization, estimated reactivation and regulatory survey costs, as well as estimated proceeds that may be received on ultimate disposition of theeach rig. The fair value of the otherremaining 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; however, the rig has not been sold.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. During the second and fourth quarters of 2017, we
We recorded impairment losses of $71.3 million and $28.0 million, respectively, or an aggregate impairment losslosses of $99.3 million for the year ended December 31, 2017 related to our 2017 Impaired Rigs.
2016 Impairments. During 2016, we evaluated 15 of our drilling rigs with indications that their carrying amounts may not be recoverable. Based on our assumptions and analyses at that time, we determined that the carrying values of eight of these rigs were impaired, including one rig that had been previously impaired in a prior year. We collectively refer to
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
these eight rigs as the “20162016 Impaired Rigs.” The 2016 Impaired Rigs consisted of three ultra-deepwater, three deepwater and twomid-water semisubmersible rigs.
We estimated the fair value of the 2016 Impaired Rigs using an income approach, as described above. 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. During the second quarter of 2016, we recorded an impairment loss of $670.0 million related to our 2016 Impaired Rigs.
2015 Impairments. During 2015, we evaluated 25 of our drilling rigs with indications that their carrying amounts may not be recoverable. Using an undiscounted, projected probability-weighted cash flow analysis, we determined that the carrying value of 17 of these rigs, consisting of two ultra-deepwater, one deepwater and ninemid-water floaters and fivejack-up rigs, were impaired. We collectively refer to these 17 rigs as the “2015 Impaired Rigs.”
We estimated the fair value of 16 of the 2015 Impaired Rigs utilizing a market approach, as described above. We estimated the fair value of the one remaining 2015 Impaired Rig using an income approach, as discussed above. Our fair value estimates are 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. During the first, third and fourth quarters of 2015, we recognized impairment losses of $358.5 million, $2.6 million and $499.4 million, respectively, for an aggregate impairment loss of $860.4 million for the year ended December 31, 2015.
See Notes 1 and 8.
4. Supplemental Financial Information
Consolidated Balance SheetSheets Information
Accounts receivable, net of allowance for bad debts, consists of the following:following (in thousands):
| December 31, | ||||||||||||||||
| 2017 | 2016 | December 31, | ||||||||||||||
| (In thousands) | 2018 | 2017 | ||||||||||||||
Trade receivables | $ | 247,453 | $ | 236,040 | $ | 160,478 | $ | 247,453 | ||||||||
Value added tax receivables | 14,067 | 14,639 | 13,237 | 14,067 | ||||||||||||
Related party receivables | 205 | 149 | 174 | 205 | ||||||||||||
Other | 464 | 1,659 | 190 | 464 | ||||||||||||
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| 262,189 | 252,487 | 174,079 | 262,189 | |||||||||||||
Allowance for bad debts | (5,459 | ) | (5,459 | ) | (5,459 | ) | (5,459 | ) | ||||||||
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Total | $ | 256,730 | $ | 247,028 | $ | 168,620 | $ | 256,730 | ||||||||
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An analysis of the changes in our provision for bad debts for each of the three years ended December 31, 2018, 2017 2016 and 20152016 is as follows:follows (in thousands):
| For the Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands) | ||||||||||||
Allowance for bad debts, beginning of year | $ | 5,459 | $ | 5,724 | $ | 5,724 | ||||||
Bad debt recovery | — | (265 | ) | — | ||||||||
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Allowance for bad debts, end of year | $ | 5,459 | $ | 5,459 | $ | 5,724 | ||||||
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| For the Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
Allowance for bad debts, beginning of year | $ | 5,459 | $ | 5,459 | $ | 5,724 | ||||||
Bad debt recovery | — | — | (265 | ) | ||||||||
|
|
|
|
|
| |||||||
Allowance for bad debts, end of year | $ | 5,459 | $ | 5,459 | $ | 5,459 | ||||||
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|
|
| |||||||
See Note 78 for a discussion of our provision for bad debts and write off ofpolicy regarding uncollectible accounts against the reserve.accounts.
Prepaid expenses and other current assets consist of the following:following (in thousands):
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2018 | 2017 | |||||||||||||
| (In thousands) | ||||||||||||||||
Deferred contract costs | $ | 70,021 | $ | 51,297 | ||||||||||||
Prepaid taxes | 54,412 | 67,212 | ||||||||||||||
Rig spare parts and supplies | $ | 28,383 | $ | 25,343 | 20,256 | 28,383 | ||||||||||
Deferred mobilization costs | 51,297 | 61,488 | ||||||||||||||
Current contract assets | 6,832 | — | ||||||||||||||
Prepaid BOP Lease | 3,873 | 3,873 | 3,873 | 3,873 | ||||||||||||
Prepaid insurance | 3,091 | 3,771 | 2,742 | 3,091 | ||||||||||||
Prepaid taxes | 67,212 | 2,894 | ||||||||||||||
Other | 3,769 | 4,777 | 5,260 | 3,769 | ||||||||||||
|
|
|
| |||||||||||||
Total | $ | 157,625 | $ | 102,146 | $ | 163,396 | $ | 157,625 | ||||||||
|
|
|
| |||||||||||||
During 2016, we recognized an $8.1 million impairment loss related to our rig spare parts and supplies.
Accrued liabilities consist of the following:following (in thousands):
| December 31, | December 31, | |||||||||||||||
| 2017 | 2016 | 2018 | 2017 | |||||||||||||
| (In thousands) | ||||||||||||||||
Payroll and benefits | $ | 47,564 | $ | 46,560 | ||||||||||||
Rig operating expenses | $ | 48,894 | $ | 33,732 | 42,323 | 48,894 | ||||||||||
Payroll and benefits | 46,560 | 45,619 | ||||||||||||||
Deferred revenue | 11,371 | 9,522 | ||||||||||||||
Accrued capital project/upgrade costs | 3,698 | 60,308 | 37,379 | 3,698 | ||||||||||||
Interest payable | 28,234 | 18,365 | 28,234 | 28,234 | ||||||||||||
Personal injury and other claims | 5,699 | 6,424 | 5,544 | 5,699 | ||||||||||||
Deferred revenue | 2,803 | 11,371 | ||||||||||||||
Other | 10,199 | 8,189 | 8,381 | 10,199 | ||||||||||||
|
|
|
| |||||||||||||
Total | $ | 154,655 | $ | 182,159 | $ | 172,228 | $ | 154,655 | ||||||||
|
|
|
| |||||||||||||
“Accrued liabilities” at December 31, 2017, includes $13.6 million in accrued costs related to our 2017 Reduction Plan of which $11.5 million and $2.1 million were reported as “Rig operating expenses” and “Payroll and benefits,” respectively. See Note 14.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Consolidated StatementStatements of Cash Flows Information
Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows:follows (in thousands):
| December 31, | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | December 31, | |||||||||||||||||||||
| (In thousands) | 2018 | 2017 | 2016 | |||||||||||||||||||||
Accrued but unpaid capital expenditures at period end | $ | 3,698 | $ | 60,308 | $ | 84,146 | $ | 37,234 | $ | 3,698 | $ | 60,308 | ||||||||||||
Common stock withheld for payroll tax obligations(1) | 483 | 181 | 236 | 1,301 | 483 | 181 | ||||||||||||||||||
Cash interest payments(2) | 97,096 | 105,987 | 110,412 | 113,063 | 97,096 | 105,987 | ||||||||||||||||||
Cash income taxes paid (refunded), net: | ||||||||||||||||||||||||
Foreign | 9,286 | 43,999 | 48,931 | |||||||||||||||||||||
U.S. federal | — | (31,151 | ) | (21,751 | ) | (7,389 | ) | — | (31,151 | ) | ||||||||||||||
Foreign | 43,999 | 48,931 | 69,697 | |||||||||||||||||||||
State | 94 | 1 | 58 | 2 | 94 | 1 | ||||||||||||||||||
| (1) | Represents the cost of 87,799, 29,416 and 7,923 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of restricted stock units in 2018, 2017 and 2016, respectively. These costs are presented as a deduction from stockholders’ equity in “Treasury stock” in our Consolidated Balance Sheets at December 31, 2018, 2017 and |
| (2) | Interest payments, net of amounts capitalized, were $112.5 million, $97.0 million |
5. Stock-Based Compensation
We have an Equity Incentive Compensation Plan, or Equity Plan, for our officers, independent contractors, employees andnon-employee directors, which is designed to encourage stock ownership by such persons, thereby aligning their interests with those of our stockholders and to permit the payment of performance-based compensation as defined by the Internal Revenue Code of 1986, as amended, or the Code.stockholders. 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;
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
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 CEO, RSUs are not participating securities, and the holders of such awards have no right to receive regular dividends if or when declared.
In March 2016, the FASB issued ASUNo. 2016-09,Compensation — Compensation—Stock Compensation (Topic 718), or ASU2016-09.2016-09, ASU2016-09which requires that all excess tax benefits and tax deficiencies be recognized in the income statement as discrete tax items when share-based awards vest or are settled. The updatesettled and also clarifies the statement of cash flows presentation for certain components of share-based awards and provides for a policy election to either estimate the number of awards expected to vest or account for forfeitures when they occur. We have elected to account for forfeitures of share-based awards in the period in which such forfeitures occur and adopted ASU2016-09 on January 1, 2017 using a modified retrospective approach. The adoption of ASU2016-09 resulted in a $0.6 million reduction in opening retained earnings. The impact to our Consolidated Balance Sheets is as follows:follows (in thousands):
| Retained Earnings | Additional Paid-in Capital | |||||||||||||||
| (In thousands) | Retained Earnings | Additional Paid-in Capital | ||||||||||||||
Balance as of January 1, 2017 before adoption | $ | 1,946,765 | $ | 2,004,514 | $ | 1,946,765 | $ | 2,004,514 | ||||||||
Adjustment for making election to account for forfeitures as they occur | (634 | ) | 634 | (634 | ) | 634 | ||||||||||
|
|
|
| |||||||||||||
Balance as of January 1, 2017 after adoption | $ | 1,946,131 | $ | 2,005,148 | $ | 1,946,131 | $ | 2,005,148 | ||||||||
|
|
|
| |||||||||||||
All other requirements of ASU2016-09, where applicable, have been applied prospectively as of January 1,2017.1, 2017.
Total compensation cost recognized for all awards under the Equity Plan (or its predecessor) for the years ended December 31, 2018, 2017 and 2016 and 2015 was $6.8 million, $8.7 million $7.0 million and $5.7$7.0 million, respectively. Tax benefits recognized for the years ended December 31, 2018, 2017 2016 and 20152016 related thereto were $0.8 million, $2.6 million $2.4 million and $1.9$2.4 million, respectively. As of December 31, 20172018 there was $11.2$8.0 million of total unrecognized compensation cost related tonon-vested awards under the Equity Plan, which we expect to recognize over a weighted average period of two years.
