DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2015 September (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 September 30, 2015

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  x    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  x    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  x

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

As of October 26, 2015      Common stock, $0.01 par value per share              137,158,706 shares

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DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED SEPTEMBER 30, 2015

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

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, 2014 (File No. 1-13926).

As of October 26, 2015, Loews Corporation owned 53.3 % 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 only of normal recurring accruals) necessary for a fair presentation of the 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.

Cash and Cash Equivalents

We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.

The effect of exchange rate changes on cash balances held in foreign currencies was not material for each of the three-month and nine-month periods ended September 30, 2015 and 2014.

Marketable Securities

We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in “Accumulated other comprehensive gain (loss),” or AOCGL, until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in our Consolidated Statements of Operations in “Interest income.” The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method. Realized gains or losses, as well as any declines in value that are judged to be other than temporary, are reported in our Consolidated Statements of Operations in “Other income (expense) — Other, net.” See Note 6.

Derivative Financial Instruments

Our derivative financial instruments consist primarily of foreign currency forward exchange, or FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative contract is stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for and is designated as an accounting hedge, the gains and losses are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions. Designated hedges are expected to be highly effective, and therefore, adjustments to record the carrying value of the effective portion of our derivative financial instruments to their fair value are recorded as a component of AOCGL in our Consolidated

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Balance Sheets. The effective portion of the cash flow hedge will remain in AOCGL until it is reclassified into earnings in the period or periods during which the hedged transaction affects earnings or it is determined that the hedged transaction will not occur. We report such realized gains and losses as a component of “Contract drilling, excluding depreciation” expense in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate. See Note 12.

Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value and realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations. See Notes 7 and 8.

Drilling and Other Property and Equipment

We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the nine months ended September 30, 2015 and the year ended December 31, 2014, we capitalized $217.8 million and $546.0 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $215 million per project.

Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed and the rig is ready for its intended use. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations as “Loss (gain) on disposition of assets.” Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from three to 30 years.

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, 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 its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment.

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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.

Capitalized Interest

We capitalize interest cost for qualifying construction and upgrade projects. See Note 9. 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:

Foreign Currency

Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses are reported as “Foreign currency transaction gain (loss)” in our Consolidated Statements of Operations and include, when applicable, unrealized gains and losses to record the carrying value of our FOREX contracts not designated as accounting hedges, as well as realized gains and losses from the settlement of such contracts. For the three-month and nine-month periods ended September 30, 2015, we recognized net foreign currency transaction gains (losses) of $(1.2) million and $1.0 million, respectively. For the three-month and nine-month periods ended September 30, 2014, we recognized net foreign currency transaction gains (losses) of $0.4 million and $(3.7) million, respectively. See Note 7.

Revenue Recognition

We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (on either a lump-sum or dayrate basis) for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each on a straight-line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.

Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a lump-sum or dayrate basis). These fees are generally earned as services are performed over the initial term of the related drilling contracts. We defer contract preparation fees received as well as direct and incremental costs associated with the contract preparation activities and amortize each, on a straight-line basis, over the term of the related drilling contracts (which we estimate to be benefited from the contract preparation activity).

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From time to time, we may receive fees from our customers for capital improvements to our rigs (on either a lump-sum or dayrate basis). We defer such fees received in “Accrued liabilities” and “Other liabilities” in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.

We record reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement, for the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our Consolidated Statements of Operations.

Recent Accounting Pronouncements

In July 2015, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, or ASU 2015-11, which requires an entity to measure inventory within the scope of the ASU at the lower of cost and net realizable value. The amendments in ASU 2015-11 are effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Earlier adoption is permitted. We are currently evaluating the provisions of ASU 2015-11 and have not yet determined its 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 also provides for additional disclosure requirements. In July 2015, the FASB issued ASU No. 2015-14, which deferred the effective date of ASU 2014-09. The guidance in 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. Early adoption is permitted. We are currently evaluating the provisions of ASU 2014-09 and have not yet determined its impact on our financial position, results of operations or cash flows.

