DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2016 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

For the quarterly period ended June 30, 2016

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  þ    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  þ    No  ¨

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

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

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

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DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2016

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PART I. FINANCIAL INFORMATION

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share data)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Unaudited)

(In thousands)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

1. General Information

The unaudited 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, 2015 (File No. 1-13926).

As of July 27, 2016, Loews Corporation owned approximately 53% of the outstanding shares of our common stock.

Interim Financial Information

The accompanying unaudited 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 consolidated financial information has not been audited but, in the opinion of management, includes all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of Diamond Offshore’s 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.

Assets Held For Sale

At December 31, 2015, we reported the $14.2 million carrying value of five marketed-for-sale jack-up rigs as “Assets held for sale” in our Consolidated Balance Sheets. One of these rigs was sold for $8.0 million in February 2016. The $6.2 million aggregate carrying value of the four remaining marketed-for-sale jack-up rigs is reported as “Assets held for sale” in our Consolidated Balance Sheets at June 30, 2016.

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 six-month period ended June 30, 2016 and the year ended December 31, 2015, we capitalized $63.0 million and $262.4 million, respectively, in replacements and betterments of our drilling fleet. See Notes 2 and 8.

Capitalized Interest

We capitalize interest cost for qualifying construction and upgrade projects. See Note 8. 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:

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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 probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:

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 the rig’s future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance, inspection and reactivation costs, are estimated using historical data adjusted for known developments, cost projections for re-entry of rigs into the market and future events that are anticipated by management at the time of the assessment.

Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Management’s assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and management’s expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different. See Note 2.

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Debt Issuance Costs

Historically, we have presented deferred costs associated with the issuance of long-term debt as “Other Assets” in our unaudited consolidated balance sheets and have amortized such costs over the respective terms of the related debt. In April 2015, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2015-03, Interest—Imputation of Interest (Subtopic 835-30); Simplifying the Presentation of Debt Issuance Costs, or ASU 2015-03, which requires debt issuance costs associated with our senior notes to be presented in the balance sheet as a reduction in the related long-term debt. We have adopted the provisions of ASU 2015-03 effective January 1, 2016 and have retrospectively applied its provisions to all periods presented in our Consolidated Financial Statements. The retrospective effect of our adoption of ASU 2015-03, which affected only the presentation of deferred debt issuance costs in our Consolidated Balance Sheets at December 31, 2015, is as follows:

Recent Accounting Pronouncements

In March 2016, the FASB issued ASU No. 2016-09, Compensation—Stock Compensation (Topic 718), or ASU 2016-09, which simplifies several aspects of the accounting for share-based payment transactions. The new guidance makes several modifications to the accounting for forfeitures, employer tax withholding on share-based compensation and the financial statement presentation of excess tax benefits or deficiencies. In addition, ASU 2016-09 clarifies the statement of cash flows presentation for certain components of share-based awards. The guidance of ASU 2016-09 is effective for interim and annual reporting periods beginning after December 15, 2017. Earlier adoption is permitted. We are currently evaluating the provisions of ASU 2016-09 and have not yet determined the impact on our financial position, results of operations or cash flows.

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. The guidance of ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, and may be adopted using a retrospective or modified retrospective approach.

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 nonlease 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. Nonlease 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 are evaluating the provisions of ASU 2016-02 concurrently with the provisions of ASU 2014-09. We have not yet determined the impact of these ASUs on our financial position, results of operations or cash flows.

2. Asset Impairments

2016 Impairments - During the second quarter of 2016, in response to the continuing decline in industry-wide utilization for semisubmersible rigs, further exacerbated by additional and more frequent contract cancelations by customers, declining dayrates, as well as the output of a third-party strategic review of our long-term business plan completed in the second quarter of 2016, we reassessed our projections for a recovery in the offshore drilling market. As a result, we concluded that an expected market recovery is now likely further in the future than had

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previously been estimated. Consequently, we believe our cold-stacked rigs, as well as those rigs that we expect to cold stack in the near term after they come off contract, will likely remain cold stacked for an extended period of time. We also believe that the re-entry costs for these rigs will be higher than previously estimated, negatively impacting the undiscounted, projected probability-weighted cash flow projections utilized in our impairment analysis. In addition, in response to the declining market, we have also reduced anticipated market pricing and expected utilization of these rigs after reactivation.