Time-Vesting Awards
SARs. Currently, SARs awarded under the Equity Plan generally vest ratably over a four-year periodimmediately 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, 2018, 2017 2016 and 20152016 was estimated using the Black Scholes pricing model with the following weighted average assumptions:
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | |||||||||||||||||||
Expected life of SARs (in years) | 7 | 7 | 6 | 7 | 7 | 7 | ||||||||||||||||||
Expected volatility | 31.70 | % | 45.79 | % | 55.12 | % | 32.10 | % | 31.70 | % | 45.79 | % | ||||||||||||
Dividend yield | — | .60 | %(1) | 1.70 | % | — | — | .60 | % (1) | |||||||||||||||
Risk free interest rate | 2.09 | % | 1.46 | % | 1.66 | % | 2.56 | % | 2.09 | % | 1.46 | % | ||||||||||||
| (1) | Represents dividend yield related to January 2016 grant of SARs prior to our decision in early 2016 to discontinue paying dividends. |
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The expected life of SARs is based on historical data as is the expected volatility. The dividend yield is based on the current approved regular dividend rate in effect and the current market price at the time of grant. 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, 20172018 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) | Number of Awards | Weighted- Average Exercise Price | Weighted- Average Remaining Contractual Term (Years) | Aggregate Intrinsic Value (In Thousands) | |||||||||||||||||||||||||
Awards outstanding at January 1, 2017 | 1,449,706 | $ | 67.43 | |||||||||||||||||||||||||||||
Awards outstanding at January 1, 2018 | 1,262,114 | $ | 60.16 | |||||||||||||||||||||||||||||
Granted | 66,000 | $ | 14.95 | 40,500 | $ | 18.22 | ||||||||||||||||||||||||||
Exercised | — | (23,000 | ) | $ | 15.89 | |||||||||||||||||||||||||||
Forfeited | 5,240 | $ | 41.88 | (1,100 | ) | $ | 42.41 | |||||||||||||||||||||||||
Expired | 248,352 | $ | 90.95 | (249,432 | ) | $ | 82.65 | |||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||||||
Awards outstanding at December 31, 2017 | 1,262,114 | $ | 60.16 | 4.3 | $ | 272 | ||||||||||||||||||||||||||
Awards outstanding at December 31, 2018 | 1,029,082 | $ | 54.07 | 4.1 | $ | — | ||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||||||
Awards exercisable at December 31, 2017 | 1,230,382 | $ | 60.63 | 4.2 | $ | 272 | ||||||||||||||||||||||||||
Awards exercisable at December 31, 2018 | 1,029,082 | $ | 54.07 | 4.1 | $ | — | ||||||||||||||||||||||||||
|
| |||||||||||||||||||||||||||||||
The weighted-average grant date fair values per share of awards granted during the years ended December 31, 2018, 2017 and 2016 were $7.11, $5.61 and 2015 were $5.61, $9.32, and $14.44, respectively. The total intrinsic value of awards exercised during the years ended December 31, 2018, 2017 and 2016 and 2015 was $0,$0.1 million, $0 and $0, respectively. The total fair value of awards vested during the years ended December 31, 2018, 2017 and 2016 and 2015 was $0.7 million, $1.2 million $2.2 million and $3.6$2.2 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 2018, 2017 2016 and 2015,2016, we granted an aggregate of 135,759, 276,085 183,076 and 153,493183,076 time-vesting RSUs, respectively.One-half of each annual grant will vest two years from the date of grant and the remaining 50% of which 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. The fair value ofnon-participating RSUs granted in 2015 was discounted at a three-year risk-free interest rate of 1.48%, in consideration of thenon-participative rights of the awards. The fair values ofnon-participating RSUs granted in 2017 and 2016 were not discounted as the fair values would have reflected the 2016 suspension of regular dividend payments.
A summary of activity for time-vesting RSUs under the Equity Plan as of December 31, 20172018 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, 2017 | 319,560 | $ | 23.13 | |||||
Granted | 276,085 | $ | 16.37 | |||||
Vested | 68,659 | $ | 25.08 | |||||
Forfeited | 55,697 | $ | 20.76 | |||||
|
| |||||||
Nonvested awards at December 31, 2017 | 471,289 | $ | 19.15 | |||||
|
| |||||||
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| Number of Awards | Weighted- Average Grant Date Fair Value Per Share | |||||||
Nonvested awards at January 1, 2018 | 471,289 | $ | 19.15 | |||||
Granted | 135,759 | $ | 14.58 | |||||
Vested | (131,418 | ) | $ | 23.00 | ||||
Forfeited | (53,571 | ) | $ | 18.55 | ||||
|
| |||||||
Nonvested awards at December 31, 2018 | 422,059 | $ | 16.57 | |||||
|
| |||||||
The total fair value of time-vesting RSUs vested during the yearyears ended December 31, 2018 and 2017 was $1.9 million and $1.1 million.
million, respectively. No time-vesting RSUs vested during the yearsyear ended December 31, 2016 or 2015.2016.
Performance-Vesting Awards
Restricted Stock Units. In 2018, 2017 2016 and 2015,2016, we granted an aggregate of 194,563, 370,616 248,188 and 169,312248,188 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 in 2015, other than to our CEO, was estimated based on the fair market value of our common stock on the date of grant. The fair value ofnon-participating, performance-vesting RSUs granted in 2015 was discounted at a three-year risk-free interest rate of 1.48% in consideration of thenon-participative rights of the awards. The fair value of performance-vesting RSUs granted to our CEO in 2015 was not discounted as such awards are participating securities. The fair values of performance-vesting RSUs granted in 2017 and 2016 were not discounted as the fair values would have reflected the 2016 suspension of regular dividend payments.
A summary of activity for performance-vesting RSUs under the Equity Plan as of December 31, 20172018 and changes during the year then ended is as follows:
| Number of Awards | Weighted- Average Grant Date Fair Value Per Share | Number of Awards | Weighted- Average Grant Date Fair Value Per Share | |||||||||||||
Nonvested awards at January 1, 2017 | 431,706 | $ | 24.55 | |||||||||||||
Nonvested awards at January 1, 2018 | 727,856 | $ | 20.28 | |||||||||||||
Granted | 370,616 | $ | 16.61 | 194,563 | $ | 14.58 | ||||||||||
Vested | 18,876 | $ | 46.64 | (164,271 | ) | $ | 26.21 | |||||||||
Forfeited | 55,590 | $ | 19.95 | (16,175 | ) | $ | 17.78 | |||||||||
|
| |||||||||||||||
Nonvested awards at December 31, 2017 | 727,856 | $ | 20.28 | |||||||||||||
Nonvested awards at December 31, 2018 | 741,973 | $ | 17.53 | |||||||||||||
|
| |||||||||||||||
The total grant date fair value of the performance-vesting RSUs that vested during the years ended December 31, 2018, 2017 and 2016 and 2015 was $2.5 million, $0.3 million $0.4 million and $0.6$0.4 million, respectively.
DIAMOND OFFSHORE DRILLING, INC.6. Earnings (Loss) Per Share
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
A reconciliation of the numerators and the denominators of the basic and dilutedper-share computations follows:follows (in thousands, except per share data):
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands, except per share data) | ||||||||||||
Net income (loss) — basic and diluted (numerator): | $ | 18,346 | $ | (372,503 | ) | $ | (274,285 | ) | ||||
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|
|
|
| |||||||
Weighted-average shares — basic (denominator): | 137,213 | 137,168 | 137,157 | |||||||||
Dilutive effect of stock-based awards | 52 | — | — | |||||||||
|
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|
|
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| |||||||
Weighted-average shares including conversions — diluted (denominator): | 137,265 | 137,168 | 137,157 | |||||||||
|
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|
| |||||||
Earnings (loss) per share: | ||||||||||||
Basic | $ | 0.13 | $ | (2.72 | ) | $ | (2.00 | ) | ||||
|
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|
|
|
| |||||||
Diluted | $ | 0.13 | $ | (2.72 | ) | $ | (2.00 | ) | ||||
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
Net (loss) income – basic and diluted (numerator): | $ | (180,272 | ) | $ | 18,346 | $ | (372,503 | ) | ||||
|
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|
|
|
| |||||||
Weighted-average shares – basic (denominator): | 137,399 | 137,213 | 137,168 | |||||||||
Dilutive effect of stock-based awards | — | 52 | — | |||||||||
|
|
|
|
|
| |||||||
Weighted-average shares including conversions – diluted (denominator): | 137,399 | 137,265 | 137,168 | |||||||||
|
|
|
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| |||||||
(Loss) earnings per share: | ||||||||||||
Basic | $ | (1.31 | ) | $ | 0.13 | $ | (2.72 | ) | ||||
|
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|
|
|
| |||||||
Diluted | $ | (1.31 | ) | $ | 0.13 | $ | (2.72 | ) | ||||
The following table sets forth the share effects of stock-based awards excluded from the computation of earnings (loss) per share, as the inclusion of such potentially dilutive shares would have been antidilutive for the periods presented.presented (in thousands).
| Year Ended December 31, | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | Year Ended December 31, | |||||||||||||||||||||
| (In thousands) | 2018 | 2017 | 2016 | |||||||||||||||||||||
Employee and director: | ||||||||||||||||||||||||
Stock options | — | 7 | 26 | — | — | 7 | ||||||||||||||||||
SARs | 1,315 | 1,505 | 1,553 | 1,133 | 1,315 | 1,505 | ||||||||||||||||||
RSUs | 757 | 704 | 278 | 1,153 | 757 | 704 | ||||||||||||||||||
6. Derivative Financial Instruments7. Marketable Securities
Foreign Currency Forward Exchange Contracts
Our international operations expose us to foreign exchange risk associated withWe report our costs payable in foreign currencies. To manage this risk, in prior years we entered into FOREX contracts for future delivery of Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner. These forward contracts were derivativesinvestments as defined by GAAP.
During the year ended December 31, 2015, we settled FOREX contracts with aggregate a notional value of approximately $91.6 million of which the entire aggregate amount was designated as an accounting hedge. During the year ended December 31, 2015 we did not enter into or settle any FOREX contracts that were not designated as accounting hedges. We did not enter into any FOREX contracts during 2017 or 2016 and there were no FOREX contracts outstanding at December 31, 2017 or 2016.
During the year ended December 31, 2015, we recognized an aggregate loss of $8.4 million related to our FOREX contracts designated as hedging instruments, which was reported in Contract drilling expense in our Consolidated Statements of Operations.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
The following table presents the amounts recognizedcurrent assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations. See Note 8.
Our investments in marketable securities are classified as available for sale and Consolidated Statements of Operations related to our derivative financial instruments designatedare summarized as cash flow hedges for the year ended December 31, 2015.follows (in thousands):
| ||||
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| ||||
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| ||||
| December 31, 2018 | ||||||||||||
| Amortized Cost | Unrealized Gain | Market Value | ||||||||||
U.S. Treasury bills (due within one year) | $ | 299,813 | $ | 36 | $ | 299,849 | ||||||
During the year ended December 31, 2015, we did not reclassify any amountsProceeds from AOCGL due to the probabilitymaturities of an underlying forecasted transaction not occurring.U.S. Treasury bills were $1.6 billion in 2018. There were no sales of U.S. Treasury bills during 2018.
8. 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, including mortgage-backed securities. We generally place our excess cash investments in U.S.
government backed short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. 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 and government-owned oil companies. Based on our current customer base and the geographic areas in which we operate, as well as the number of rigs currently working in a geographic area,these areas, we do not believe that we have any significant concentrations of credit risk at December 31, 2017.2018.
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. We record a provision for bad debts on acase-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible and, historically,collectible. Historically, losses on our trade receivables have been infrequent occurrences.
In December 2013, we entered into a settlement with Niko with respect to certain obligations under dayrate contracts for theOcean Monarch andOcean Lexington, whereby we would receive an aggregate of $80.0 million. From December
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
2013 until Niko’s default on the agreement, we received $49.0 million from Niko. Commencing in 2015, we filed a lawsuit against Niko in a U.S. court and a Canadian court, both of which granted judgments against Niko. On October 18, 2016, we executed a final settlement agreement with Niko, or which we refer to as the 2016 Agreement. Under the 2016 Agreement, Niko paid us a cash settlement amount of $3.0 million, agreed to make future payments to us equal to 20% of amounts to be retained by Niko pursuant to a waterfall distribution under their credit facility and assigned to us Niko’s interest in potential contingent payments related to the sale of five Indonesian production sharing contracts. We plan to recognize revenue from these amounts as funds are received due to the uncertainty regarding their timing and collection. As of December 31, 2017, the amount outstanding to us under the agreement was $28.0 million.