2. Asset Impairments

During the first quarter of 2015, in response to pending regulatory requirements in the U.S. Gulf of Mexico, as well as the continued deterioration of the market fundamentals in the oil and gas industry, including the dramatic decline in oil prices, significant cutbacks in customer capital spending plans and contract cancelations by customers, we evaluated all drilling rigs in our fleet with indications that their carrying amounts may not be recoverable (e.g., cold stacked or expected to be cold stacked in the near term; see Note 1). Using the undiscounted projected probability-weighted cash flow analysis described in Note 1, we determined that the carrying values of seven of our mid-water semisubmersibles, as well as our older, 7,875-foot water depth rated drillship were impaired at March 31, 2015.

We determined the fair value of five of the rigs in the impairment group using a market approach, which utilized the most recent contracted sales price for another of our previously impaired mid-water semisubmersible rigs. We determined the fair value of the three remaining rigs (which were under contract with a customer at that time) using an income approach, which utilized significant unobservable inputs, including assumptions related to estimated dayrate revenue, rig utilization and anticipated costs for the remainder of the current contract, as well as estimated proceeds that may be received on disposition of each rig. We consider each of these methodologies to be 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 third quarter of 2015, we evaluated 13 drilling rigs with indications that their carrying amounts may not be recoverable and that were not previously impaired, including four additional rigs that did not have prior indicators of impairment as noted above, and determined that further impairment of our fleet had not occurred. However, after receipt of offers in October 2015 to sell three drilling rigs, consisting of one semisubmersible rig and our 7,875-foot water depth rated drillship, both of which were previously impaired, and one cold-stacked jack-up rig, we recorded an aggregate impairment loss of $2.6 million during the third quarter of 2015 to write down the carrying value of

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each of these rigs to their expected selling price, which we also consider to be Level 3 fair value measurements. The sale of these rigs is currently being negotiated. As a result of our valuations, we recognized impairment losses aggregating $361.1 million for the first nine months of 2015.

Of the rigs impaired during 2015, four semisubmersible rigs have been sold for scrap and another three rigs are currently cold stacked. The two remaining rigs in the impairment group are under contract with customers and are expected to be sold for scrap at the end of their respective contracts. The aggregate fair value of the rigs in the impairment group was $8.7 million at September 30, 2015, of which $6.7 million is reported as “Asset held for sale” and $2.0 million is reported in “Drilling and other property and equipment, net of accumulated depreciation” in our Consolidated Balance Sheets. See Notes 8 and 9.

During the three-month and nine-month periods ended September 30, 2014, we recognized an impairment loss of $109.5 million related to six mid-water semisubmersible rigs, for which we had initiated a plan to retire and scrap. All of these rigs were subsequently sold for scrap.

Management’s assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation. The use of different assumptions could produce results that differ from those reported. The actual amount realized upon disposition of our drilling rigs may vary if, or when, such rigs are sold.

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:

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Accrued liabilities consist of the following:

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. Stock-Based Compensation

In April 2015, we granted an aggregate of 311,145 restricted stock units, or RSUs, to employees under our Equity Incentive Compensation Plan, or Equity Plan, collectively referred to as the 2015 RSUs. RSUs are contractual rights to receive shares of our common stock in the future if the applicable vesting conditions are met. Our 2015 RSUs included both performance-vesting and time-vesting RSUs. Under the terms of the 2015 awards, the performance-vesting 2015 RSUs vest upon achievement of certain performance goals as set forth in the individual award agreements over the performance period from January 1, 2015 to December 31, 2017, and the shares of our common stock to be received upon the vesting of the performance-vesting RSUs will be delivered no later than March 15, 2018. 50% of the time-vesting 2015 RSUs will vest on April 1, 2017 and 50% will vest on April 1, 2018, conditioned upon continued employment through the applicable vesting date.