In the second quarter of 2016, we evaluated 15 of our drilling rigs with indications that their carrying amounts may not be recoverable. Based on our updated assumptions and analyses, we determined that the carrying values of eight of these rigs, consisting of three ultra-deepwater, three deepwater and two mid-water semisubmersible rigs, were impaired (we collectively refer to these eight rigs as the “2016 Impaired Rigs”).

We estimated the fair value of the 2016 Impaired Rigs using an income approach. 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, which 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 the rig. 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

As of June 30, 2016, there were seven rigs in our drilling fleet for which there were no indications that their carrying amounts may not be recoverable and, thus, were not evaluated for impairment at that time. If market fundamentals in the offshore oil and gas industry deteriorate further, we may be required to recognize additional impairment losses in future periods.

2015 Impairments - During the first quarter of 2015, we evaluated 17 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 eight of these rigs, consisting of seven mid-water floaters and our older 7,875-foot water depth rated drillship, were impaired (we collectively refer to these eight rigs as the “1st Quarter 2015 Impaired Rigs”).

We estimated the fair value of five of the 1st Quarter 2015 Impaired Rigs that were cold stacked utilizing a market approach, which required us to estimate the value that would be received for each rig in the principal or most advantageous market for that rig in an orderly transaction between market participants. Such estimates were based on various inputs, including historical contracted sales prices for similar rigs in our fleet, nonbinding quotes from rig brokers and/or indicative bids. We estimated the fair value of the three remaining 1st Quarter 2015 Impaired Rigs using an income approach, as discussed 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.

We recognized an impairment loss aggregating $358.5 million during the first quarter of 2015 to write down these rigs to their estimated recoverable amounts. Subsequent to the first quarter of 2015, we evaluated an additional eight drilling rigs, as well those rigs initially evaluated in the first quarter of 2015 that we had determined not to be impaired, for impairment. As a result of these evaluations, we determined that the carrying value of an additional nine drilling rigs, consisting of one ultra-deepwater, one deepwater and two mid-water semisubmersible rigs and five jack-up rigs, was not recoverable and recorded additional impairment losses of $2.6 million and $499.4 million in the third and fourth quarters of 2015, respectively.

Of the 17 rigs impaired during 2015, six mid-water semisubmersible rigs, our older drillship and one marketed-for-sale jack-up rig have been sold. At June 30, 2016, 14 of the remaining rigs impaired during 2015 and 2016 were cold stacked, including four jack-up rigs that are marketed for sale. Two of the 2016 Impaired Rigs are currently contracted by customers. Subsequent to June 30, 2016, our management announced a plan to sell two of the cold-stacked 2016 Impaired Rigs for scrap value.

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3. Supplemental Financial Information

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:

During the three-month and six-month periods ended June 30, 2016, we recognized an $8.1 million impairment loss related to our rig spare parts and supplies.

Accrued liabilities consist of the following:

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Consolidated Statements of Cash Flows Information

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

4. Earnings Per Share

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

The following table sets forth the share effects of stock-based awards excluded from our computations of diluted earnings per share, or EPS, as the inclusion of such potentially dilutive shares would have been anti-dilutive for the periods presented:

5. Marketable Securities

We report our investments as current assets in our Consolidated Balance Sheets in “Marketable securities,” representing the investment of cash available for current operations. See Note 7.

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Our investments in marketable securities are classified as available for sale and are summarized as follows:

In June 2016, we sold our investment in corporate bonds for proceeds of $4.6 million and recognized a loss of $12.9 million, including $0.8 million in accrued interest, which we do not expect to collect.

Proceeds from maturities and sales of mortgage-backed securities and the related gains and losses during the three-month and six-month periods ended June 30, 2016 and 2015 were not significant.

6. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

During the six months ended June 30, 2015, we settled foreign currency forward exchange, or FOREX, contracts with aggregate notional values of approximately $88.8 million, of which the entire aggregate amount was designated as a cash flow accounting hedge. We did not settle any FOREX contracts during the six months ended June 30, 2016 and had no FOREX contracts outstanding at June 30, 2016 or December 31, 2015.

