DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2017 March (Form 10-Q)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended March 31, 2017

OR

For the transition period from                      to                     

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

15415 Katy Freeway

Houston, Texas

77094

(Address of principal executive offices)

(Zip Code)

(281) 492-5300

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act.  ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ☐    No  ☒

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

As of April 27, 2017 Common stock, $0.01 par value per share 137,224,156 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED MARCH 31, 2017

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PART I. FINANCIAL INFORMATION

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)

The accompanying notes are an integral part of the condensed consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share data)

The accompanying notes are an integral part of the condensed consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

The accompanying notes are an integral part of the condensed consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

The accompanying notes are an integral part of the condensed consolidated financial statements.

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

The unaudited condensed consolidated financial statements of Diamond Offshore Drilling, Inc. and subsidiaries, which we refer to as “Diamond Offshore,” “we,” “us” or “our,” should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2016 (File No. 1-13926).

As of April 27, 2017, Loews Corporation owned approximately 53% of the outstanding shares of our common stock.

Interim Financial Information

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the U.S., or GAAP, for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission. Accordingly, pursuant to such rules and regulations, they do not include all disclosures required by GAAP for complete financial statements. The condensed consolidated financial information has not been audited but, in the opinion of management, includes all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of Diamond Offshore’s condensed consolidated balance sheets, statements of operations, statements of comprehensive income and statements of cash flows at the dates and for the periods indicated. Results of operations for interim periods are not necessarily indicative of results of operations for the respective full years.

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with 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.

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. During the three-month period ended March 31, 2017 and the year ended December 31, 2016, we capitalized $24.5 million and $177.6 million, respectively, in replacements and betterments of our drilling fleet. See Note 5.

Capitalized Interest

We capitalize interest cost for qualifying construction and upgrade projects. There were no qualifying projects during the three months ended March 31, 2017. A reconciliation of our total interest cost to “Interest expense, net of amounts capitalized” as reported in our Condensed Consolidated Statements of Operations is as follows:

Stock-Based Compensation

In March 2016, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2016-09, Compensation - Stock Compensation (Topic 718), or ASU 2016-09. ASU 2016-09 requires that all excess tax benefits and tax deficiencies be recognized in the income statement as discrete tax items when

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share-based awards vest or are settled. The update 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. ASU 2016-09 is effective for fiscal years beginning after December 15, 2016 and was adopted by us on January 1, 2017.

The guidance requiring (i) excess tax benefits to be recorded in the condensed consolidated statement of operations, (ii) exclusion of excess tax benefits from the computation of assumed proceeds under the treasury stock method when calculating earnings per share, and (iii) presentation of excess tax benefits as an operating activity on the statement of cash flows rather than as a financing activity has been applied prospectively effective January 1, 2017. We have elected to account for forfeitures of share-based awards in the period in which such forfeitures occur rather than using an estimated forfeiture rate and have adopted this change using a modified retrospective approach, which resulted in a $0.6 million reduction in opening retained earnings. The impact to our Condensed Consolidated Balance Sheets is as follows:

Recent Accounting Pronouncements

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, or ASU 2016-15. ASU 2016-15 provides specific guidance on eight cash flow classification issues not specifically addressed by GAAP: debt prepayment or debt extinguishment costs; settlement of zero-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 ASU 2016-15 are effective for interim and annual periods beginning after December 15, 2017. ASU 2016-15 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. Early adoption is permitted. We are currently evaluating the provisions of ASU 2016-15 but do not expect ASU 2016-15 to have a significant impact on the presentation of cash receipts and cash payments within our condensed consolidated statements of cash flows.

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU 2016-02, which requires an entity to separate the lease components from the non-lease components in a contract. The lease components are to be accounted for under ASU 2016-02, which, under the guidance, may require recognition of lease assets and lease liabilities by lessees for most leases and derecognition of the leased asset and recognition of a net investment in the lease by the lessor. ASU 2016-02 also provides for additional disclosure requirements for both lessees and lessors. Non-lease components would be accounted for under ASU 2014-09. The guidance of ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted. We expect to adopt ASU 2016-02 on January 1, 2019. We are currently reviewing the provisions of the accounting standard, but have not yet determined the impact of ASU 2016-02 on our financial position, results of operations or cash flows or our expected transition method.