2015 RSUs awarded under the Equity Plan are summarized as follows:

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We recognized compensation expense of $0.8 million and $1.7 million for the three-month and nine-month periods ended September 30, 2015, respectively, in connection with RSUs awarded under our Equity Plan. In connection with RSUs awarded in 2014, we recognized $0.2 million and $0.5 million in compensation expense for the three-month and nine-month periods ended September 30, 2014, respectively.

During the nine months ended September 30, 2015, we issued an aggregate of 107,750 stock appreciation rights to our board of directors and certain employees under the Equity Plan.

5. 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 antidilutive for the periods presented:

6. 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 8.

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

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Proceeds from maturities and sales of marketable securities are summarized as follows:

Gross realized gains and losses from the sale of marketable securities for the three-month and nine-month periods ended September 30, 2015 and 2014 were not significant.

7. Derivative Financial Instruments

Foreign Currency Forward Exchange Contracts

Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. From time to time, we may utilize FOREX contracts to manage our foreign exchange risk. Our FOREX contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.

We enter into FOREX contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign currency gains and losses on future foreign currency expenditures. The amount and duration of such contracts are based on our monthly forecast of expenditures in the significant currencies in which we do business and for which there is a financial market. Historically we have entered into FOREX contracts for future delivery of Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner. These forward contracts are derivatives as defined by GAAP.

During the nine months ended September 30, 2015 and 2014, we settled FOREX contracts with aggregate notional values of approximately $91.6 million and $233.9 million, respectively, of which the entire aggregate amounts were designated as a cash flow accounting hedge. There were no FOREX contracts outstanding at September 30, 2015.

The following table presents the aggregate amount of gain or loss recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as accounting hedges for the three-month and nine-month periods ended September 30, 2015 and 2014.

The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at September 30, 2015 and December 31, 2014.

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 nine-month periods ended September 30, 2015 and 2014.

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As of September 30, 2015, the estimated amount of net unrealized gains associated with our treasury lock agreements that will be reclassified to interest expense during the next twelve months was $8,052. During the nine-month periods ended September 30, 2015 and 2014, we did not reclassify any amounts from AOCGL due to the probability of an underlying forecasted transaction not occurring.

8. 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.

Most of our investments in debt securities are securitized corporate bonds whereby our credit risk is mitigated by the collateral. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.

Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. At September 30, 2015 and December 31, 2014, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government), or Petrobras, accounted for $74.1 million and $123.3 million, or 16% and 29%, respectively, of our total consolidated net trade accounts receivable balance.

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.

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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 and nine-month periods ended September 30, 2015 and 2014.

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 assets measured at fair value on a nonrecurring basis during the three-month and nine-month periods ended September 30, 2015 of $2.6 million and $361.1 million, respectively. We recorded impairment charges related to assets measured at fair value on a nonrecurring basis of $109.5 million during the three-month and nine-month periods ended September 30, 2014.

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

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We consider our senior notes, including current maturities, to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service at September 30, 2015 and December 31, 2014. 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.

9. Drilling and Other Property and Equipment

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

During the nine months ended September 30, 2015, we sold eight rigs with an aggregate net book value of $4.4 million for scrap and recognized an aggregate gain on disposition of $0.2 million and $1.0 million for the three-month and nine-month periods ended September 30, 2015, respectively. In addition, during the nine-month period ended September 30, 2015, we recognized an impairment loss of $361.1 million. See Note 2.

Construction work-in-progress, including capitalized interest, at September 30, 2015 and December 31, 2014 is summarized as follows:

The Ocean BlackLion was placed in service in June 2015 and is no longer reported as construction work-in-progress at September 30, 2015.

