DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2018 March (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 March 31, 2018

OR

For the transition period from                      to                     

Commission file number 1-13926

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

15415 Katy Freeway

Houston, Texas

77094

(Address of principal executive offices)

(Zip Code)

(281) 492-5300

(Registrant’s telephone number, including area code)

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

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

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

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

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

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

As of April 26, 2018 Common stock, $0.01 par value per share 137,428,272 shares

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DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED MARCH 31, 2018

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PART I. FINANCIAL INFORMATION

ITEM 1. Financial Statements.

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Unaudited)

(In thousands, except share and per share data)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Unaudited)

(In thousands, except per share data)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(Unaudited)

(In thousands)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

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

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DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

1. General Information

The unaudited condensed consolidated financial statements of Diamond Offshore Drilling, Inc. and subsidiaries, which we refer to as “Diamond Offshore,” “we,” “us” or “our,” should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2017 (File No. 1-13926).

As of April 26, 2018, Loews Corporation owned approximately 53% of the outstanding shares of our common stock.

Interim Financial Information

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

Use of Estimates in the Preparation of Financial Statements

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.

Changes in Accounting Principles

Revenue Recognition. In May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09, which supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services.

We adopted ASU 2014-09 and its related amendments, or collectively Topic 606, effective January 1, 2018 using the modified retrospective implementation method. Accordingly, we have applied the five-step method outlined in Topic 606 for determining when and how revenue is recognized to all contracts that were not completed as of the date of adoption. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance. For contracts that were modified before the effective date, we have considered the modification guidance within the new standard and determined that the revenue recognized and contract balances recorded prior to adoption for such contracts were not impacted. While Topic 606 requires additional disclosure of the nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers, its adoption has not had a material impact on the measurement or recognition of our revenues.

Our adoption of ASU 2014-09 represents a change in accounting principle and therefore, we have recorded the cumulative effect of adopting Topic 606 as an increase to opening retained earnings on January 1, 2018. This adjustment represents an accrual for the earned portion of demobilization revenue expected to be received for contracts not completed as of December 31, 2017, which was not recordable under previous revenue recognition guidance until completion of the demobilization activities. See Note 2.

Income Taxes. In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory, or ASU 2016-16. ASU 2016-16 amends the guidance in Topic 740 with

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respect to the accounting for the income tax consequences of intra-entity transfers of assets other than inventory. We have evaluated our historical intra-group transactions for impact under the provisions of ASU 2016-16 and have adopted the guidance thereof effective January 1, 2018 using the modified retrospective approach. We have recorded the $17.4 million cumulative effect of applying the new standard as a decrease to opening retained earnings with an offset to deferred income tax liability. See Note 9.

The aggregate impact of the changes in accounting principles, as discussed above, to our unaudited Condensed Consolidated Balance Sheet on January 1, 2018 was as follows (in thousands):

Other Recently Adopted Accounting Pronouncements

In February 2018, the FASB issued ASU No. 2018-02, Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, or ASU 2018-02. ASU 2018-02 provides for entities to make a one-time election to reclassify the income tax effects of the Tax Cuts and Jobs Act enacted in December 2017, or Tax Reform Act, on items within accumulated other comprehensive income to retained earnings. The guidance of ASU 2018-02 is effective for fiscal years beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of ASU 2018-02 is permitted. We have early adopted ASU 2018-02 and have reclassified the effect of the change in the U.S. federal corporate income tax rate on deferred tax-related items remaining in accumulated other comprehensive loss. The impact of adoption of ASU 2018-02 was not significant.

In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, or ASU 2016-15. ASU 2016-15 provides specific guidance on eight cash flow classification issues not specifically addressed by GAAP: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments; contingent consideration payments; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies; distributions from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The adoption of ASU 2016-15 did not have a significant impact on the presentation of cash receipts and cash payments within our condensed consolidated statements of cash flows.