In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09. 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 customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized and requires enhanced disclosures about revenue. In July 2015, the FASB issued ASU 2015-14, which deferred the effective date of ASU 2014-09. ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017. We plan to adopt ASU 2014-09 effective January 1, 2018 using the modified retrospective approach whereby we will record the cumulative effect of applying the new standard to all outstanding contracts as of January 1, 2018 as an adjustment to opening retained earnings. We do not expect our pattern of revenue recognition under the new guidance to materially differ from our current revenue recognition practice. We expect that the cumulative effect adjustment to opening retained earnings will not be significant.

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Condensed Consolidated Balance Sheets Information

Accounts receivable, net of allowance for bad debts, consist of the following:

Prepaid expenses and other current assets consist of the following:

Accrued liabilities consist of the following:

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Condensed Consolidated Statements of Cash Flows Information

Noncash investing activities excluded from the Condensed Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows:

A reconciliation of the numerators and the denominators of our basic and diluted per-share computations is as follows:

The following table sets forth the share effects of stock-based awards excluded from our computations of diluted earnings per share, or EPS, for the periods presented:

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 residential 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.

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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 has consisted 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, we do not believe that we have any significant concentrations of credit risk at March 31, 2017.

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 a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible and, historically, losses on our trade receivables have been infrequent occurrences.

Fair Values

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value:

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 three-month period ended March 31, 2017 or the year ended December 31, 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 of $678.1 million related to certain of our drilling rigs and related rig spare parts and supplies, which were measured at fair value on a nonrecurring basis during the year ended December 31, 2016.

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Assets and liabilities measured at fair value are summarized below.

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 Condensed Consolidated Balance Sheets, approximate fair value based on the following assumptions:

We consider our senior notes 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 March 31, 2017 and December 31, 2016. 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

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service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day period of the report date. Fair values and related carrying values of our senior notes are shown below.

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.

Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:

Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.

Asbestos Litigation. We are one of several unrelated defendants in lawsuits filed in Louisiana state courts alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted in the lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our 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 these claims, lawsuits and actions cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of these matters. Any claims against us, whether meritorious or not, could cause us to incur costs and expenses, require significant

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amounts of management time and result in the diversion of significant operational 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.

NPI Arrangement. We received customer payments measured by a percentage net profits interest (primarily of 27%) under an overriding royalty interest in certain developmental oil-and-gas producing properties, or NPI, which we believe is a real property interest. Our drilling program related to the NPI was completed in 2011, and the balance of the amounts due to us under the NPI was received in 2013. However, in August 2012, the customer that conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code. Certain parties (including the debtor) in the bankruptcy proceedings questioned whether our NPI, and certain amounts we received under it after the filing of the bankruptcy, should be included in the debtor’s estate under the bankruptcy proceeding. In 2013, we filed a declaratory judgment action in the bankruptcy court seeking a declaration that our NPI, and payments that we received from it after the filing of the bankruptcy, are not part of the bankruptcy estate. We agreed to a settlement with the company that purchased most of the debtor’s assets (including the debtor’s claims against our NPI) whereby the nature of our NPI will not be challenged by that party and our declaratory judgment action was dismissed. Following the settlement, the bankruptcy was converted to a Chapter 7 liquidation proceeding. Several lienholders who had previously intervened in the declaratory judgment action filed motions in the bankruptcy contending that their liens have priority and seeking disgorgement of $3.25 million of payments made to us after the bankruptcy was filed. We believe that our rights to the payments at issue are superior to these liens, and we filed motions to dismiss the claims. In November 2016, the court dismissed the lienholders’ claims, and the lienholders are appealing the ruling. In addition, the bankruptcy trustee filed counterclaims seeking disgorgement of a total of $30.0 million of pre- and post-bankruptcy payments made to us under the original NPI. The bankruptcy court has dismissed all but one of the trustee’s disgorgement claims, which is limited in amount to $17.0 million. In December 2016, the company that purchased most of the debtor’s assets from bankruptcy also filed for bankruptcy. We continue to pursue available defenses and available protections, and still expect the bankruptcy proceedings to be concluded with no further material impact to us.