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 1 assets include short-term investments such as money market funds, U.S. Treasury |
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 2 assets and liabilities may include residential mortgage-backed securities, corporate bonds purchased in a private placement offering andover-the-counter foreign currency forward exchange contracts. | |
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. Our Level 3 assets at December 31, 2017 | |
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Market conditions could cause an instrument to be reclassified among Levels 1, 2 and 3. Our policy regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the transfers as having occurred at the beginning of the reporting period. There were no transfers between fair value levels during the years ended December 31, 2017 and 2016.
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 impairment charges related to certain of our drilling rigs, and related spare parts and supplies, which were measured at fair value on a nonrecurring basis in 20172018 and 2016, respectively,2017 and have presented the aggregate loss in “Impairment of assets” in our Consolidated Statements of Operations for the years ended December 31, 20172018 and 2016.2017.
Assets and liabilities measured at fair value are summarized below.below (in thousands).
| December 31, 2017 | ||||||||||||||||||||||||||||||||||||||||
| Fair Value Measurements Using | Assets at Fair Value | Total Losses for Year Ended(1) | December 31, 2018 | |||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Fair Value Measurements Using | |||||||||||||||||||||||||||||||||||||
| (In thousands) | Level 1 | Level 2 | Level 3 | Assets at Fair Value | Total Losses for Year Ended(1) | |||||||||||||||||||||||||||||||||||
Recurring fair value measurements: | ||||||||||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||||||
Short-term investments | $ | 358,019 | $ | — | $ | — | $ | 358,019 | $ | 435,671 | $ | — | $ | — | $ | 435,671 | ||||||||||||||||||||||||
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Nonrecurring fair value measurements: | ||||||||||||||||||||||||||||||||||||||||
Assets: | ||||||||||||||||||||||||||||||||||||||||
Impaired assets(2) | $ | — | $ | — | $ | 97,261 | $ | 97,261 | $ | 99,313 | ||||||||||||||||||||||||||||||
Impaired assets | $ | — | $ | — | $ | — | $ | — | $ | 27,225 | ||||||||||||||||||||||||||||||
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| (1) | Represents impairment |
| December 31, 2017 | ||||||||||||||||||||
| Fair Value Measurements Using | ||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Assets at Fair Value | Total Losses for Year Ended(1) | ||||||||||||||||
Recurring fair value measurements: | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Short-term investments | $ | 358,019 | $ | — | $ | — | $ | 358,019 | ||||||||||||
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Nonrecurring fair value measurements: | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Impaired assets (2) | $ | — | $ | — | $ | 97,261 | $ | 97,261 | $ | 99,313 | ||||||||||
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| (1) | Represents aggregate impairment loss of $99.3 million recognized during 2017 |
| (2) | Represents the total book value as of December 31, 2017 of |
3.
| December 31, 2016 | ||||||||||||||||||||
| Fair Value Measurements Using | Assets at Fair Value | Total Losses for Year Ended(1) | ||||||||||||||||||
| Level 1 | Level 2 | Level 3 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
Recurring fair value measurements: | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Short-term investments | $ | 146,360 | $ | — | $ | — | $ | 146,360 | ||||||||||||
Mortgage-backed securities | — | 35 | — | 35 | ||||||||||||||||
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Total assets | $ | 146,360 | $ | 35 | $ | — | $ | 146,395 | ||||||||||||
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Nonrecurring fair value measurements: | ||||||||||||||||||||
Assets: | ||||||||||||||||||||
Impaired assets(2) | $ | — | $ | — | $ | 69,153 | $ | 69,153 | $ | 678,145 | ||||||||||
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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. |
We consider our senior notes, including current maturities, to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service
at December 31, 20172018 and 2016.2017. 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 a10-day window of the report date. Fair values and related carrying values of our senior notes (see Note 9)10) are shown below.below (in millions).
| December 31, 2017 | December 31, 2016 | December 31, 2018 | December 31, 2017 | |||||||||||||||||||||||||||||
| Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||||||||||||||
| (In millions) | ||||||||||||||||||||||||||||||||
5.875% Senior Notes due 2019 | $ | — | $ | — | $ | 518.6 | $ | 499.8 | ||||||||||||||||||||||||
3.45% Senior Notes due 2023 | 223.1 | 249.4 | 215.0 | 249.3 | $ | 185.0 | $ | 249.5 | $ | 223.1 | $ | 249.4 | ||||||||||||||||||||
7.875% Senior Notes due 2025 | 523.1 | 496.5 | — | — | 415.0 | 496.8 | 523.1 | 496.5 | ||||||||||||||||||||||||
5.70% Senior Notes due 2039 | 405.0 | 497.2 | 392.5 | 497.1 | 305.0 | 497.2 | 405.0 | 497.2 | ||||||||||||||||||||||||
4.875% Senior Notes due 2043 | 547.5 | 748.9 | 532.7 | 748.9 | 416.3 | 748.9 | 547.5 | 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.
9. Drilling and Other Property and Equipment
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:follows (in thousands):
| December 31, | ||||||||||||||||
| 2017 | 2016 | December 31, | ||||||||||||||
| (In thousands) | 2018 | 2017 | ||||||||||||||
Drilling rigs and equipment | $ | 7,971,406 | $ | 8,950,385 | $ | 8,210,824 | $ | 7,971,406 | ||||||||
Land and buildings | 63,309 | 64,449 | 63,757 | 63,309 | ||||||||||||
Office equipment and other | 82,691 | 73,108 | 91,819 | 82,691 | ||||||||||||
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| |||||||||||||
Cost | 8,177,406 | 9,087,942 | 8,366,400 | 8,117,406 | ||||||||||||
Less accumulated depreciation | (2,855,765 | ) | (3,361,007 | ) | (3,182,178 | ) | (2,855,765 | ) | ||||||||
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| |||||||||||||
Drilling and other property and equipment, net | $ | 5,261,641 | $ | 5,726,935 | $ | 5,184,222 | $ | 5,261,641 | ||||||||
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During the years ended December 31, 20172018 and 2016,2017, we recognized impairment losses of $99.3$27.2 million and $670.0$99.3 million, respectively. See Note 2.3.
10. Credit Agreements and Senior Notes
Credit AgreementAgreements
We haveIn September 2012, we entered into a syndicated5-year revolving credit agreement, with Wells Fargo Bank, National Association,which, as administrative agent and swingline lender, that providesamended as of August 18, 2016, provided for a $1.5 billion senior unsecured revolving credit facility for general corporate purposes,purposes. On October 2, 2018, we entered into Amendment No. 6 and Consent to Credit Agreement and Successor Agency Agreement, or the Amendment, which weamended our5-year revolving credit agreement, dated as of September 28, 2012, as amended (we refer to such credit agreement, as amended by the Amendment, as the $325 Million Credit Agreement. Our Credit Agreement matures on October 22, 2020, except for $40Facility). Among other things, the Amendment reduced the aggregate principal amount of commitments under the credit facility to $325.0 million, of which $40.0 million of the commitments that mature on March 17, 2019, and $60$60.0 million of the commitments that mature on October 22, 2019. In addition, we also have the option to increase the revolving commitments under the Credit Agreement by up to an additional $5002019 and $225.0 million from time to time, upon receipt of additional commitments from new or existing lenders, and to request one additionalone-year extension of the maturity date.commitments mature on October 22, 2020. The entire amount of the facility$325 Million Credit Facility is available, subject to its terms, for revolving loans. Up
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 senior5-year revolving credit agreement with a syndicate of lenders and Wells Fargo Bank, National Association, as administrative agent (we refer to $250such credit agreement as the $950 Million Credit Facility). The maximum amount of borrowings available under the $950 Million Credit Facility is $950.0 million of the facilityand may be used for the issuancegeneral 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 performance or other standby letters$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 upa portion of such amount is available for loans to $100 million may be usedDODI, 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.
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 $325 Million Credit Facility.
We refer to the $325 Million Credit Facility and $950 Million Credit Facility collectively as the Credit Agreements. At December 31, 2018, we had no borrowings outstanding under the Credit Agreements. At February 8, 2019, we had no borrowings outstanding under the Credit Agreements and an aggregate $1.275 billion available under the Credit Agreements, subject to their respective terms.
Covenants
The $325 Million Credit Facility contains customary covenants, including, but not limited to, maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the $325 Million 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 (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 of not less than 80% at the end of each fiscal quarter and (iii) maintenance of a ratio 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 theOcean 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 $325 Million Credit Facility plus certain other indebtedness of DFAC and certain foreign guarantors, as specified in the $950 Million Credit Facility, of not less than 3:00 to 1:00 at the end of each fiscal quarter.
The $950 Million Credit Facility also contains additional covenants generally applicable to DODI and its subsidiaries that we consider usual and customary for swingline loans.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, 2018, we were in compliance with all covenant requirements under the Credit Agreements.
Interest Rates and Fees
Revolving loans under the Credit AgreementAgreements 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. Basedloan (determined based on our current credit ratings, the applicable interest rate for ABRratings). Swingline loans under the $950 Million Credit Agreement is 0.25% over the greater of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the dailyone-month Eurodollar Rate plus 1.00%. The applicable interest rate for Eurodollar loans under the Credit Agreement is currently 1.25% over British Bankers’ Association LIBOR.
Swingline loansFacility bear interest, at our option, at a rate per annum equal to (i) the ABR plus the applicable interest margin for ABR loans or (ii) the dailyone-month Eurodollar Rate plus the applicable interest margin for Eurodollar loans.
Under the Credit Agreement,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 Agreement of 0.20% per annumAgreements 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, currently 0.625% per annum for performance letters ofissued.
The following summarizes the interest rate margins and fees payable under the Credit Agreements, based on our current long-term credit and
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)ratings:
$325 Million 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 dailyone-month Eurodollar Rate plus 1.00% | 3.00% over the greater of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the dailyone-month Eurodollar Rate plus 1.00% | ||
Eurodollar | 1.25% over specified LIBOR | 4.00% 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 dailyone-month Eurodollar Rate plus the applicable interest margin for Eurodollar loans | ||
Letter of credit participation fees: | ||||
Performance letters of credit | N/A | 2.00% per annum | ||
All other letters of credit | N/A | 4.00% per annum | ||
Commitment fee on unused commitments under credit agreement | 0.20% per annum | 0.70% per annum |
1.25% per annum for all other letters of credit. Favorable changes in our current credit ratings could lower the interest rate margins and fees that we pay under the Credit Agreement;Agreements; however, current interest rates and fees under the $325 Million Credit Facility will apply should there be any further downgrade in our credit ratings. A downgrade in our credit ratings would increase the interest rate margins and fees that we pay under the $950 Million Credit Facility.
The Credit Agreement contains customary covenants, including, but not limited to, maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the Credit Agreement, 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. As of December 31, 2017, we were in compliance with all covenant requirements.
Senior Notes
At December 31, 2017, we had no borrowings outstanding under the Credit Agreement. At February 9, 2018, we had no borrowings outstanding under the Credit Agreement and an additional $1.5 billion available. At December 31, 2016, we had $104.2 million in borrowings outstanding under the Credit Agreement that bore interest at a weighted average interest rate of 1.9%.