Recent Accounting Pronouncements Not Yet Adopted

In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842), or ASU 2016-02, which requires an entity to separate the lease components from the non-lease components in a contract. The lease components are to be accounted for under ASU 2016-02, which, under the guidance, may require recognition of lease assets and lease liabilities by lessees for most leases and derecognition of the leased asset and recognition of a net investment in the lease by the lessor. ASU 2016-02 also provides for additional disclosure requirements for both lessees and lessors. Non-lease components would be accounted for under ASU 2014-09. We have determined that under the new standard, our drilling contracts contain a lease component and therefore we will be required to separately recognize revenues associated with the lease and services components. Additionally, for transactions in which we are considered lessees, we will recognize a lease liability and right of use asset based on our portfolio of leases as of the time of adoption. The guidance of ASU 2016-02 is effective for annual reporting periods beginning after December 15, 2018, including interim periods within that reporting period. Early adoption of ASU 2016-02 is permitted. We expect to adopt ASU 2016-02 on January 1, 2019 using the modified retrospective approach. We are currently reviewing the requirements of the accounting standard with regard to arrangements under which we are either the lessor or lessee, to determine the impact of ASU 2016-02 on our financial position, results of operations, cash flows and disclosures contained in the notes to our condensed consolidated financial statements.

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2. Revenue from Contracts with Customers

The activities that primarily drive the revenue earned from our drilling contracts include (i) providing a drilling rig and the crew and supplies necessary to operate the rig, (ii) mobilizing and demobilizing the rig to and from the drill site, and (iii) performing rig preparation activities and/or modifications required for the contract. Consideration received for performing these activities may consist of dayrate drilling revenue, mobilization and demobilization revenue, contract preparation revenue and reimbursement revenue. We account for these integrated services provided within our drilling contracts as a single performance obligation satisfied over time and comprised of a series of distinct time increments in which we provide drilling services.

Consideration for activities that are not distinct within the context of our contracts and do not correspond to a distinct time increment within the contract term are allocated across the single performance obligation and recognized ratably as time elapses over the initial term of the contract (which is the period we estimate to be benefited from the corresponding activities and generally ranges from two to 60 months). Consideration for activities that correspond to a distinct time increment within the contract term is recognized in the period when the services are performed. The total transaction price is determined for each individual contract by estimating both fixed and variable consideration expected to be earned over the term of the contract. See below for further discussion regarding the allocation of the transaction price to the remaining performance obligations.

The amount estimated for variable consideration may be constrained (reduced) and is only included in the transaction price to the extent that it is probable that a significant reversal of previously recognized revenue will not occur throughout the term of the contract. When determining if variable consideration should be constrained, management considers whether there are factors outside of our control that could result in a significant reversal of revenue as well as the likelihood and magnitude of a potential reversal of revenue. These estimates are re-assessed each reporting period as required.

Dayrate Drilling Revenue. Our drilling contracts generally provide for payment on a dayrate basis, with higher rates for periods when the drilling unit is operating and lower rates or zero rates for periods when drilling operations are interrupted or restricted. The dayrate invoices billed to the customer are typically determined based on the varying rates applicable to the specific activities performed on an hourly basis. Such dayrate consideration is allocated to the distinct hourly increment it relates to within the contract term, and therefore, recognized in line with the contractual rate billed for the services provided for any given hour.

Mobilization/Demobilization Revenue. We may receive fees (on either a fixed lump-sum or variable dayrate basis) for the mobilization and demobilization of our rigs. These activities are not considered to be distinct within the context of the contract and therefore, the associated revenue is allocated to the overall performance obligation and recognized ratably over the initial term of the related drilling contract. We record a contract liability for mobilization fees received, which is amortized ratably to contract drilling revenue as services are rendered over the initial term of the related drilling contract. Demobilization revenue expected to be received upon contract completion is estimated as part of the overall transaction price at contract inception and recognized in earnings ratably over the initial term of the contract with an offset to an accretive contract asset.

In some contracts, there is uncertainty as to the likelihood and amount of expected demobilization revenue to be received. For example, contractual provisions may require that a rig demobilize a certain distance before the demobilization revenue is payable or the amount may vary dependent upon whether or not the rig has additional contracted work within a certain distance from the wellsite. Therefore, the estimate for such revenue may be constrained, as described above, depending on the facts and circumstances pertaining to the specific contract. We assess the likelihood of receiving such revenue based on past experience and knowledge of the market conditions.

Contract Preparation Revenue. Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a fixed lump-sum or variable dayrate basis). These activities are not considered to be distinct within the context of the contract. We record a contract liability for contract preparation fees received, which is amortized ratably to contract drilling revenue over the initial term of the related drilling contract.