Personal Injury Claims. Under our current insurance policies, which renewed effective May 1, 2017, 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 deductible for personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico is $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 March 31, 2017 our estimated liability for personal injury claims was $32.8 million, of which $4.5 million and $28.3 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Condensed Consolidated Balance Sheets. At December 31, 2016 our estimated liability for personal injury claims was $32.9 million, of which $6.1 million and $26.8 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Condensed Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

Letters of Credit and Other. We were contingently liable as of March 31, 2017 in the amount of $38.2 million under certain performance, tax, supersedeas, court and customs bonds and letters of credit. Agreements relating to approximately $35.2 million of performance, tax, supersedeas, court and customs bonds can require collateral at any

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time. As of March 31, 2017, 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.

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.

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 March 31, 2017, our active drilling rigs were located offshore in six 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.

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The following discussion should be read in conjunction with our unaudited condensed consolidated financial statements (including the notes thereto) included in Item 1 of this report and our audited consolidated financial statements (including the notes thereto), Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 1A, “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2016. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We provide contract drilling services to the energy industry around the globe with a fleet of 24 offshore drilling rigs. Our current fleet consists of four drillships, 19 semisubmersibles and one jack-up rig. During the first quarter of 2017, the Ocean GreatWhite, Ocean BlackRhino and Ocean Scepter all went on contract and the Ocean Monarch is currently undergoing a shipyard survey and contract preparation activities in advance of three future contracts, the first of which is expected to commence late in the second quarter of 2017. Of our current fleet, as of April 27, 2017, ten rigs were cold stacked, consisting of four ultra-deepwater, three deepwater and three mid-water semisubmersible rigs. The Ocean Spur, reported as an asset held for sale at December 31, 2016, was sold in April 2017. See “— Contract Drilling Backlog.”

Market Overview

During the first four months of 2017, oil prices remained in the general range of $50-$55 per barrel but continued to exhibit day-to-day volatility due to multiple factors, including fluctuations in the current and expected level of global oil inventories and estimates of global oil demand. As a result, overall fundamentals in the offshore oil and gas industry have not yet improved. Capital spending for offshore exploration and development has continued to decline, with 2017 capital spending estimated by some industry analysts to decrease up to 20% from 2016 levels. If these market estimates are realized, it would represent three consecutive years of decline in offshore spending. However, inquiries for rig availability and new tenders have recently increased, although from a low base line over the past few years. Recent tendering activity is primarily for projects commencing in 2019 and later.

Despite the cold stacking and retirement of numerous rigs during 2016, the floater market remains oversupplied. Based on industry data as of the date of this report, there are in excess of 30 floater rigs currently on order, with scheduled deliveries from 2017 through 2021. The majority of these rigs are not currently contracted for future work.

Dayrate competition among offshore drillers remains intense as rig supply exceeds demand. In some cases, dayrates have been negotiated at break-even, or below cost levels, in order to enable drilling contractors to recover a portion of operating costs for rigs that would otherwise be uncontracted or cold stacked. Discussions with our customers indicate a preference for “hot” rigs rather than the reactivation of cold-stacked rigs. This preference incentivizes drilling contractors to accept lower rates for the sole purpose of maintaining their rigs in an active state and allowing for at least partial cost recovery. Industry analysts have predicted that the offshore contract drilling market may remain depressed with further declines in dayrates and utilization throughout 2017, but that the market could begin to see stabilization in these metrics in late 2017 or early 2018.