Senior Notes
At December 31, 2017, our senior notes were comprised of the following debt issues:issues (dollars in millions):
Semiannual Interest Payment Dates | ||||||||||||||||||||||
| Principal Amount | Interest Rate | Semiannual Interest Payment Dates | Interest Rate | |||||||||||||||||||
Debt Issue | (In millions) | Maturity Date | Coupon | Effective | Principal Amount | Maturity Date | Coupon | Effective | ||||||||||||||
3.45% Senior Notes due 2023 | $ | 250.0 | November 1, 2023 | 3.45% | 3.50% | May 1 and November 1 | $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 | $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 | $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 | $750.0 | November 1, 2043 | 4.875% | 4.89% | May 1 and November 1 | |||||||||||
At December 31, 20172018 and 2016,2017, the carrying value of our senior notes, net of unamortized discount and debt issuance costs, was as follows:follows (in thousands):
| December 31, | ||||||||
| 2017 | 2016 | |||||||
| (In thousands) | ||||||||
5.875% Senior Notes due 2019 | $ | — | $ | 498,679 | ||||
3.45% Senior Notes due 2023 | 248,162 | 247,879 | ||||||
7.875% Senior Notes due 2025 | 489,420 | — | ||||||
5.70% Senior Notes due 2039 | 492,971 | 492,812 | ||||||
4.875% Senior Notes due 2043 | 741,672 | 741,514 | ||||||
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| |||||
Total senior notes, net | $ | 1,972,225 | $ | 1,980,884 | ||||
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| |||||
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| December 31, | ||||||||
| 2018 | 2017 | |||||||
3.45% Senior Notes due 2023 | $ | 248,455 | $ | 248,162 | ||||
7.875% Senior Notes due 2025 | 490,491 | 489,420 | ||||||
5.70% Senior Notes due 2039 | 493,139 | 492,971 | ||||||
4.875% Senior Notes due 2043 | 741,837 | 741,672 | ||||||
|
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| |||||
Total senior notes, net | $ | 1,973,922 | $ | 1,972,225 | ||||
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As of December 31, 2017,2018, the aggregate annual maturity of our senior notes, excluding net unamortized discounts and debt issuance costs of $8.1$7.5 million and $19.7$18.5 million, respectively, was as follows:follows (in thousands):
| Aggregate Principal Amount | ||||||||
| (In thousands) | Aggregate Principal Amount | |||||||
Year Ending December 31, | ||||||||
2018 | $ | — | ||||||
2019 | — | $ | — | |||||
2020 | — | — | ||||||
2021 | — | — | ||||||
2022 | — | — | ||||||
2023 | 250,000 | |||||||
Thereafter | 2,000,000 | 1,750,000 | ||||||
|
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Total maturities of senior notes | $ | 2,000,000 | $ | 2,000,000 | ||||
|
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Senior Notes Due 2019Redemption. 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 deducting underwritingdeduction of underwriter discounts, commissions and estimated expenses. The 2025 Notes bear interest at 7.875% per year and mature on August 15, 2025. Interest on the 2025 Notes is payable semiannually in arrears on February 15 and August 15 of each year, beginning February 15, 2018. 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 Diamond Offshore Drilling, Inc.,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. The 2025 Notes 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 the governing indenture.
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 Diamond Offshore Drilling, Inc.,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 Diamond Offshore Drilling, Inc.DODI, and rank equally in right of payment to all of its existing and future unsecured and unsubordinated
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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.
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.
11. Other Comprehensive Income (Loss)
The following table sets forth the components of “Other comprehensive gain (loss)” and the related income tax effects thereon for the three years ended December 31, 20172018 and the cumulative balances in “Accumulated other comprehensive gain (loss),” or AOCGL, by component at December 31, 2018, 2017 and 2016 and 2015.(in thousands).
| Unrealized Gain (Loss) on | Total AOCGL | |||||||||||
| Derivative Financial Instruments | Marketable Securities | |||||||||||
| (In thousands) | ||||||||||||
Balance at January 1, 2015 | (3,504 | ) | (101 | ) | (3,605 | ) | ||||||
Change in other comprehensive loss before reclassifications, after tax of $846 and $(1) | (1,574 | ) | (4,940 | ) | (6,514 | ) | ||||||
Reclassification adjustments for items included in Net Loss, after tax of $(2,737) and $0 | 5,084 | — | 5,084 | |||||||||
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| |||||||
Total other comprehensive income (loss) | 3,510 | (4,940 | ) | (1,430 | ) | |||||||
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| |||||||
Balance at December 31, 2015 | 6 | (5,041 | ) | (5,035 | ) | |||||||
Change in other comprehensive loss before reclassifications, after tax of $0 and $2 | — | (6,559 | ) | (6,559 | ) | |||||||
Reclassification adjustments for items included in Net Loss, after tax of $3 and $0 | (5 | ) | 11,600 | 11,595 | ||||||||
|
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| |||||||
Total other comprehensive (loss) income | (5 | ) | 5,041 | 5,036 | ||||||||
|
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|
| |||||||
Balance at December 31, 2016 | 1 | — | 1 | |||||||||
Reclassification adjustments for items included in Net Loss, after tax of $2 and $0 | (6 | ) | — | (6 | ) | |||||||
|
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|
|
| |||||||
Total other comprehensive loss | (6 | ) | — | (6 | ) | |||||||
|
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| |||||||
Balance at December 31, 2017 | $ | (5 | ) | $ | — | $ | (5 | ) | ||||
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| |||||||
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| Unrealized Gain (Loss) on | ||||||||||||
| Derivative Financial Instruments | Marketable Securities | Total AOCGL | ||||||||||
Balance at January 1, 2016 | 6 | (5,041 | ) | (5,035 | ) | |||||||
Change in other comprehensive loss before reclassifications, after tax of $0 and $2 | — | (6,559 | ) | (6,559 | ) | |||||||
Reclassification adjustments for items included in Net Loss, after tax of $3 and $0 | (5 | ) | 11,600 | 11,595 | ||||||||
|
|
|
|
|
| |||||||
Total other comprehensive (loss) income | (5 | ) | 5,041 | 5,036 | ||||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2016 | 1 | — | 1 | |||||||||
Reclassification adjustments for items included in Net Loss, after tax of $2 and $0 | (6 | ) | — | (6 | ) | |||||||
|
|
|
|
|
| |||||||
Total other comprehensive loss | (6 | ) | — | (6 | ) | |||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2017 | (5 | ) | — | (5 | ) | |||||||
Change in other comprehensive gain before reclassifications, after tax of $0 and $(8) | — | 69 | 69 | |||||||||
Reclassification adjustments for items included in Net Loss, after tax of $2 and $4 | (6 | ) | (37 | ) | (43 | ) | ||||||
|
|
|
|
|
| |||||||
Total other comprehensive (loss) income | (6 | ) | 32 | 26 | ||||||||
|
|
|
|
|
| |||||||
Balance at December 31, 2018 | $ | (11 | ) | $ | 32 | $ | 21 | |||||
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| |||||||
The following table presents the line items in our Consolidated Statements of Operations affected by reclassification adjustments out of AOCGL.AOCGL (in thousands).
Major Components of AOCGL | Year Ended December 31, | Consolidated Statements of | Year Ended December 31, | Consolidated Statements of Operations Line Items | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||
Derivative financial instruments: | ||||||||||||||||||||||||||||
Unrealized loss on FOREX contracts | $ | — | $ | — | $ | 7,829 | Contract drilling, excluding depreciation | |||||||||||||||||||||
Unrealized gain on Treasury Lock Agreements | (8 | ) | (8 | ) | (8 | ) | Interest expense | $ | (8 | ) | $ | (8 | ) | $ | (8 | ) | Interest expense | |||||||||||
| 2 | 3 | (2,737 | ) | Income tax expense (benefit) | 2 | 2 | 3 | Income tax expense (benefit) | ||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||
| $ | (6 | ) | $ | (5 | ) | $ | 5,084 | Net of tax | $ | (6 | ) | $ | (6 | ) | $ | (5 | ) | Net of tax | ||||||||||
|
|
|
|
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| |||||||||||||||||||||||
Marketable securities: | ||||||||||||||||||||||||||||
Unrealized loss on marketable securities | $ | — | $ | 11,600 | $ | — | Other, net | |||||||||||||||||||||
Unrealized (gain) loss on marketable securities | $ | (41 | ) | $ | — | $ | 11,600 | Other, net | ||||||||||||||||||||
| — | — | — | Income tax expense | 4 | — | — | Income tax expense | |||||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||||||
| $ | — | $ | 11,600 | $ | — | Net of tax | $ | (37 | ) | $ | — | $ | 11,600 | Net of tax | ||||||||||||||
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| |||||||||||||||||||||||
12. 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.
Patent Litigation. On August 30, 2017, an affiliate of Transocean Ltd., or Transocean, an offshore drilling contractor, filed a lawsuit against us and one of our subsidiaries in the United States District Court for the Southern District of Texas, alleging that we infringed certain United States patents previously owned by Transocean or its affiliates or employees pertaining to certain dual-activity drilling operations. The lawsuit allegesalleged that we infringed the patents by the unauthorized sale, offer for sale, and importation and use of four of our drilling rigs (Ocean BlackhawkBlackHawk,Ocean BlackHornet,Ocean BlackRhino andOcean BlackLion). On June 1, 2018, we filed petitions with the Patent Trial and is seeking unspecified monetary damages. TheAppeal Board to challenge the validity of each of the Transocean patents which expiredthrough an administrative process referred to as anInter Partes Review. In September 2018, we reached an agreement with Transocean to settle the lawsuit and theInter Partes Review on mutually agreeable terms, and both proceedings were dismissed in May 2016, do not apply to drilling activities outsideOctober 2018. We expensed the United States or to activities that occurred aftersettlement charge during the expiration of the patents. We are unable to estimate our potential exposure, if any, to the Transocean lawsuit at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.year ended December 31, 2018.
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
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.
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 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, which renewed effective May 1, 2017,2018, 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 $10.0 million for the first occurrence, with no aggregate deductible, 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 deductibledeductibles for personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico isare $25.0 million for the first occurrence, with no aggregate deductible, 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.
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, 20172018, our estimated liability for personal injury claims was $30.9$27.9 million, of which $5.2 million and $25.7$22.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 20162017, our estimated liability for personal injury claims was $32.9$30.9 million, of which $6.1$5.2 million and $26.8$25.7 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.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Purchase Obligations. At December 31, 2017,2018, 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.
Operating Leases.We lease office and yard facilities, housing,non-rig office equipment and vehicles under operating leases, which expire at various times through the year 2022. Total rent expense amounted to $3.1 million, $3.9 million $5.5 million and $7.8$5.5 million for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. Future minimum rental payments under leases are approximately $1.7$2.1 million and $0.5$0.8 million for 20182019 and 2019,2020, respectively, and an aggregate of $0.3 million for the years 20202021 through 2022.
In addition, we lease certain blowout preventer equipment, or BOP, and related well control equipment underten-year operating leases. See Note 12.13.
Letters of Credit and Other.We were contingently liable as of December 31, 20172018 in the amount of $20.4$25.7 million under certain customs, performance, supersedeas, tax bid and customsVAT bonds and letters of credit. Agreements relating to approximately $14.8$17.1 million of supersedeas,customs and tax and customs bonds can require collateral at any time. As of December 31, 2017,2018, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.
13. Sale and Leaseback Transactions
In February 2016, we entered into aten-year agreement with a subsidiary of GE Oil & Gas, or GE, to provide services with respect to certain blowout preventer and related well control equipment, or Well Control Equipment, on our four drillships. Such services include management of maintenance, certification and reliability with respect to such equipment.