Capital Modification Revenue. From time to time, we may receive fees from our customers for capital improvements or upgrades to our rigs to meet contractual requirements (on either a fixed lump-sum or variable dayrate basis). The activities related to these capital modifications are not considered to be distinct within the context of our contracts. We record a contract liability for such fees and recognize them ratably as contract drilling revenue over the initial term of the related drilling contract.

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Revenues Related to Reimbursable Expenses. We generally receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request in accordance with a drilling contract or other agreement. Such reimbursable revenue is variable and subject to uncertainty, as the amounts received and timing thereof are highly dependent on factors outside of our influence. Accordingly, reimbursable revenue is fully constrained and not included in the total transaction price until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of a customer. We are generally considered a principal in such transactions and record the associated revenue at the gross amount billed to the customer, as “Revenues related to reimbursable expenses” in our unaudited Condensed Consolidated Statements of Operations. Such amounts are recognized ratably over the period within the contract term during which the corresponding goods and services are to be consumed.

Contract Balances

Accounts receivable are recognized when the right to consideration becomes unconditional based upon contractual billing schedules. Payment terms on invoiced amounts are typically 30 days. Contract asset balances consist of demobilization revenue that we expect to receive and is recognized ratably throughout the contract term, but invoiced upon completion of the demobilization activities. Once the demobilization revenue is invoiced, the corresponding contract asset is transferred to accounts receivable. Contract liabilities include payments received for mobilization as well as rig preparation and upgrade activities which are allocated to the overall performance obligation and recognized ratably over the initial term of the contract.

Contract balances are netted at a contract level, such that deferred revenue for mobilization, contract preparation and capital modifications (contract liabilities) is netted with any accrued demobilization revenue (contract asset) for each applicable contract.

The following table provides information about receivables, contract assets and contract liabilities from our contracts with customers (in thousands):

Significant changes in the contract assets and the contract liabilities balances during the period are as follows (in thousands):

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Deferred Contract Costs

Certain direct and incremental costs incurred for upfront preparation, initial mobilization and modifications of contracted rigs represent costs of fulfilling a contract as they relate directly to a contract, enhance resources that will be used in satisfying our performance obligations in the future and are expected to be recovered. Such costs are deferred and amortized ratably to contract drilling expense as services are rendered over the initial term of the related drilling contract. Such deferred contract costs in the amount of $53.1 million and $42.0 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively in our unaudited Condensed Consolidated Balance Sheet at March 31, 2018. During the three months ended March 31, 2018, the amount of amortization of such costs was $12.9 million and there was no impairment loss in relation to capitalized costs.

Costs incurred for the demobilization of rigs at contract completion are recognized as incurred during the demobilization process. Costs incurred for rig modifications or upgrades required for a contract, which are considered to be capital improvements, are capitalized as drilling and other property and equipment and depreciated over the estimated useful life of the improvement.

Transaction Price Allocated Remaining Performance Obligations

The following table reflects revenue expected to be recognized in the future related to unsatisfied performance obligations as of March 31, 2018 (in thousands):

The revenue included above consists of expected fixed mobilization, demobilization, and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization, demobilization, and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. The amounts are derived from the specific terms within drilling contracts that contain such provisions, and the expected timing for recognition of such revenue is based on the estimated start date and duration of each respective contract based on information known at March 31, 2018. The actual timing of recognition of such amounts may vary due to factors outside of our control. We have applied the disclosure practical expedient in ASC 606-10-50-14A(b) and have not included estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue.

Impact of Topic 606 on Financial Statement Line Items

Our revenue recognition pattern under Topic 606 is similar to revenue recognition under the previous guidance, except for the recognition of demobilization revenue. Such revenue, which was recognized upon completion of a contract under the previous guidance, is now estimated at contract inception and recognized ratably as contract drilling revenue over the term of the contract with an offset to a contract asset under Topic 606.

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The following tables summarize the impacts of adopting Topic 606 on our selected unaudited Condensed Consolidated Balance Sheets, Statements of Operations and Statements of Cash Flows information, as of and for the three months ended March 31, 2018 (in thousands, except per share data):

3. Supplemental Financial Information

Condensed Consolidated Balance Sheets Information

Accounts receivable, net of allowance for bad debts, consist of the following (in thousands):

Prepaid expenses and other current assets consist of the following (in thousands):

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Accrued liabilities consist of the following (in thousands):

Includes $1.9 million and $13.6 million in accrued costs at March 31, 2018 and December 31, 2017, respectively, related to a restructuring plan that was implemented in late 2017. See Note 8.