As a result of the current depressed market conditions in the offshore drilling industry and continued pessimistic outlook for the near term, certain of our customers, as well as those of our competitors, have attempted to renegotiate or terminate existing drilling contracts. Such renegotiations have included requests to lower the contract dayrate, in some cases in exchange for additional contract term, shorten the term on one contracted rig in exchange for additional term on another rig, terminate a contract in exchange for a lump sum payout and many other possibilities. In addition to the potential for renegotiations, some of our drilling contracts permit the customer to terminate the contract early after specified notice periods, usually resulting in a requirement for the customer to pay a contractually specified termination amount, which may not fully compensate us for the loss of the contract. Some of our customers have also utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance with the contracts.

Particularly during depressed market conditions, the early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. When a customer terminates our contract prior to the contract’s scheduled expiration, our contract backlog is also adversely impacted. When we cold stack or expect to scrap a rig, we evaluate the rig for impairment. See “– Contract Drilling Backlog” for future commitments of our rigs during 2017 through 2020.

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Contract Drilling Backlog

The following table reflects our contract drilling backlog as of April 1, 2017 (based on information available at that time), January 1, 2017 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2016), and April 1, 2016 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended March 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 approach 92-98% 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.

In August 2016, our subsidiary received notice of termination of its drilling contract from Petróleo Brasileiro S.A., or Petrobras, the customer for the Ocean Valor. We do not believe that Petrobras had a valid or lawful basis for terminating the contract and in August 2016, we filed a lawsuit in Brazil, claiming that Petrobras’ purported termination of the contract was unlawful and requested an injunction to prohibit the contract termination. In September 2016, a Brazilian court issued a preliminary injunction, suspending Petrobras’ purported termination of the contract and ordering that the contract remain in effect until the end of the term or further court order. Petrobras appealed the granting of the injunction, but in March 2017, the court ruled against Petrobras’ appeal and upheld the injunction. As a result of the favorable ruling, both the injunction and the Ocean Valor contract remain in effect. Petrobras has the right to seek to appeal the ruling to the Superior Court of Justice. We intend to continue to defend our rights under the contract, which is estimated to conclude in accordance with its terms in October 2018. However, litigation is inherently unpredictable, and there can be no assurance as to the ultimate outcome of this matter. The rig is currently on standby earning a reduced dayrate.

The following table reflects the amount of our contract drilling backlog by year as of April 1, 2017.

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The following table reflects the percentage of rig days committed by year as of April 1, 2017. 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).

Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows

Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half years. During the remainder of 2017, we expect to spend approximately 15 days to complete a special survey for the Ocean Monarch and approximately 60 days for a special survey for the Ocean Patriot after completion of its current contract. In addition, we expect to spend approximately 45 days and 65 days during the remainder of 2017 and in 2018, respectively, for contract preparation, customer modifications and the mobilization of the Ocean Monarch to its well location in Australia. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ – Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, 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, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, 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 is $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.

Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. We did not have any construction projects for which we capitalized interest during the first quarter of 2017.

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Critical Accounting Policies

Our significant accounting policies are discussed in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2016. There were no material changes to these policies during the three months ended March 31, 2017.

Results of Operations

Although we perform contract drilling services with different types of drilling rigs 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.

Key performance indicators by equipment type are listed below.

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Comparative data relating to our revenues and operating expenses by equipment type are listed below.

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Overview

Three Months Ended March 31, 2017 and 2016

Operating Income. Operating income for the first quarter of 2017 decreased $60.7 million, or 54%, compared to the same period of 2016. This unfavorable variance was primarily due to an $80.0 million reduction in contract drilling revenue, partially offset by the favorable impacts of lower contract drilling expense ($9.3 million) and depreciation ($11.0 million). The decrease in depreciation expense was primarily due to a lower depreciable asset base in 2017, compared to the first quarter of 2016, as a result of asset impairments taken in 2016.