During the three-month and six-month periods ended June 30, 2015, we recognized aggregate losses of $1.5 million and $7.9 million, respectively, related to our FOREX contracts designated as accounting hedges. We have presented these amounts within “Contract drilling expense, excluding depreciation” in our Consolidated Statements of Operations.

The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our derivative financial instruments designated as cash flow hedges for the three-month and six-month periods ended June 30, 2015. In the table, AOCGL refers to accumulated other comprehensive gain (loss).

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During the six-month period ended June 30, 2015, we did not reclassify any amounts from AOCGL due to the probability of an underlying forecasted transaction not occurring.

7. Financial Instruments and Fair Value Disclosures

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.

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, as well as the number of rigs currently working in a geographic area, we do not believe that we have any significant concentrations of credit risk at June 30, 2016.

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:

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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 and six-month periods ended June 30, 2016 and 2015.

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 rig spare parts and supplies, which were measured at fair value on a nonrecurring basis during the three-month periods ended March 31, 2015, September 30, 2015, December 31, 2015 and June 30, 2016 of $358.5 million, $2.6 million, $499.4 million and $678.1 million, respectively.

Assets and liabilities measured at fair value are summarized below:

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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:

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 June 30, 2016 and December 31, 2015. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day period of the report date. Fair values and related carrying values of our senior notes 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.

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8. Drilling and Other Property and Equipment

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

During the three-month and six-month periods ended June 30, 2016, we recognized an aggregate impairment loss of $670.0 million related to the 2016 Impaired Rigs. See Notes 1 and 2.

See Note 13 for a discussion of three sale and leaseback transactions that were executed during the six-month period ended June 30, 2016.

Construction work-in-progress, including capitalized interest, at June 30, 2016 and December 31, 2015 was $716.3 million and $269.6 million, respectively, attributable to the Ocean GreatWhite, a 10,000 foot dynamically positioned, harsh environment semisubmersible drilling rig, which was delivered by Hyundai Heavy Industries Co., Ltd., or HHI, in July 2016. We expect to place the rig in service in the third quarter of 2016 after completion of a rig enhancement project.

9. Credit Agreement, Commercial Paper and Credit Ratings

In February 2016, Moody’s Investors Service, or Moody’s, downgraded our senior unsecured credit rating to Ba2 from Baa2, with a stable outlook, and also downgraded our short-term credit rating to sub-prime. In July 2016, S&P Global Ratings (formerly Standard & Poor’s Ratings Services) downgraded our senior unsecured credit rating to BBB from BBB+; the outlook remains negative.

As a result of the Moody’s downgrade, we canceled our commercial paper program due to our inability to access the commercial paper market in the foreseeable future and no longer obtain a short-term credit rating from either rating agency. In addition, based on our current credit ratings, the applicable interest rate for alternate base rate loans under our revolving credit agreement is 0.25% over the greater of (i) the prime rate, (ii) the federal funds rate plus 0.50% and (iii) the daily one-month Eurodollar Rate plus 1.00%. The applicable interest rate for Eurodollar loans under our revolving credit agreement is currently 1.25% over British Bankers’ Association LIBOR. The applicable commitment fee is 0.20%, and the participation fee for performance letters of credit is 0.625%.

In January 2016, we repaid the $286.6 million in commercial paper notes outstanding at December 31, 2015 with proceeds from short-term borrowings under our revolving credit agreement. At June 30, 2016, we had $327.3 million in short-term borrowings outstanding under our revolving credit agreement. These short-term borrowings bore interest at a weighted average interest rate of 3.4%.

As of July 27, 2016, we had $270.0 million in short-term borrowings outstanding and an additional $1.2 billion available under our revolving credit agreement.