In connection with the contractual services agreement with GE, we completed four sale and leaseback transactions with another GE affiliate during 2016 with respect to the Well Control Equipment on our four drillships. As a result of these transactions, we received an aggregate of $210.0 million in proceeds from the sale of the Well Control Equipment, which was less than the carrying value of the equipment. The resulting difference was recorded as prepaid rent with no gain or loss recognized on the transactions. The prepaid rent will be amortized over the respective terms of the operating leases. Future commitments under the operating leases and contractual services agreements are estimated to be approximately $65.0 million per year or an estimated $550.0
$485.0 million in the aggregate over the remaining term of the agreements. During the years ended December 31, 2018, 2017 and 2016, we recognized $65.1 million, $61.7 million and $34.0 million, respectively, in aggregate expense related to the Well Control Equipment leases and contractual services agreements.
14. 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 personnel, internal auditing, accounting, and cash management services, in addition to advice and assistance with respect to preparation of tax returns and obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i) allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews personnel actually providing such services and (ii) allout-of-pocket expenses related to the provision of such services. The Services
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 by Loews under the Services Agreement unless due to the gross negligence or willful misconduct of Loews. We were charged $1.0$0.6 million, $1.0 million and $1.3$1.0 million by Loews for these support functions during the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively.
Transactions with Other Related Parties.We hire marine vessels and helicopter transportation services at the prevailing market rate from subsidiaries of SEACOR Holdings Inc., SEACOR Marine Holdings Inc. and Era Group Inc. We paid $47,000, $0.7$0.4 million, $0.1 million and $6.0$0.7 million for the hire of such vessels and such services during the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively. A member of our Board of Directors serves as the Chief Executive Officer and Executive Chairman of the Board of Directors of SEACOR Holdings Inc., theNon-Executive Chairman of the Board of Directors of SEACOR Marine Holdings Inc. and theNon-Executive Chairman of the Board of Directors of Era Group Inc.
15. Restructuring and Separation Costs
In late 2017, in response to expectations that a recovery of the offshore drilling market willwould 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, also referred to as the 2017 Reduction Plan. As of December 31, 2017, appropriate communications had been made to substantially all impacted personnel, and weWe incurred $14.1 million in restructuring and employee separation related costs during 2017. Accrued2017, 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 2017 Reduction Plan and paid $12.4 million in previously accrued costs.
At December 31, 2018, accrued costs associated with the 2017 Reduction Plan were $13.6$1.5 million, as of December 31, 2017,all of which $11.5is payable in 2019.
16. Income Taxes
Effective January 1, 2018, we adopted ASU2016-16, which required us to record the income tax consequences of two historical intra-entity transfers of rigs, for which previous accounting guidance precluded us from recognizing such income tax effects. We adopted the new accounting guidance using the modified retrospective approach, whereby we recorded the $17.4 million is relatedcumulative effect of applying the new standard as an adjustment to the termination of our Brazilian agency agreement, which is expectedopening retained earnings with an offset to be paid in the first quarter of 2018, and $2.1 million is related to severance payments to two former executives, payable over a two year period.deferred income tax liability.
During 2015,Additionally, in response to depressed conditions in the offshore drilling market at that time, we reviewed our cost and organization structure, and, as a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, also referred to as the 2015 Reduction Plan. During 2015, we paid $9.8 million in restructuring and employee separation related costs to impacted personnel.
On December 22, 2017, the Presidentinterpretation of the United StatesTax Reform Act, which was signed into law the Tax Cuts and Jobs Act, commonly referred to as the Tax Reform Act. The Tax Reform Act amended the Internal Revenue Code in several areas that had a direct and immediate effect on our results of operations and statement of financial position as of and for the year endedlate December 31, 2017, including, among other items, aone-time mandatory deemed repatriation of accumulated earnings of our foreign subsidiaries as of December 31, 2017 and a reduction in the U.S corporate income tax rate from 35% to 21% beginning in January 2018. As a result of these changes, we recorded a provisional net tax expense of $1.1 million during the fourth quarter of 2017, consisting
which included a charge relating to theone-time mandatory repatriation of previously deferred earnings of certainnon-U.S. subsidiaries that are owned either wholly or partially by our U.S. subsidiaries, inclusive of the utilization of certain tax attributes offset by a provisional liability for uncertain tax positions related to such attributes. Due to the timing of the enactment of the Tax Reform Act, there has been and continues to be a significant amount of uncertainty as to the appropriate application of a number of the underlying provisions, pending further guidance and clarification from the relevant authorities. In 2018, the U.S. Department of the Treasury and Internal Revenue Service, or IRS, issued additional guidance which we believe clarified certain of our tax positions taken in 2017 and, consequently, during the first quarter of 2018, we reversed a $43.3 million liability for an uncertain tax position related to the deemed repatriation of accumulatednon-U.S. earnings. During the fourth quarter of 2018, the IRS issued further proposed regulations that may impact the utilization of certain tax attributes used to offset the deemed mandatory repatriation, for which we recorded an uncertain tax position in the amount of $20.1 million. Consequently, our revised net tax benefit associated with the Tax Reform Act is $20.3 million, which now consists of (i) a $75.4$52.2 million charge relating to theone-time mandatory repatriation of previously deferred earnings of certainnon-US subsidiaries that are owned either wholly or partially by our U.S. subsidiaries, inclusive of the utilization of certain tax attributes offset by a provisional liability for uncertain tax positions related to such attributes and (ii) a $74.3$72.5 million credit resulting from the remeasurementdetermination andre-measurement of our net U.S. deferred tax liabilities at the lower corporate income tax rate.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Also on December 22, 2017, theThe Securities and Exchange Commission issuedCommission’s Staff Accounting Bulletin No. 118, which allowsor SAB 118, allowed companies to report the income tax effects of the Tax Reform Act as a provisional amount based on a reasonable estimate, which would be subject to adjustment during a reasonable measurement period, not to exceed twelve months, until the accounting and analysis under ASCTopic 740 is complete. Due to the timing of the enactment of the Tax Reform Act, there continues to be a significant amount of uncertainty as to the appropriate application of a number of the underlying provisions, pendingAlthough further guidance and clarification from the relevant authorities. We willauthorities is expected to continue to monitor developmentsinto 2019, in this area and adjustaccordance with SAB 118’s twelve month measurement period, we have completed our estimates throughoutanalysis of the year in 2018, as and if necessary, as additional guidance and clarification becomes available. Our provisional estimate of theincome tax effect of the Tax Reform Act is a net charge of $1.1 million as discussed above. We are still in the process of evaluating our estimate as it relates to the tax effect ofincluding (i) the mandatory, deemed repatriation aspect of the Tax Reform Act, (ii) the amount of deferred tax assets and liabilities subject to the income tax rate change from 35% to 21%, and (iii) the ability to more likely than not realize the benefit of deferred tax assets, including net operating losses and foreign tax credits. Any adjustmentscredits, and (iv) our position with regard to these provisional amounts will be reported asthe permanent reinvestment ofnon-U.S. earnings, and, consequently, we recorded a componentnet tax benefit of “Tax expense (benefit)”$21.0 million in the reporting period in which such adjustments are determined, which will be no later than the fourth quarter of 2018.
Our income tax expense is a function of the mix between our domestic and internationalpre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC. We currently intend to indefinitely reinvest theThe deferred foreign earnings of DFAC and its foreignour international subsidiaries were deemed to finance foreign activities. Except to the extent of the U.S. tax providedbe repatriated under the Tax Reform Act, or other required U.S.and our management has determined that we will no longer permanently reinvest foreign earnings. As of December 2018, we recorded $0.5 million for the withholding income tax provision, weimpact associated with the potential distribution of DFAC’s earnings. We have not provided income tax on the outside basis difference of this subsidiary nor provided forour international subsidiaries as management does not intend to dispose of these subsidiaries and structuring alternatives exist to mitigate any withholding or other tax that may be applicablepotential liability should a future distribution be made from any unremitted earnings of this subsidiary. Itdisposition take place. The potential unrecorded tax liability associated with the outside basis difference is not practical to estimate this potential liability.approximately $116 million.
The components of income tax expense (benefit) are as follows:follows (in thousands):
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands) | ||||||||||||
Federal — current | $ | 6,994 | $ | 230 | $ | 63,223 | ||||||
State — current | 95 | (60 | ) | 93 | ||||||||
Foreign — current | 25,252 | 10,297 | 71,655 | |||||||||
|
|
|
|
|
| |||||||
Total current | 32,341 | 10,467 | 134,971 | |||||||||
|
|
|
|
|
| |||||||
Federal — deferred | (85,066 | ) | (108,274 | ) | (245,045 | ) | ||||||
Foreign — deferred | 12,939 | 2,011 | 3,011 | |||||||||
|
|
|
|
|
| |||||||
Total deferred | (72,127 | ) | (106,263 | ) | (242,034 | ) | ||||||
|
|
|
|
|
| |||||||
Total | $ | (39,786 | ) | $ | (95,796 | ) | $ | (107,063 | ) | |||
|
|
|
|
|
| |||||||
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| Year Ended December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
Federal – current | $ | 20,107 | $ | 6,994 | $ | 230 | ||||||
State – current | 2 | 95 | (60 | ) | ||||||||
Foreign – current | 9,531 | 25,252 | 10,297 | |||||||||
|
|
|
|
|
| |||||||
Total current | 29,640 | 32,341 | 10,467 | |||||||||
|
|
|
|
|
| |||||||
Federal – deferred | (75,279 | ) | (85,066 | ) | (108,274 | ) | ||||||
Foreign – deferred | (714 | ) | 12,939 | 2,011 | ||||||||
|
|
|
|
|
| |||||||
Total deferred | (75,993 | ) | (72,127 | ) | (106,263 | ) | ||||||
|
|
|
|
|
| |||||||
Total | $ | (46,353 | ) | $ | (39,786 | ) | $ | (95,796 | ) | |||
|
|
|
|
|
| |||||||
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:following (in thousands):
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||
Income before income tax expense: | ||||||||||||||||||||||||
(Loss) income before income tax expense: | ||||||||||||||||||||||||
U.S. | $ | (241,178 | ) | $ | (146,037 | ) | $ | (11,158 | ) | $ | (266,855 | ) | $ | (241,178 | ) | $ | (146,037 | ) | ||||||