Contract drilling revenue decreased an aggregate $80.0 million, or 18%, during the first quarter of 2017, compared to the first quarter of 2016, primarily due to lower average daily revenue earned ($68.9 million) and an aggregate 27 fewer revenue-earning days ($11.1 million), reflective of continued weakness in the offshore contract drilling market. Except for our mid-water semisubmersibles, average daily revenue earned decreased compared to the first quarter of 2016, and reflected the absence of $40.0 million in demobilization revenue recognized as a result of the completion of the Ocean Endeavor’s contract in the Black Sea during the first quarter of 2016.

Total contract drilling expense decreased $9.3 million during the first quarter of 2017, compared to the first quarter of 2016. Incremental contract drilling expense for the Ocean GreatWhite ($11.7 million), which began operating during the first quarter of 2017, was more than offset by lower overall operating costs for the fleet, primarily for labor and personnel ($9.8 million), repairs and maintenance ($10.6 million) and an aggregate net decrease in other rig operating and overhead costs ($0.6 million).

Income Tax Expense. Our effective tax rate for the first quarter of 2017 was 3.8%, compared to a (5.1)% effective tax rate for the first quarter of 2016. The variance in effective tax rates between periods was primarily due to the mix of our domestic and international pre-tax earnings and losses, with varying tax consequences, and other discrete adjustments.

Contract Drilling Revenue and Expense by Equipment Type

Three Months Ended March 31, 2017 and 2016

Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters decreased $82.5 million during the first quarter of 2017, compared to the first quarter of 2016, primarily as a result of 71 fewer revenue-earning days ($37.4 million), combined with lower average daily revenue earned ($45.1 million). Revenue-earning days decreased in the first quarter of 2017 compared to the prior year period, primarily due to cold-stacked rigs that had operated during the 2016 period (79 days) and the Ocean Monarch, which was in the shipyard for a survey and contract modifications (75 days). The decrease in revenue-earning days was partially offset by incremental revenue-earning days for the Ocean GreatWhite (77 days) and fewer other non-operating days (6 days). Average daily revenue decreased during the first quarter of 2017, compared to the first quarter of 2016, primarily due to the absence of $40.0 million in demobilization revenue recognized in the first quarter of 2016 for the Ocean Endeavor.

Contract drilling expense for our ultra-deepwater floaters increased $18.1 million during the first quarter of 2017, compared to the first quarter of 2016, primarily due to incremental costs associated with our Pressure Control by the Hour^® program on our drillships ($12.3 million) and incremental contract drilling expense for the Ocean GreatWhite ($11.7 million). Absent these incremental costs, contract drilling expense for our ultra-deepwater floaters decreased $5.9 million in the first quarter of 2017, compared to the prior year quarter, primarily due to the effect of lower costs for labor and personnel ($1.3 million), mobilization of rigs ($1.9 million), agency fees ($1.0 million), shorebase support and overhead ($5.4 million) and other costs ($0.5 million), partially offset by higher inspections costs ($4.2 million), primarily for the Ocean Monarch.

Deepwater Floaters. Revenue generated by our deepwater floaters increased $8.8 million in the first quarter of 2017, compared to the same quarter of 2016, primarily due to 84 incremental revenue-earning days ($28.1 million), partially offset by a reduction in average daily revenue earned ($19.3 million). The increase in revenue-earning days resulted primarily from 90 incremental days for the Ocean Apex, which operated during the first quarter of 2017 under a contract that commenced in the second quarter of 2016. Average daily revenue decreased during the first quarter of 2017, compared to the same period of 2016, primarily as a result of lower mobilization revenue combined with lower average revenue per day earned by the Ocean Valiant and Ocean Victory.

Contract drilling expense for our deepwater floaters decreased $14.4 million during the first quarter of 2017, compared to the same period of 2016, primarily due to a net reduction in costs associated with labor and personnel ($2.7 million), maintenance and repairs ($6.2 million), mobilization of rigs ($2.6 million) and other rig operating and overhead costs ($2.9 million) attributable to various factors, including the cold stacking of rigs and implementation of other cost control measures in 2016.