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10. Revolving Credit Facility, Commercial Paper and Senior Notes

Revolving Credit Facility. We have a syndicated revolving credit agreement with Wells Fargo Bank, National Association, as administrative agent and swingline lender, which provides for a $1.5 billion senior unsecured revolving credit facility for general corporate purposes, or the Revolving Credit Facility. Effective October 22, 2015, we entered into an extension agreement and fourth amendment to our Revolving Credit Facility, which, among other things, provides for a one-year extension of the maturity date for most of the lenders. As so extended, our Revolving Credit Facility matures on October 22, 2020, except for $40 million of commitments that mature on March 17, 2019 and $60 million of commitments that mature on October 22, 2019. In addition, we also have the option to increase the revolving commitments under the Revolving Credit Facility by up to an additional $500 million from time to time, upon receipt of additional commitments from new or existing lenders, and to request one additional one-year extension of the maturity date. The entire amount of the facility is available, subject to its terms, for revolving loans. Up to $250 million of the facility may be used for the issuance of performance or other standby letters of credit and up to $100 million may be used for swingline loans.

Commercial Paper. In 2015, we established a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion. Proceeds from issuances under the commercial paper program may be used for general corporate purposes. The maturities of the notes may vary, but may not exceed 397 days from the date of issuance. The notes will be issued, at our option, either at a discounted price to their principal face value or will bear interest, which may be at a fixed or floating rate, at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The notes are not redeemable or subject to voluntary prepayment by us prior to maturity. Liquidity for our payment obligations in respect of the notes issued under the commercial paper program is provided under our Revolving Credit Facility, and the aggregate amount of notes outstanding at any time will not exceed the amount available under the Revolving Credit Facility.

As of September 30, 2015, we had $493.0 million in commercial paper notes outstanding with a weighted average interest rate of 0.44% and a weighted average remaining term of two days. As of October 29, 2015, we had an additional $1.1 billion available under our Revolving Credit Facility to provide liquidity for our payment obligations with respect to the issuance of commercial paper.

4.875% Senior Notes due 2015. On July 1, 2015, we repaid $250.0 million in aggregate principal amount of our 4.875% Senior Notes due July 1, 2015, primarily with funds obtained through the issuance of additional commercial paper. These notes were presented as “Current portion of long-term debt” in our Consolidated Balance Sheet at December 31, 2014.

11. Commitments and Contingencies

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

Asbestos Litigation. We are one of several unrelated defendants in lawsuits filed in Mississippi, Louisiana and Missouri 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 offshore 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 and we expect to receive complete defense and indemnity from Murphy Exploration & Production Company with respect to many of the lawsuits pursuant to the terms of our 1992 asset purchase agreement with them. We also believe that we are not liable for the damages asserted in the remaining lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation, and we filed a declaratory judgment action in Texas state court against NuStar Energy LP, or NuStar, and Kaneb Management Co., L.L.C., or Kaneb, the successors to Diamond M Corporation, seeking a judicial determination that we did not assume liability for these claims. 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.

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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 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, the customer that conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in August 2012. Certain parties (including the debtor) in the bankruptcy proceedings questioned whether our NPI, and certain amounts we received under it since 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. We have filed motions to dismiss these counterclaims and still expect the bankruptcy proceedings to be concluded with no further material impact to us.

Personal Injury Claims. Under our current insurance policies that expire on May 1, 2016, our deductibles for marine liability insurance coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are $25.0 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.

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 September 30, 2015 our estimated liability for personal injury claims was $43.4 million, of which $8.2 million and $35.2 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. At December 31, 2014, our estimated liability for personal injury claims was $39.4 million, of which $8.2 million and $31.2 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. The Ocean GreatWhite, a 10,000 foot dynamically positioned, harsh environment semisubmersible drilling rig, is under construction in South Korea at an estimated cost of $764 million, including shipyard costs, capital spares, commissioning, project management and shipyard supervision. The contracted price

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to Hyundai Heavy Industries Co., Ltd. totaling $628.5 million is payable in two installments, of which the first installment of $188.6 million has been paid. The final installment of $439.9 million is due upon delivery of the rig, which is expected to occur in the second quarter of 2016.

At September 30, 2015, 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.

Letters of Credit and Other. We were contingently liable as of September 30, 2015 in the amount of $71.3 million under certain performance, security, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $63.7 million of performance, security, supersedeas and customs bonds can require collateral at any time. As of September 30, 2015, 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.