Foreign | 219,738 | (322,262 | ) | (370,190 | ) | 40,230 | 219,738 | (322,262 | ) | |||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
| $ | (21,440 | ) | $ | (468,299 | ) | $ | (381,348 | ) | $ | (226,625 | ) | $ | (21,440 | ) | $ | (468,299 | ) | |||||||
|
|
|
|
|
| |||||||||||||||||||
Expected income tax benefit at federal statutory rate | $ | (7,504 | ) | $ | (163,905 | ) | $ | (133,472 | ) | $ | (47,591 | ) | $ | (7,504 | ) | $ | (163,905 | ) | ||||||
Effect of tax rate changes | (74,294 | ) | — | — | 1,763 | (74,294 | ) | — | ||||||||||||||||
Mandatory repatriation of earnings pursuant to Tax Reform and Jobs Act | 94,194 | — | — | |||||||||||||||||||||
Mandatory repatriation of earnings pursuant to Tax Reform Act | — | 94,194 | — | |||||||||||||||||||||
Effect of foreign operations | (42,102 | ) | 48,573 | (4,906 | ) | 15 | (42,102 | ) | 48,573 | |||||||||||||||
Amortization of deferred charges associated with intercompany rig sales to other tax jurisdictions | — | — | 38,466 | |||||||||||||||||||||
Valuation allowance | (41,492 | ) | 62,400 | — | 11,929 | (41,492 | ) | 62,400 | ||||||||||||||||
Uncertain tax positions, settlements and adjustments relating to prior years | 31,726 | (34,666 | ) | (1,114 | ) | (15,777 | ) | 31,726 | (34,666 | ) | ||||||||||||||
Other | (314 | ) | (8,198 | ) | (6,037 | ) | 3,308 | (314 | ) | (8,198 | ) | |||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Income tax benefit | $ | (39,786 | ) | $ | (95,796 | ) | $ | (107,063 | ) | $ | (46,353 | ) | $ | (39,786 | ) | $ | (95,796 | ) | ||||||
|
|
|
|
|
| |||||||||||||||||||
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
Deferred Income Taxes.Significant components of our deferred income tax assets and liabilities are as follows:follows (in thousands):
| December 31, | ||||||||||||||||
| 2017 | 2016 | December 31, | ||||||||||||||
| (In thousands) | 2018 | 2017 | ||||||||||||||
Deferred tax assets: | ||||||||||||||||
Net operating loss carryforwards, or NOLs | $ | 133,298 | $ | 159,653 | $ | 209,679 | $ | 133,298 | ||||||||
Foreign tax credits | 27,623 | 95,145 | 43,225 | 27,623 | ||||||||||||
Disallowed interest deduction | 16,248 | — | ||||||||||||||
Worker’s compensation and other current accruals | 10,330 | 14,824 | 8,375 | 10,330 | ||||||||||||
Bareboat charter deductions | — | 23,353 | ||||||||||||||
UK depreciation deduction | 52,800 | 21,222 | ||||||||||||||
U.K. depreciation deduction | — | 52,800 | ||||||||||||||
Anticipatory deductions and credits | 13,111 | — | 2,438 | 13,111 | ||||||||||||
Deferred compensation | 3,711 | 4,689 | ||||||||||||||
Foreign contribution taxes | 3,806 | 3,857 | ||||||||||||||
Stock compensation awards | 6,872 | 11,679 | ||||||||||||||
Deferred deductions | 94 | 8,185 | 10,481 | 14,483 | ||||||||||||
Other | 3,748 | 2,526 | 3,942 | 3,748 | ||||||||||||
|
|
|
| |||||||||||||
Total deferred tax assets | 255,393 | 345,133 | 294,388 | 255,393 | ||||||||||||
Valuation allowance | (169,224 | ) | (210,716 | ) | (174,970 | ) | (169,224 | ) | ||||||||
|
|
|
| |||||||||||||
Net deferred tax assets | 86,169 | 134,417 | 119,418 | 86,169 | ||||||||||||
|
|
|
| |||||||||||||
Deferred tax liabilities: | ||||||||||||||||
Property, plant and equipment | (236,038 | ) | (284,480 | ) | (212,251 | ) | (236,038 | ) | ||||||||
Mobilization | (17,192 | ) | (46,274 | ) | (11,012 | ) | (17,192 | ) | ||||||||
Other | (238 | ) | (674 | ) | (535 | ) | (238 | ) | ||||||||
|
|
|
| |||||||||||||
Total deferred tax liabilities | (253,468 | ) | (331,428 | ) | (223,798 | ) | (253,468 | ) | ||||||||
|
|
|
| |||||||||||||
Net deferred tax liability | $ | (167,299 | ) | $ | (197,011 | ) | $ | (104,380 | ) | $ | (167,299 | ) | ||||
|
|
|
| |||||||||||||
Net Operating Loss Carryforwards.As of December 31, 2018, we recorded a deferred tax asset of $209.7 million for the benefit of NOL carryforwards, comprised of $96.9 million related to our U.S. losses and $112.8 million related to our international operations. Approximately $111.6 million of this deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $98.1 million relates to NOL carryforwards in several of our foreign subsidiaries, as well as in the U.S. Unless utilized, the NOL carryforwards will expire between 2021 and 2028.
Foreign Tax Credits.As of December 31, 2018, we recorded a deferred tax asset of $43.2 million for the benefit of foreign tax credits in the U.S., all of which will expire, unless utilized, between 2020 to 2027.
Interest Deduction Carryforward.The Tax Reform Act signed into law in 2017 imposed new limitations to Code Section 163(j), restricting the ability to deduct interest paid or accrued on indebtedness. As of December 2018, we recorded a deferred tax asset for the benefit of the interest deduction carryforward in the amount of $16.2 million. The interest carryforward has an indefinite life.
Valuation Allowances.We record a valuation allowance to derecognize a portion of our deferred tax assets, which we do not expect to be ultimately realized. A summaryDuring the years ended December 31, 2018, 2017 and 2016, we established valuation allowances related to net operating losses, foreign tax credits and other deferred tax assets of changes$35.2 million, $37.9 million and $77.5 million, respectively. During the years ended December 31, 2018, 2017 and 2016, we released valuation allowances in thevarious jurisdictions of $23.3 million, $79.4 million and $13.5 million, respectively. The valuation allowance is as follows:
| For the Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands) | ||||||||||||
Valuation allowance as of January 1 | $ | 210,716 | $ | 146,647 | $ | 48,036 | ||||||
Establishment of valuation allowances: | ||||||||||||
Net operating losses | 20,805 | 10,318 | 82,155 | |||||||||
Foreign tax credits | 2,877 | 62,400 | — | |||||||||
Other deferred tax assets | 14,213 | 4,823 | 27,928 | |||||||||
Releases of valuation allowances in various jurisdictions | (79,387 | ) | (13,472 | ) | (11,472 | ) | ||||||
|
|
|
|
|
| |||||||
Valuation allowance as of December 31 | $ | 169,224 | $ | 210,716 | $ | 146,647 | ||||||
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|
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| |||||||
Net Operating Loss Carryforwards— Aswas also reduced by a $6.2 million adjustment to retained earnings at January 1, 2018 in connection with our adoption of December 31, 2017, we had recorded a deferred tax asset of $133.3 million for the benefit of NOL carryforwards, $18.1 million related to our U.S. losses and $115.2 million related to our international operations. Approximately $73.5 million of this deferred tax asset relates to NOL carryforwards that have anASU2016-16. See Note 1 “General Information –Changes in Accounting Principles –Income Taxes.”
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
indefinite life. The remaining $59.8 million relates to NOL carryforwards in several of our foreign subsidiaries, as well as in the United States. Unless utilized, the NOL carryforwards will expire between 2021 and 2037 as follows:
Year Expiring | Tax Benefit of NOL Carryforwards (In millions) | |||
2021 | $ | 5.1 | ||
2022 | 0.2 | |||
2023 | 0.1 | |||
2025 | 28.7 | |||
2027 | 7.6 | |||
2036 | 17.9 | |||
2037 | 0.2 | |||
|
| |||
Total | $ | 59.8 | ||
|
| |||
As of December 31, 2017, a2018, valuation allowance for $110.9allowances of $98.8 million, has$42.3 million, $16.2 million and $17.7 million have been recorded for our NOLs, foreign tax credits, interest deduction carryforward and other deferred tax assets, respectively, for which the deferred tax assetsbenefits are not likely to be realized.
Foreign Tax Credits.As of December 31, 2017, we had recorded a deferred tax asset of $27.6 million for the benefit of foreign tax credits in the U.S. Unless utilized, our excess foreign tax credits of $27.6 million in the U.S. will expire in 2019 and in the years 2024 to 2027 as follows:
Year Expiring | Foreign Tax Credits (In millions) | |||
2019 | $ | 0.8 | ||
2024 | 3.1 | |||
2025 | 3.5 | |||
2026 | 20.0 | |||
2027 | 0.2 | |||
|
| |||
Total | $ | 27.6 | ||
|
| |||
As of December 31, 2017, a valuation allowance of $26.7 million has been recorded for our foreign tax credits for which the deferred tax assets are not likely to be realized.
Valuation Allowances — Other Deferred Tax Assets.As of December 31, 2017, we recorded valuation allowances for other deferred tax assets of $31.6 million.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 morenot likely than not exposures.to be realized. A reconciliationrollforward of the beginning and ending amount of unrecognized tax benefits, gross of tax carryforwards and excluding interest and penalties, is as follows:follows (in thousands):
| For the Year Ended December 31, | ||||||||||||||||||||||||
| 2017 | 2016 | 2015 | For the Year Ended December 31, | |||||||||||||||||||||
| (In thousands) | 2018 | 2017 | 2016 | |||||||||||||||||||||
Balance, beginning of period | $ | (34,970 | ) | $ | (53,952 | ) | $ | (57,116 | ) | $ | (81,864 | ) | $ | (34,970 | ) | $ | (53,952 | ) | ||||||
Additions for current year tax positions | (51,260 | ) | (4,233 | ) | (7,013 | ) | (2,906 | ) | (51,260 | ) | (4,233 | ) | ||||||||||||
Additions for prior year tax positions | (2,938 | ) | (1,020 | ) | (82 | ) | (20,943 | ) | (2,938 | ) | (1,020 | ) | ||||||||||||
Reductions for prior year tax positions | 623 | 19,661 | 2,673 | 49,175 | 623 | 19,661 | ||||||||||||||||||
Reductions related to statute of limitation expirations | 6,681 | 4,574 | 7,586 | 595 | 6,681 | 4,574 | ||||||||||||||||||
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| |||||||||||||||||||
Balance, end of period | $ | (81,864 | ) | $ | (34,970 | ) | $ | (53,952 | ) | $ | (55,943 | ) | $ | (81,864 | ) | $ | (34,970 | ) | ||||||
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| |||||||||||||||||||
The $20.9 million addition for prior year tax positions in 2018 is primarily due to recent proposed regulations issued to clarify the use of certain tax attributes against the deemed, mandatory repatriation provision of the Tax Reform Act. The $49.2 million reduction for prior year tax positions in 2018 is primarily due to clarification issued by the IRS in regard to tax attributes available to offset the deemed, mandatory repatriation. The $51.3 million addition tofor current year tax positions for 2017 is primarily attributable to a provisional liability associated with the use of tax attributes in conjunction with the deemed, mandatory repatriation provision of the Tax Reform Act. The $19.7 million reduction for prior year tax positions in 2016 resulted primarily from the devaluation of the Egyptian Pound.
At December 31, 2017, $2.32018, $1.2 million, $51.3$7.5 million and $52.9$72.2 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively. At December 31, 2016, $2.12017, $2.3 million, $3.1$51.3 million and $35.0$52.9 million of the net liability for uncertain tax positions were reflected in “Other assets,” “Deferred tax liability” and “Other liabilities,” respectively. Of the net unrecognized tax benefits at December 31, 2018, 2017 and 2016, and 2015, all $81.6 million, $101.9 million $36.0 million and $49.4$36.0 million, respectively, would affect the effective tax rates if recognized.
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. At December 31, 2017, the amount of accrued interest and penalties related to uncertain tax positions werewas $3.1 million and $15.1 million, respectively. At December 31, 2016, the amount of accrued interest and penalties related to uncertain tax positions were $2.7 million and $16.8 million, respectively.
We record interest related to accrued uncertain tax positions in interest expense and recognize penalties associated with uncertain tax positions in tax expense. Interest expense (benefit) recognized during the three years ended December 31, 2018, 2017 and 2016 related to uncertain tax positions was $0.1 million, $0.5 million $(0.1) million and $(4.8)$(0.1) million, respectively. Penalties recognized during the three years ended December 31, 2018, 2017 and 2016 related to uncertain tax positions were $0.6 million $(1.7) million and $(23.2) million, and $2.3 million, respectively.