10. Commitments and Contingencies

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

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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 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 since 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 have filed appropriate motions to dismiss these claims. 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. We continue to pursue all 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, 2016, 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 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 June 30, 2016 our estimated liability for personal injury claims was $38.9 million, of which $6.0 million and $32.9 million were recorded in “Accrued

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liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2015 our estimated liability for personal injury claims was $40.4 million, of which $8.2 million and $32.2 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:

Purchase Obligations. In June 2016, we funded the final payment to HHI totaling $402.5 million in final settlement of the contract price for the Ocean GreatWhite, excluding $4.2 million in post-delivery items. The Ocean GreatWhite was delivered in mid-July 2016. We will complete a rig enhancement project in Singapore before placing the rig in service. We expect the rig enhancement project to be completed in the third quarter of 2016.

At June 30, 2016, we had no other 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. See Note 13.

Letters of Credit and Other. We were contingently liable as of June 30, 2016 in the amount of $53.6 million under certain performance, supersedeas, bid, tax and customs bonds and letters of credit. Agreements relating to approximately $48.5 million of performance, tax, supersedeas, court and customs bonds can require collateral at any time. As of June 30, 2016, 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.

11. Accumulated Other Comprehensive Gain (Loss)

The components of our AOCGL and related changes thereto are as follows:

The following table presents the line items in our Consolidated Statements of Operations affected by reclassification adjustments out of AOCGL.

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12. Restructuring and Separation Costs

In early 2015, in response to the continuing decline in the offshore drilling market, 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 Corporate Reduction Plan. We recognized $1.0 million and $7.2 million in restructuring and employee separation related costs for the three-month and six-month periods ended June 30, 2015, respectively. Substantially all costs associated with the Corporate Reduction Plan had been paid as of June 30, 2015.

13. Sale and Leaseback Transaction

In February 2016, we entered into a ten-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 newly-built 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 agreed to sell the Well Control Equipment to another GE affiliate and subsequently lease back such equipment pursuant to separate ten-year operating leases.

During the six months ended June 30, 2016, we executed three sale and leaseback transactions with respect to the Well Control Equipment on the Ocean BlackHawk, Ocean BlackHornet and Ocean BlackLion. As a result of these transactions, we received an aggregate $157.5 million in proceeds from the sale of the Well Control Equipment on these rigs, 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, and will be amortized over the respective terms of the operating leases. We simultaneously executed three ten-year operating lease and contractual services agreements with respect to the Well Control Equipment. Future commitments under the operating leases and contractual services agreements for the Ocean BlackHawk, Ocean BlackHornet and Ocean BlackLion are estimated to be approximately $49.0 million per year or an aggregate $491.0 million over the term of the agreements. We expect to complete the remaining sale and leaseback transaction for the Ocean BlackRhino in the third quarter of 2016.

14. Income Taxes

Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned and operated, directly or indirectly, by one of our wholly owned foreign subsidiaries. It is our intention to indefinitely reinvest future earnings of this subsidiary to finance foreign activities. Accordingly, we have not made a provision for U.S. income taxes on such earnings except to the extent that such earnings were immediately subject to U.S. income taxes.

At December 31, 2015 we had recorded a deferred tax asset of $33.7 million for the benefit of foreign tax credits in the U. S. which we expected to utilize prior to their expiration in 2024 and 2025. As of June 30, 2016, due to revised financial forecasts as a result of worsening market conditions for the offshore drilling industry, including expectations that a market recovery is now further in the future than previously estimated, we no longer expect to be able to realize certain future tax benefits. Accordingly, we have established a valuation allowance of $33.7 million for the prior year deferred tax asset, as well as a $43.6 million valuation allowance for the deferred tax asset for the benefit of foreign tax credits arising in 2016 that we do not expect to be able to utilize prior to their expiration.

15. Segments and Geographic Area Analysis

Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue earning process as it relates to the offshore drilling industry over the operating lives of our drilling rigs.

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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 June 30, 2016, our actively-marketed drilling rigs were en route to or located offshore in four 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 consolidated financial statements (including the notes thereto) included elsewhere in this report and our audited consolidated financial statements and 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, 2015. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We provide contract drilling services worldwide with a fleet of 28 offshore drilling rigs. Our current fleet consists of 19 semisubmersibles, five jack-up rigs, including four jack-up rigs that we are marketing for sale, and four dynamically positioned drillships. Our harsh environment, ultra-deepwater semisubmersible rig, the Ocean GreatWhite, was delivered in mid-July 2016 and has mobilized to Singapore for a rig enhancement project. We expect the Ocean GreatWhite to commence its contract offshore Australia in the fourth quarter of this year. Additionally, in July 2016, we reached a decision to sell the Ocean Quest and Ocean Star for scrap value.