12. 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.

13. Restructuring and Separation Costs

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, during the first nine months of 2015. As of September 30, 2015, appropriate communications have been made to substantially all impacted personnel, and we paid $1.6 million and $8.7 million in restructuring and employee separation related costs during the three-month and nine-month periods ended September 30, 2015, respectively. There were no accrued costs associated with the Corporate Reduction Plan as of September 30, 2015.

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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.

Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. In several of these jurisdictions, tax years remain subject to examination and/or we are currently under audit or we have assessments that we are disputing.

U.S. Tax Jurisdiction. During 2015, the Internal Revenue Service began an audit of our corporate income tax return for the 2013 tax year.

Australia Tax Jurisdiction. During 2015, the Australian Taxation Office began an audit of our income tax returns for the 2010 through 2013 tax years.

Mexico Tax Jurisdiction. Due to the 2015 expiration of the statute of limitations in Mexico for the 2009 tax year for one of our subsidiaries operating in Mexico, we reversed our $10.7 million accrual for an uncertain tax position, of which $3.6 million is interest and $1.4 million is penalty.

During 2015, one of our subsidiaries operating in Mexico received a tax assessment of $5.3 million from the Mexican tax authorities for the 2008 tax year, which we are appealing.

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.

Revenues from contract drilling services by equipment type are listed below:

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Geographic Areas

Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At September 30, 2015, our actively-marketed drilling rigs were en route to or located offshore seven 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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ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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, 2014. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We are a leader in offshore drilling, providing contract drilling services to the energy industry around the globe with a fleet of 33 offshore drilling rigs. Our current fleet consists of eight ultra-deepwater, seven deepwater and eight mid-water semisubmersibles, four dynamically-positioned ultra-deepwater drillships and six jack-ups. Construction of our fourth newbuild ultra-deepwater drillship, the Ocean BlackLion, was completed in the second quarter of 2015, and the rig is currently in the U.S. Gulf of Mexico, or GOM, and is expected to begin contract drilling operations by the end of this year. One of our eight ultra-deepwater semisubmersibles, the Ocean GreatWhite is currently under construction and is expected to be delivered in the second quarter of 2016. The Ocean GreatWhite is expected to commence a three-year drilling contract offshore Australia in late 2016.

Of our current fleet, eleven rigs are cold stacked, including one ultra-deepwater, one deepwater and four mid-water semisubmersible rigs and five jack-up rigs. Since the beginning of 2015, eight of our older mid-water semisubmersible rigs have been sold for scrap. We intend to sell one of our idled jack-up rigs and, after completion of their respective contracts, we also intend to sell one mid-water semisubmersible and our older 7,875-foot water depth rated drillship for scrap.

Market Overview

Crude oil prices have declined significantly since the summer of 2014, and oil markets remain volatile and unpredictable due to a number of geopolitical and economic factors, including the Iranian Joint Comprehensive Plan of Action which, if implemented, would result in the lifting of certain international sanctions. In reaction to the depressed fundamentals in the oil and gas industry, independent and national oil companies and exploration and production companies have announced significant reductions to their 2016 capital spending plans, in addition to their already-reduced 2015 capital spending plans, and are projecting reductions to their 2017 spending budgets. Thus far in 2015, rig tenders have been infrequent and have generally been limited to short-term or well-to-well work or long-range work not commencing until 2017 or later. Competition for the limited number of drilling jobs continues to be intense, with numerous offshore drillers vying for the same opportunities, including some contractors bidding multiple rigs on the same bid, and in some cases bidding rigs of both high and lower specifications on the same bid. Operators are continuing to attempt to sublet previously contracted rigs for which capital spending programs have been delayed or canceled. In addition, newbuild floaters continue to enter the market, many of which are not contracted, adding to the oversupply of rigs. With the shortage of work and an oversupply of rigs available for work, price competition remains intense, and some industry analysts are predicting further weakening in already lower dayrates across the floater markets.