In several of the international locations in which we operate, certain of our wholly-owned subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide specialized services and equipment in support of our foreign operations. We apply a transfer pricing methodology to determine the amount to be charged for providing the services and equipment. In most cases, there are alternative transfer pricing methodologies that could be applied to these transactions and, if applied, could result in different chargeable amounts. Taxing authorities in the various foreign locations in which we operate could apply one of the alternative transfer pricing methodologies which could result in an increase to our income tax liabilities with respect to tax returns that remain subject to examination.
We expect the statute of limitations for the 2012 through 2017 tax yearyears to expire in 20182019 for onevarious of our subsidiaries operating in Mexico.Egypt, Ireland, Malaysia, Mexico and the U.K. We anticipate that the related unrecognized tax benefit will decrease by $1.5$3.9 million at that time.
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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 2006 to 2016.2017. We are currently under audit in the United States, Australia, Brazil, Egypt, Equatorial Guinea, Mexico, Nicaragua, Norway, Qatar and the United Kingdom.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.
17. 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 makeafter-tax contributions to the 401k Plan. During 2018, 2017 2016 and 2015,2016, we matched 5%, 6%5% and 6%, respectively, of each employee’s compensation contributed to the 401k Plan. We ceased making discretionary profit sharing contributions to the 401k Plan on May 1, 2015. Prior to that date, we made discretionary profit sharing contributions equal to 4% of a participant’s defined compensation. Participants are fully vested in the employer match immediately upon enrollment in the 401k Plan and subject to a three-year cliff vesting period for any profit sharing contribution. For the years ended December 31, 2018, 2017 2016 and 2015,2016, our provision for contributions was $8.0 million, $8.9 million and $12.9 million, and $23.8 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 2018, 2017 and from July 1, 2016 to December 31, 2016 for employees working in the U.K. sector of the North Sea was 6% of the employee’s defined compensation. During the first six months of 2016, and in 2015, our contribution was 10% of the employee’s defined compensation. Our provision for contributions was $1.5 million, $1.4 million $2.0 million and $3.4$2.0 million for the years ended December 31, 2018, 2017 2016 and 2015,2016, respectively.
The defined contribution retirement plan for our TCN employees, or International Savings Plan, is similar to the 401k Plan. During 2018, 2017 2016 and 2015,2016, we matched 5%, 6%5% and 6%, respectively, of each employee’s compensation contributed to the International Savings Plan. During the four months ended April 30, 2015, we made discretionary profit sharing contributions to the International Savings Plan equal to 4% of a participant’s defined compensation. We ceased making profit sharing contributions on May 1, 2015. Our provision for contributions was $0.4 million, $0.4 million and $0.8 million for the years ended December 31, 2018, 2017 and $2.2 million for 2017, 2016, and 2015, respectively.
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 ourthe 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 2018, 2017 2016 and 20152016 was approximately $136,000, $146,000$0.1 million in each respective year.
18. Segments and $153,000, respectively.Geographic Area Analysis
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
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.
Revenues from contract drilling services by equipment-type are listed below:
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands) | ||||||||||||
Floaters: | ||||||||||||
Ultra-Deepwater | $ | 1,090,139 | $ | 989,158 | $ | 1,339,059 | ||||||
Deepwater | 202,329 | 256,997 | 548,667 | |||||||||
Mid-Water | 137,607 | 248,846 | 387,549 | |||||||||
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Total Floaters | 1,430,075 | 1,495,001 | 2,275,275 | |||||||||
Jack-ups | 21,144 | 30,213 | 84,909 | |||||||||
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Total contract drilling revenues | 1,451,219 | 1,525,214 | 2,360,184 | |||||||||
Revenues related to reimbursable expenses | 34,527 | 75,128 | 59,209 | |||||||||
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| |||||||
Total revenues | $ | 1,485,746 | $ | 1,600,342 | $ | 2,419,393 | ||||||
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Geographic Areas
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, 2017,2018, our actively-marketedactive drilling rigs were located offshore fourthree 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.
| Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| (In thousands) | ||||||||||||
United States | $ | 630,595 | $ | 548,024 | $ | 513,605 | ||||||
International: | ||||||||||||
South America | 348,479 | 434,956 | 812,271 | |||||||||
Australia/Asia | 307,925 | 234,182 | 415,033 | |||||||||
Europe | 177,603 | 344,964 | 532,824 | |||||||||
Mexico | 21,144 | 38,216 | 145,660 | |||||||||
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| |||||||
| 855,151 | 1,052,318 | 1,905,788 | ||||||||||
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Total revenues | $ | 1,485,746 | $ | 1,600,342 | $ | 2,419,393 | ||||||
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DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)The following tables provide information about disaggregated revenue by equipment-type and primary geographical market (in thousands):
| 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 | ||||||||||
Australia/Asia | 167,398 | — | 167,398 | 7,811 | 175,209 | |||||||||||||||
South America | 170,839 | — | 170,839 | (26 | ) | 170,813 | ||||||||||||||
Europe | 84,749 | — | 84,749 | 8,021 | 92,770 | |||||||||||||||
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|
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Total | $ | 1,051,560 | $ | 8,413 | $ | 1,059,973 | $ | 23,242 | $ | 1,083,215 | ||||||||||
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| |||||||||||
| (1) | Loss-of-hire insurance proceeds related to early contract terminations for twojack-up rigs. |
| 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 | ||||||||||
Australia/Asia | 290,552 | — | 290,552 | 17,373 | 307,925 | |||||||||||||||
South America | 348,721 | — | 348,721 | (242 | ) | 348,479 | ||||||||||||||
Europe | 171,147 | — | 171,147 | 6,456 | 177,603 | |||||||||||||||
Mexico | — | 21,144 | 21,144 | — | 21,144 | |||||||||||||||
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| |||||||||||
Total | $ | 1,430,075 | $ | 21,144 | $ | 1,451,219 | $ | 34,527 | $ | 1,485,746 | ||||||||||
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| Year Ended December 31, 2016 | ||||||||||||||||||||
| Floater Rigs | Jack-up Rigs | Total Contract Drilling Revenues | Revenues Related to Reimbursable Expenses | Total | ||||||||||||||||
United States | $ | 482,638 | $ | 4,882 | $ | 487,520 | $ | 9,832 | $ | 497,352 | ||||||||||
Australia/Asia | 234,182 | — | 234,182 | 14,795 | 248,977 | |||||||||||||||
South America | 434,956 | — | 434,956 | 720 | 435,676 | |||||||||||||||
Europe | 330,340 | — | 330,340 | 49,781 | 380,121 | |||||||||||||||
Mexico | 12,885 | 25,331 | 38,216 | — | 38,216 | |||||||||||||||
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| |||||||||||
Total | $ | 1,495,001 | $ | 30,213 | $ | 1,525,214 | $ | 75,128 | $ | 1,600,342 | ||||||||||
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An individual international country may, from time to time, comprise a material percentage of our total contract drilling revenues from unaffiliated customers. For the years ended December 31, 2018, 2017 2016 and 2015,2016, individual countries that comprised 5% or more of our total contract drilling revenues from unaffiliated customers are listed below.
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | |||||||||||||||||||
Brazil | 18.9 | % | 18.0 | % | 23.1 | % | 15.8 | % | 18.9 | % | 18.0 | % | ||||||||||||
Malaysia | 10.5 | % | 11.2 | % | 1.7 | % | ||||||||||||||||||
United Kingdom | 12.0 | % | 15.3 | % | 11.4 | % | 8.5 | % | 12.0 | % | 15.3 | % | ||||||||||||
Malaysia | 11.2 | % | 1.7 | % | 6.8 | % | ||||||||||||||||||
Australia | 9.5 | % | 12.8 | % | 7.0 | % | 5.6 | % | 9.5 | % | 12.8 | % | ||||||||||||
Trinidad & Tobago | 4.6 | % | 9.2 | % | 9.8 | % | — | 4.6 | % | 9.2 | % | |||||||||||||
Mexico | 1.4 | % | 2.4 | % | 6.0 | % | ||||||||||||||||||
Romania | — | 4.0 | % | 9.7 | % | |||||||||||||||||||
The following table presents our long-lived tangible assets by geographic location as of December 31, 2018, 2017 2016 and 2015.2016. 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 geographic area in which they were expected to operate.operate (in thousands).
| December 31, | ||||||||||||||||||||||||
| 2017 (1) | 2016 (1) | 2015 (1) | December 31, | |||||||||||||||||||||
| (In thousands) | 2018(1) | 2017(1) | 2016(1) | |||||||||||||||||||||
Drilling and other property and equipment, net: | ||||||||||||||||||||||||
United States | $ | 2,300,956 | $ | 2,753,511 | $ | 3,292,474 | $ | 2,245,989 | $ | 2,300,956 | $ | 2,753,511 | ||||||||||||
International: | ||||||||||||||||||||||||
Europe/Africa | 1,084,540 | 320,473 | 380,462 | |||||||||||||||||||||
Australia/Asia/Middle East | 1,714,246 | 1,429,563 | 1,224,089 | 927,919 | 1,714,246 | 1,429,563 | ||||||||||||||||||
South America | 923,398 | 1,030,069 | 1,051,283 | 923,355 | 923,398 | 1,030,069 | ||||||||||||||||||
Europe/Africa | 320,473 | 380,462 | 664,520 | |||||||||||||||||||||
Mexico | 2,568 | 133,330 | 146,448 | 2,419 | 2,568 | 133,330 | ||||||||||||||||||
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| |||||||||||||||||||
| 2,960,685 | 2,973,424 | 3,086,340 | 2,938,233 | 2,960,685 | 2,973,424 | |||||||||||||||||||
|
|
|
|
|
| |||||||||||||||||||
Total | $ | 5,261,641 | $ | 5,726,935 | $ | 6,378,814 | $ | 5,184,222 | $ | 5,261,641 | $ | 5,726,935 | ||||||||||||
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| |||||||||||||||||||
| (1) | During 2018, 2017 |
The following table presents the countries in which material concentrations of our long-lived tangible assets were located as of December 31, 2018, 2017 2016 and 2015:2016:
| December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
United States | 43.7 | % | 48.1 | % | 51.6 | % | ||||||
Malaysia | 20.6 | % | 13.6 | % | 10.4 | % | ||||||
Brazil | 17.5 | % | 16.8 | % | 15.3 | % | ||||||
Australia | 12.0 | % | 11.4 | % | 4.5 | % | ||||||
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)
| December 31, | ||||||||||||
| 2018 | 2017 | 2016 | ||||||||||
United States | 43.3 | % | 43.7 | % | 48.1 | % | ||||||
United Kingdom | 20.9 | % | 2.5 | % | 2.9 | % | ||||||
Brazil | 17.8 | % | 17.5 | % | 16.8 | % | ||||||
Singapore | 7.1 | % | — | — | ||||||||
Malaysia | 6.1 | % | 20.6 | % | 13.6 | % | ||||||
Australia | 4.7 | % | 12.0 | % | 11.4 | % | ||||||
As of December 31, 2018, 2017 2016 and 2015,2016, no other countries had more than a 5% concentration of our long-lived tangible assets.