Market Overview

Overall fundamentals in the offshore oil and gas industry have continued to deteriorate. Oil prices, which had fallen to a 12-year low below $30 per barrel in January 2016, had rebounded to the upper $40 per barrel range as of June 30, 2016, but continue to exhibit day-to-day volatility due to multiple factors, including fluctuations in the current and expected level of global oil inventories. Despite the increase in oil prices during the second quarter of 2016, industry reports indicate that utilization for floaters continues to fall at a rate of approximately 5% per quarter and cancelation of contracts for deepwater rigs has persisted. Significant operating losses incurred during 2015 and 2016 by many independent and national oil companies and exploration and production companies, as well as an uncertain outlook with respect to future demand for oil and gas and the resulting price instability, have resulted in significantly reduced capital spending plans for 2016 and possibly beyond, as operators struggle to stay cash neutral in the current oil price environment. Customer inquiries for rig availability and new tenders have continued to decline in 2016, as compared to prior years. The majority of our recent customer discussions related to new projects are for work that materializes in 2018 and later.

Based on industry reports, since 2014, approximately 55 floater rigs have been retired and others have been cold stacked, slightly abating the current oversupply of drilling rigs. However, the number of available rigs continues to grow as contracted rigs come off contract and newly-built rigs are delivered. Competition for the limited number of drilling jobs continues to be intense. In some cases, dayrates have been negotiated at near break-even levels to provide for the recovery of operating costs for rigs that would otherwise be uncontracted or cold stacked. Market studies indicate that dayrates for sixth- generation rigs have declined on average by double digits during the second quarter of 2016, compared to the fourth quarter of 2015. Industry analysts have predicted that the offshore contract drilling market may remain depressed with further declines in dayrates and utilization likely in 2016 and 2017.

As a result of the continuing and worsening market conditions for 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 could include requests to lower the contract dayrate, lowering of a dayrate in exchange for additional contract term, shortening the term on one contracted rig in exchange for additional term on another rig, early termination of a contract in exchange for a lump sum margin 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 contractually specified termination amount, which may not fully compensate us for the loss of the contract. As a result of these depressed market conditions, certain 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.

On April 28, 2016, our subsidiary’s agent in Mexico received a letter from PEMEX – Exploración y Producción, or PEMEX, exercising its contractual right to terminate its drilling contract on the Ocean Scepter with 30 days’ advance notice, resulting in the early termination of the contract on May 28, 2016. Industrywide, during the first half of 2016, industry reports indicate that customers canceled 21 contracts for floater rigs, compared to 31 contract cancelations for deepwater drilling rigs during the full year 2015. 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.

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The continuation of these conditions for an extended period could result in more of our rigs being without contracts and/or cold stacked or scrapped and could further materially and adversely affect our financial condition, results of operations and cash flows. When we cold stack or expect to scrap a rig, we evaluate the rig for impairment. We currently expect that these adverse market conditions will continue for the foreseeable future. As of August 1, 2016, 17 rigs in our fleet were cold stacked, including four jack-up rigs that are currently being marketed for sale. See “– Contract Drilling Backlog” for future commitments of our rigs during 2016 through 2020.

Although these general market conditions impact all segments of the offshore drilling market, the following discussion addresses market conditions within segments of the floater market.

Floater Markets

Ultra-Deepwater and Deepwater Floaters. Globally, the ultra-deepwater and deepwater floater markets continue to worsen. Diminished or nonexistent demand, combined with an oversupply of rigs, has caused floater dayrates to decline significantly. Industry analysts expect offshore drillers to continue to scrap older, lower specification rigs; however, newer and higher specification rigs have also been impacted by the recycling trend.