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Mid-Water Floaters. Revenue generated by our mid-water floaters during the first quarter of 2017 remained stable, increasing $0.6 million compared to the same quarter of 2016, while contract drilling expense decreased $4.6 million. Comparing the periods, only two of our mid-water floaters operated during both quarters, while the remainder of our mid-water fleet remained cold stacked or was sold during 2016. The decrease in contract drilling expense was primarily due a reduction in labor and personnel costs ($4.2 million).

Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $6.9 million and $0.7 million, respectively, during the first quarter of 2017, compared to the prior year quarter. The Ocean Scepter, which had been idle since completing its contract in Mexico in the second quarter of 2016, commenced operations offshore Mexico in February 2017 under a new contract. The decrease in contract drilling revenue was primarily due to 39 fewer revenue-earning days and lower average daily revenue earned during the first quarter of 2017 compared to the prior year period.

Liquidity and Capital Resources

We principally rely on our cash flows from operations and cash reserves to meet our liquidity needs and may also utilize borrowings under our $1.5 billion syndicated revolving credit agreement, or Credit Agreement. See “ – Credit Agreement.”

Based on our cash available for current operations and contractual backlog of $3.2 billion as of April 1, 2017, of which $1.1 billion is expected to be realized during the remainder of 2017, we believe future 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, as needed. See “– Sources and Uses of Cash – Capital Expenditures.”

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC, and, as a result of our intention to indefinitely reinvest the earnings of DFAC and its foreign subsidiaries to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to finance our domestic activities. 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 March 31, 2017 and December 31, 2016, we had cash available for current operations, including cash reserves of DFAC, as follows:

A substantial portion of our cash flows has historically been invested in the enhancement of our drilling fleet. 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. We did not pay any dividends in 2016 or the first quarter of 2017.

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Depending on market and other 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 the three-month periods ended March 31, 2017 and 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

During the three-month period ended March 31, 2017, our primary sources of cash were an aggregate $98.7 million generated by operating activities and $2.1 million from the disposition of assets. Cash usage during the same period was primarily $104.2 million for the net repayment of borrowings under our Credit Agreement and capital expenditures aggregating $29.5 million.

Our cash flow from operations and capital expenditures for the three-month periods ended March 31, 2017 and 2016 were as follows:

Cash Flow from Operations. Cash flow from operations decreased $142.7 million during the first three months of 2017, compared to the first three months of 2016, primarily due to lower cash receipts for contract drilling services ($176.4 million), partially offset by a net decrease in cash payments for contract drilling expenses, including personnel-related, repairs and maintenance, overheads and other rig operating costs ($31.1 million) and lower income taxes paid, net of refunds ($2.7 million). The decline in both cash receipts and cash payments related to the performance of contract drilling services reflects continuing depressed market conditions in the offshore drilling industry, as well as positive results of our continuing focus on controlling costs.

Capital Expenditures. As of the date of this report, we expect total capital expenditures for 2017 to aggregate approximately $145.0 million for our ongoing capital maintenance and replacement programs.

We had no other purchase obligations for major rig upgrades at March 31, 2017.

Other Obligations. As of March 31, 2017, the total net unrecognized tax benefits related to uncertain tax positions was $58.3 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

Credit Agreement

At March 31, 2017, we had no borrowings outstanding under our Credit Agreement, and were in compliance with all covenants thereunder. As of April 27, 2017, we had $1.5 billion available under our Credit Agreement to provide liquidity for our payment obligations.

Credit Ratings

In January 2017, S&P Global Ratings downgraded our corporate credit rating to BB- from BB+, with a negative outlook. Our current corporate credit rating by Moody’s Investor Services is Ba2 with a stable outlook. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered further. A downgrade in our credit ratings could adversely impact our cost of issuing additional debt and

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the amount of additional debt that we could issue, and could further restrict our access to capital markets and our ability to raise additional debt. 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.

Other Commercial Commitments - Letters of Credit

We were contingently liable as of March 31, 2017 in the amount of $38.2 million under certain performance, tax, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $35.2 million of performance, tax, supersedeas, court and customs bonds can require collateral at any time. As of March 31, 2017, 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.