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, 2018, 2017 2016 and 20152016 that contributed more than 10% of our total revenues are as follows:
| Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
Customer | 2017 | 2016 | 2015 | 2018 | 2017 | 2016 | ||||||||||||||||||
Anadarko | 24.9 | % | 22.4 | % | 12.4 | % | 33.8 | % | 24.9 | % | 22.4 | % | ||||||||||||
Hess Corporation | 25.0 | % | 16.0 | % | 7.7 | % | ||||||||||||||||||
Petróleo Brasileiro S.A. | 18.9 | % | 17.9 | % | 24.1 | % | 15.8 | % | 18.9 | % | 17.9 | % | ||||||||||||
Hess Corporation | 16.0 | % | 7.7 | % | 0.3 | % | ||||||||||||||||||
BP | 15.8 | % | 9.0 | % | 0.1 | % | 10.5 | % | 15.8 | % | 9.0 | % | ||||||||||||
ExxonMobil | — | 5.8 | % | 12.4 | % | |||||||||||||||||||
19. Unaudited Quarterly Financial Data
Unaudited summarized financial data by quarter for the years ended December 31, 20172018 and 20162017 is shown below.below (in thousands).
| First Quarter | Second Quarter | Third Quarter | Fourth Quarter | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | |||||||||||||||||||||||||
2018 | ||||||||||||||||||||||||||||||||
Revenues | $ | 295,510 | $ | 268,861 | $ | 286,322 | $ | 232,522 | ||||||||||||||||||||||||
Operating income (loss) (1) | 512 | (52,375 | ) | (23,043 | ) | (37,277 | ) | |||||||||||||||||||||||||
(Loss) income 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 | ) | |||||||||||||||||||||
| (In thousands, except per share data) | ||||||||||||||||||||||||||||||||
2017 | ||||||||||||||||||||||||||||||||
Revenues | $ | 374,226 | $ | 399,289 | $ | 366,023 | $ | 346,208 | ||||||||||||||||||||||||
Operating income (loss)(1) | 50,859 | 20,824 | 58,581 | (6,385 | ) | |||||||||||||||||||||||||||
Income (loss) before income tax expense | 24,462 | (7,020 | ) | (3,801 | ) | (35,081 | ) | |||||||||||||||||||||||||
Net income (loss) | 23,539 | 15,949 | 10,799 | (31,941 | ) | |||||||||||||||||||||||||||
Net income (loss) per share, basic and diluted | $ | 0.17 | $ | 0.12 | $ | 0.08 | $ | (0.23 | ) | |||||||||||||||||||||||
2016 | ||||||||||||||||||||||||||||||||
Revenues | $ | 470,543 | $ | 388,747 | $ | 349,178 | $ | 391,874 | $ | 374,226 | $ | 399,289 | $ | 366,023 | $ | 346,208 | ||||||||||||||||
Operating income (loss)(2) | 111,569 | (626,669 | ) | 54,071 | 104,145 | 50,859 | 20,824 | 58,581 | (6,385 | ) | ||||||||||||||||||||||
Income (loss) before income tax expense | 83,196 | (666,115 | ) | 34,746 | 79,874 | 24,462 | (7,020 | ) | (3,801 | ) | (35,081 | ) | ||||||||||||||||||||
Net income (loss) | 87,425 | (589,937 | ) | 13,927 | 116,082 | 23,539 | 15,949 | 10,799 | (31,941 | ) | ||||||||||||||||||||||
Net income (loss) per share, basic and diluted | $ | 0.64 | $ | (4.30 | ) | $ | 0.10 | $ | 0.85 | $ | 0.17 | $ | 0.12 | $ | 0.08 | $ | (0.23 | ) | ||||||||||||||
| (1) | During the second quarter of 2018, we recognized an impairment loss of $27.2 million to write down the carrying value of theOcean Scepter to its estimated recoverable amount. See Notes 1 and 3. |
| (2) | During the second and fourth quarters of 2017, we recognized |
| Item 9. |
|
Not applicable.
| Item 9A. | Controls and Procedures |
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain a system of disclosure controls and procedures that are designed to ensure information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.
Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules13a-15(e) and15d-15(e)) as of December 31, 2017.2018. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of December 31, 2017.2018.
Internal Control Over Financial Reporting
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as defined in Exchange Act Rules13a-15(f) and15d-15(f)) for Diamond Offshore Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our management and Board of Directors regarding the preparation and fair presentation of published financial statements.
There are inherent limitations to the effectiveness of any control system, however well designed, including the possibility of human error or mistakes, faulty judgments in decision-making and the possible circumvention or overriding of controls. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Management must make judgments with respect to the relative cost and expected benefits of any specific control measure. The design of a control system also is based in part upon assumptions and judgments made by management about the likelihood of future events, and there can be no assurance that a control will be effective under all potential future conditions. As a result, even an effective system of internal controls can provide no more than reasonable assurance with respect to the fair presentation of financial statements and the processes under which they were prepared. 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 ifof changes in conditions, or that the degree of compliance with the policies and procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting as of December 31, 2017.2018. In making this assessment, our management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) inInternal Control – Integrated Framework (2013). Based on this assessment our management believes that, as of December 31, 2017,2018, our internal control over financial reporting was effective.
Deloitte & Touche LLP, the registered public accounting firm that audited our financial statements included in this Annual Report on Form10-K, has issued an attestation report on the effectiveness of our internal control over financial reporting. The attestation report of Deloitte & Touche LLP is included at the beginning of Item 8 of
this Form10-K.
There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our fourth fiscal quarter of 20172018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
| Item 10. |
|
Information about our directors and persons nominated to become directors is contained under the caption “Election of Directors” in our Proxy Statement for our 20182019 Annual Meeting of Stockholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2017,2018, or our 20182019 Proxy Statement, and is incorporated herein by reference. Information about our executive officers is reported under the caption “Executive Officers of the Registrant” in Item 1 of Part I of this Report.
Information about beneficial ownership reporting compliance is contained under the caption “Section 16(a) Beneficial Ownership Reporting Compliance” in our 20182019 Proxy Statement and is incorporated herein by reference.
We have a Code of Business Conduct and Ethics that applies to all of our directors, officers and employees, including our principal executive officer, principal financial officer and principal accounting officer. Our code can be found in the Corporate Governance section of our website at www.diamondoffshore.com and is available in print to any stockholder who requests a copy by writing to our Corporate Secretary at Diamond Offshore, Attention: Corporate Secretary, 15415 Katy Freeway, Suite 100, Houston, Texas 77094. We intend to post any changes to or waivers of our code for our directors or executive officers, including our principal executive officer, principal financial officer and principal accounting officer, on our website within the time period required by the SEC and the NYSE.
Information about the procedures by which security holders may recommend nominees to our Board of Directors can be found in our 20182019 Proxy Statement under the captions “Board Diversity and Director Nominating Process” and “Communications with Diamond Offshore and Others” and is incorporated herein by reference.
Information about the composition of the Audit Committee and our Audit Committee financial expertsexpert is contained in our 20182019 Proxy Statement under the caption “Board Committees – Audit Committee”Committees” and is incorporated herein by reference.
| Item 11. |
Information about Compensation Committee interlocks, director and executive officer compensation and the Compensation Committee Reportreport is contained in our 20182019 Proxy Statement under the captions “Compensation Discussion and Analysis,” “Executive Compensation,” “Equity Plan,” “Director Compensation,” “Board Committees – Compensation Committee —– Compensation Committee Interlocks and Insider Participation,” “Director Compensation,” “Compensation Discussion and Analysis”Participation” and “Compensation Committee Report” and is incorporated herein by reference.
| Item 12. |
|
Information about securities authorized for issuance under equity compensation plans can be found under the caption “Stock-Based Compensation” under Item 4 of this Report and is contained in our 20182019 Proxy Statement under the caption “Equity Plan” and is incorporated herein by reference.
Information about the number of shares of our common stock beneficially owned by each director and named executive officer, by all directors and executive officers as a group and onby each beneficial owner of more than 5% of our common stock is contained under the captions “Security“Stock Ownership of Certain Beneficial Owners”Principal Stockholders” and “Security ownership“Stock Ownership of Management and Directors” in our 20182019 Proxy Statement and is incorporated herein by reference.
| Item 13. |
|
Information about certain relationships and related transactions and director independence is contained under the captions “Director Independence” and “Transactions with Related Persons” in our 20182019 Proxy Statement and is incorporated herein by reference.
| Item 14. | Principal Accounting Fees and Services. |
Item 14. Principal Accounting Fees and Services.
Information about our Audit Committee’spre-approval policy and procedures for audit and other services and information about our principal accountant fees and services is contained in our 20182019 Proxy Statement under the caption “Ratification of Appointment of Independent Auditor —– Audit Fees” and “—“ – Auditor Engagement andPre-Approval Policy” and is incorporated herein by reference.
| Item 15. | Exhibits and Financial Statement Schedules. |
(a) Index to Financial Statements and Financial Statement Schedules
(1) Financial Statements | Page | |||
| ||||
| 43 | ||||
| 45 | ||||
| 46 | ||||
Consolidated | 47 | |||
| 48 | ||||
| 49 | ||||
(b) Exhibits
Exhibit No. | Description | |
| | Executive Retention Agreement, dated June 29, 2018, between Diamond Offshore Drilling, Inc. and Ronald Woll (incorporated by reference to Exhibit 10.1 to our Current Report on Form | |
| 21.1* | List of Subsidiaries of Diamond Offshore Drilling, Inc. | |
| 23.1* | Consent of Deloitte & Touche LLP. | |
| 24.1* | Power of Attorney (set forth on the signature page hereof). | |
| 31.1* | Rule13a-14(a) Certification of the Chief Executive Officer. | |
| 31.2* | Rule13a-14(a) Certification of the Chief Financial Officer. | |
| 32.1* | Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer. | |
| 101.INS** | XBRL Instance Document. | |
| 101.SCH** | XBRL Taxonomy Extension Schema Document. | |
| 101.CAL** | XBRL Taxonomy Calculation Linkbase Document. | |
| 101.LAB** | XBRL Taxonomy Label Linkbase Document. | |
| 101.PRE** | XBRL Presentation Linkbase Document. | |
| 101.DEF** | XBRL Taxonomy Extension Definition. | |
| * | Filed or furnished herewith. |
| ** | The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections. |
| + | Management contracts or compensatory plans or arrangements. |
| Item 16. | Form10-K Summary. |
None.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 13, 2018.2019.
| DIAMOND OFFSHORE DRILLING, INC. | ||
| By: | /s/ SCOTT KORNBLAU | |
Scott Kornblau
| ||
| Chief Financial Officer | ||
Each person whose signature appears below constitutes and appoints Scott Kornblau and David L. Roland and each of them, as his or her true and lawfulattorneys-in-fact and agents, with full power of substitution andre-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all documents relating to this Annual Report on Form10-K, including any and all amendments and supplements thereto, and to file the same with all exhibits thereto and other documents in connection therewith with the Securities and Exchange Commission, granting unto saidattorneys-in-fact and agents full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully as to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that saidattorneys-in-fact and agents or their or his or her substitute or substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature | Title | Date | ||
/s/ MARC EDWARDS Marc Edwards | President, Chief Executive Officer and Director
| February 13, | ||
/s/ SCOTT KORNBLAU Scott Kornblau | Senior Vice President Officer
| February 13, | ||
/s/ BETH G. GORDON Beth G. Gordon | Vice President and Controller
| February 13, | ||
/s/ JAMES S. TISCH James S. Tisch | Chairman of the Board | February 13, | ||
| ||||
/s/ CHARLES L. FABRIKANT Charles L. Fabrikant | Director | February 13, | ||
/s/ PAUL G. GAFFNEY II Paul G. Gaffney II | Director | February 13, | ||
/s/ EDWARD GREBOW Edward Grebow | Director | February 13, 2019 | ||
/s/ KENNETH I. SIEGEL Kenneth I. Siegel | Director | February 13, 2019 | ||
Signature | Title | Date | ||
|
|
| ||
| ||||
| ||||
/s/ CLIFFORD M. SOBEL Clifford M. Sobel | Director | February 13, | ||
/s/ ANDREW H. TISCH Andrew H. Tisch | Director | February 13, | ||
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