In an effort to manage the oversupply of rigs and potentially avoid the cost of cold stacking newly-built rigs, which, in the case of dynamically-positioned rigs, can be significant, several drilling contractors have exercised options to delay the delivery of rigs by the shipyard or have exercised their right to cancel orders due to the late delivery of rigs. As of the date of this report, industry data indicates that there are approximately 37 competitive, or non-owner-operated, newbuild floaters on order, of which only three rigs are reported to be contracted for future work. Of the 37 rigs on order, 13 and 15 rigs are scheduled for delivery in the remainder of 2016 and in 2017, respectively. The remaining nine rigs are scheduled for delivery between 2018 and 2020. Industry analysts predict that delivery dates may shift further as newbuild owners negotiate with their respective shipyards.

Mid-Water Floaters. While conditions in the mid-water market vary slightly by region, mid-water rigs have been adversely impacted by (i) lower demand, (ii) declining dayrates, (iii) increased regulatory requirements, including more stringent design requirements for well control equipment, which could significantly increase the capital needed to comply with design requirements that would permit such rigs to work in the U.S. Gulf of Mexico, or GOM, (iv) the challenges experienced by lower specification units in this segment as a result of more complex customer specifications and (v) the intensified competition resulting from the migration of some deepwater and ultra-deepwater units to compete against mid-water units. To date, the mid-water market has seen the highest number of cold-stacked and scrapped rigs. Since 2012, we have sold 12 of our mid-water rigs for scrap. As market conditions remain challenging, we expect higher-specification rigs to take the place of lower-specification units, where possible, leading to additional lower-specification rigs being cold stacked or ultimately scrapped. Our current mid-water fleet consists of six drilling rigs, of which only two units are currently operating under contract.

GOM Floaters. On April 14, 2016, the Bureau of Safety and Environmental Enforcement, or BSEE, issued its final well control regulations, which have now become effective, although, several of the new requirements have extended timeframes for compliance. The final rule addresses the full range of systems and equipment associated with well control operations, focusing on requirements for blowout preventers, or BOPs, well design, well control casing, cementing, real-time monitoring and subsea containment. The regulations combine prescriptive and performance-based measures to cultivate a greater culture of safety for both oil and gas companies and offshore rig operators that minimizes risk. Key features of the well control regulations include requirements for BOPs, double shear rams, third-party reviews of equipment, real-time monitoring data, safe drilling margins, centralizers, inspections and other reforms related to well design and control, casing, cementing and subsea containment.

The issuance of these rules could result in the future retirement of older, less capable rigs, for which compliance with the new requirements is not physically or economically feasible. Additionally, some analysts predict that the new rules will drive the continued preference for modern floaters when drilling opportunities present. See “— Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows.”

Our results of operations and cash flows for the quarter ended June 30, 2016 have been negatively impacted by the continuing and worsening market conditions in the offshore drilling industry, as discussed above. See “— Results of Operations” and “— Liquidity and Capital Resources” and Notes 1 and 2 to our unaudited consolidated financial statements included in Item 1 of Part I of this report.

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Contract Drilling Backlog

The following table reflects our contract drilling backlog as of August 1, 2016, February 16, 2016 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2015), and July, 1 2015 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2015). 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.

The following table reflects the amount of our contract drilling backlog by year as of August 1, 2016.

The following table reflects the percentage of rig days committed by year as of August 1, 2016. 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). Total available days have been calculated based on the expected contract start date for the Ocean GreatWhite, which is under construction.

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

Regulatory Surveys, Planned Downtime and Regulatory Compliance. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. 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.”

As previously discussed, BSEE’s final well control regulations became effective in July 2016. We are currently assessing the final rules and have not yet determined the costs to comply with the additional requirements to enable our drilling rigs to be eligible to operate in U.S. waters.

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the GOM. If a named windstorm in the GOM 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, 2016, we carry physical damage insurance for certain losses other than those caused by named windstorms in the GOM 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, 2016, 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., or GAAP. 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. During the first half of 2016, we capitalized interest of $7.2 million related to the construction of the Ocean GreatWhite and will continue capitalizing interest on this project until completion of its enhancement project, which we expect to occur in the third quarter of 2016.

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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, 2015. There were no material changes to these policies during the three months ended June 30, 2016.

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 among all our divisions and locations, including the nature of services provided and the type of customers for our services. 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.