Off-Balance Sheet Arrangements

At March 31, 2017 and December 31, 2016, we had no off-balance sheet debt or other off-balance sheet arrangements.

New Accounting Pronouncements

See Note 1 “General Information” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of recently issued accounting pronouncements.

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, 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:

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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, those described or referenced under “Risk Factors” in Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2016.

The risks and uncertainties referenced above are not exhaustive. Other sections of this report and our other filings with the Securities and Exchange Commission 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. We do so for the convenience of our investors and potential investors and in an effort to provide information available in the market intended to lead to a better understanding of the market environment in which we operate. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

There were no material changes in our market risk components for the three months ended March 31, 2017. See “Quantitative and Qualitative Disclosures About Market Risk” included in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2016 for further information.

Material Weakness Previously Disclosed

As discussed in our 2016 Annual Report on Form 10-K, as of December 31, 2016 we identified a material weakness in the design of our controls over the application of changes in foreign exchange rates when measuring our liability for uncertain tax positions denominated in foreign currencies. These liabilities for uncertain tax positions are considered monetary liabilities and are required to be revalued in accordance with Accounting Standards Codification 830 – Foreign Currency Matters. We had historically utilized a manual (non-system) calculation to

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revalue our foreign liability for uncertain tax positions, as appropriate. Prior to the completion of our year-end financial reporting process for fiscal year 2016, it was discovered that our revaluation of our liability for uncertain tax positions did not properly reflect appropriate changes for current foreign exchange rates. This omission resulted in an improper measurement of certain of our liabilities for uncertain tax positions. As a result, we concluded that we failed to adequately design and operate our internal controls over the application of changes in foreign exchange rates in revaluation of liabilities for foreign uncertain tax positions to mitigate the risk of a material error.

Evaluation of Disclosure Controls and Procedures

We maintain a system of disclosure controls and procedures that are designed to ensure that 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 Rules 13a-15(e) and 15d-15(e)) as of March 31, 2017. Based on their participation in that evaluation, our CEO and CFO concluded that, as of March 31, 2017, our disclosure controls and procedures were not effective due to a material weakness in our internal control over financial reporting as discussed above. Because of this material weakness, we performed additional procedures to evaluate our unaudited condensed consolidated financial statements as of and for the quarter ended March 31, 2017. Notwithstanding the material weakness in our internal control over financial reporting as of March 31, 2017, management believes that our unaudited condensed consolidated financial statements included in Item 1 of Part I of this Form 10-Q present fairly, in all material respects, our financial position, results of operations and cash flows as of the dates, and for the periods, presented, in conformity with accounting principles generally accepted in the United States.

Remediation Efforts

We have designed and implemented new controls to remediate the underlying cause of the material weakness discussed above. Specifically, during the first fiscal quarter of 2017, we implemented the following actions:

We are currently in the process of testing the operational effectiveness of the actions discussed above. We believe the measures described above will remediate the material weakness we have identified and generally strengthen our internal control over financial reporting. As we continue to evaluate and work to improve our internal control over financial reporting, we may decide to take additional measures to address control deficiencies or determine to modify certain of the remediation measures described above. We will continue to monitor the effectiveness of these and other processes, procedures and controls and will make any further changes that management determines are appropriate.

Changes in Internal Control over Financial Reporting

We have taken actions to remediate the material weakness in our internal control over financial reporting, as described above. Except as described herein, there were no changes in our internal control over financial reporting that occurred during our first fiscal quarter of 2017 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Information related to certain legal proceedings is included in Note 6 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Our Annual Report on Form 10-K for the year ended December 31, 2016 includes a detailed discussion of certain material risk factors facing our company. No material changes have been made to such risk factors as of March 31, 2017.

Items 2(a) and 2(b) are not applicable.

(c) During the three months ended March 31, 2017, in connection with the vesting of restricted stock units held by our chief executive officer, 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

See the Exhibit Index for a list of those exhibits filed or furnished herewith.

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SIGNATURES

Pursuant to the requirements 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.

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EXHIBIT INDEX

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