In addition, as a result of the depressed market conditions 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, sometimes resulting in no payment to us or sometimes resulting in a contractually specified termination amount, which often does not fully compensate us for the loss of the contract. During depressed market conditions, certain customers have 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. 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. See “— Contract Drilling Backlog” below.

In October 2015, we reached agreement with Petróleo Brasileiro S.A., or Petrobras, to terminate the drilling contracts on the Ocean Clipper and Ocean Alliance early, to be effective on October 30, 2015, and to add 875 days

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to the end of the current term of the drilling contract on the Ocean Courage at the rate of $380,000 per day. Petrobras has approved the agreement and we are in the process of completing the amendments to the drilling contracts. When the amendment has been completed, the revised term of the Ocean Courage contract will expire on July 20, 2020. Prior to the amendment, the terms of the Ocean Clipper and Ocean Alliance contracts were scheduled to expire on December 9, 2015 and June 17, 2016, respectively.

As previously disclosed, on February 20, 2015, a representative of PEMEX — Exploración y Producción, or PEMEX, verbally informed us of PEMEX’s intention to exercise its contractual right to terminate its drilling contract on the Ocean Ambassador and to cancel its drilling contract on the Ocean Lexington, which contract was scheduled to commence in September 2015. During the second quarter of 2015, we and PEMEX renegotiated the contract for the Ocean Ambassador, which is expected to be completed in the first quarter of 2016, at a lower dayrate. In July 2015, PEMEX delivered to us a notice to initiate the rescission of the Ocean Lexington contract, which process is currently underway.

Current depressed market conditions in the offshore drilling industry have materially impacted our results of operations and cash flows during the first nine months of 2015. We currently expect that these adverse market conditions will continue for the foreseeable future. The continuation of these conditions 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 elect to scrap a rig, we evaluate the rig for impairment. During the first nine months of 2015, we recognized a $361.1 million impairment charge related to nine rigs, for which we determined the carrying values to be impaired. See “ — Results of Operations — Overview — Nine Months Ended September 30, 2015 and 2014 — Impairment of Assets.”

As of October 19, 2015, 15 of our rigs were not subject to a drilling contract with a customer, including 11 rigs that have been cold stacked or are in the process of being cold stacked. See “— Contract Drilling Backlog” for future commitments of our rigs during the last quarter of 2015 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 be depressed. The continuing oversupply of rigs and diminished demand has resulted in further decline in dayrates and the stacking, and in some cases scrapping, of rigs in all asset classes. Industry analysts expect offshore drillers to continue to scrap older, lower specification rigs and predict that the number of uncontracted floaters may more than double by the end of 2016.

Newbuild rig deliveries and established rigs coming off contract continue to fuel an oversupply of floaters in both the ultra-deepwater and deepwater markets. 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, based on industry data, there are approximately 52 competitive, or non-owner-operated, newbuild floaters on order, 37 of which are not yet contracted for future work. There are currently 22 newbuild floaters scheduled for delivery in 2016, of which only six rigs have been contracted for future work, and another 30 rigs scheduled for delivery in 2017 and beyond. The influx of newbuilds into the market, combined with established rigs coming off contract during 2015 and in 2016, is expected to exacerbate the continuing weakened condition of the ultra-deepwater and deepwater floater markets.

Mid-Water Floaters. While conditions in the mid-water market vary slightly by region, mid-water rigs have generally 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 U.S. waters, (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. Additionally, as market conditions remain challenging, higher specification rigs may continue to take the place of lower specification units, leading to additional lower specification rigs being cold stacked or ultimately scrapped.

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Contract Drilling Backlog

The following table reflects our contract drilling backlog as of October 1, 2015 (based on contract information known as of November 2, 2015), February 9, 2015 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2014), and October 21, 2014 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014). Contract drilling backlog as presented below includes only firm commitments (typically represented by signed contracts, except as indicated in the footnotes to the tables below), and is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. 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.