Condensed Consolidated Statements of Cash Flows Information

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

4. Earnings Per Share

A reconciliation of the numerators and the denominators of our basic and diluted per-share computations is as follows (in thousands, except per share data):

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The following table sets forth the share effects of stock-based awards excluded from the computations of diluted earnings per share, as the inclusion of such potentially dilutive shares would have been antidilutive for the periods presented (in thousands):

5. 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. We generally place our excess cash investments in U.S. Treasury bills and notes and U.S. government-backed short-term money market instruments through several financial institutions. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.

Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base has consisted primarily of major and independent oil and gas companies and government-owned oil companies. Based on our current customer base and the geographic areas in which we operate, we do not believe that we have any significant concentrations of credit risk at March 31, 2018.

In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible and, historically, losses on our trade receivables have been infrequent occurrences.

Fair Values

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

Market conditions could cause an instrument to be reclassified among Levels 1, 2 and 3. Our policy regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the transfers as having occurred at the beginning of the reporting period. There were no transfers between fair value levels during the three-month period ended March 31, 2018 or the year ended December 31, 2017.

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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, which were measured at fair value on a nonrecurring basis, during the year ended December 31, 2017 of $99.3 million.

Assets and liabilities measured at fair value are summarized below (in thousands).

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

We consider our senior notes to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service at March 31, 2018 and December 31, 2017. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day period of the report date. Fair values and related carrying values of our senior notes are shown below (in millions).

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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.

6. Drilling and Other Property and Equipment

Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows (in thousands):

7. 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 reasonably estimated, we record a liability for the amount of the reasonably estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.

Patent Litigation. On August 30, 2017, an affiliate of Transocean Ltd., or Transocean, an offshore drilling contractor, filed a lawsuit against us and one of our subsidiaries in the United States District Court for the Southern District of Texas, alleging that we infringed certain United States patents previously owned by Transocean or its affiliates or employees pertaining to certain dual-activity drilling operations. The lawsuit alleges that we infringed the patents by the unauthorized sale, offer for sale, and importation and use of four of our drilling rigs (Ocean BlackHawk, Ocean BlackHornet, Ocean BlackRhino and Ocean BlackLion) and is seeking unspecified monetary damages. The Transocean patents, which expired in May 2016, do not apply to drilling activities outside the United States or to activities that occurred after the expiration of the patents. We are unable to estimate our potential exposure, if any, to the Transocean lawsuit at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.

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.

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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 one of our customers in Brazil, Petróleo Brasileiro S.A., or Petrobras, that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras’ charter agreements with its contractors. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of any claim, lawsuit or action cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of any litigation matter. Any claims against us, whether meritorious or not, could cause us to incur significant costs and expenses and require significant amounts of management and operational time and resources. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.

Personal Injury Claims. Under our current insurance policies, which will renew on May 1, 2018, our deductibles for marine liability insurance coverage with respect to personal injury claims not related to named windstorms in the U.S. Gulf of Mexico, which primarily result from Jones Act liability in the U.S. Gulf of Mexico, are $10.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year. Our deductibles for personal injury claims arising due to named windstorms in the U.S. Gulf of Mexico are $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $25.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.

The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At March 31, 2018 our estimated liability for personal injury claims was $29.4 million, of which $5.1 million and $24.3 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our unaudited Condensed Consolidated Balance Sheets. At December 31, 2017 our estimated liability for personal injury claims was $30.9 million, of which $5.2 million and $25.7 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:

Letters of Credit and Other. We were contingently liable as of March 31, 2018 in the amount of $20.9 million under certain performance, tax, supersedeas, bid and customs bonds and letters of credit. Agreements relating to approximately $15.2 million of tax, supersedeas, and customs bonds can require collateral at any time. As of March 31, 2018, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds.

8. Restructuring and Separation Costs

In late 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our corporate facilities and onshore bases, which we refer to as the 2017 Reduction Plan. During the three months ended March 31, 2018, we incurred and paid an additional $3.0 million in severance and related costs to redundant employees identified in early 2018. As of March 31, 2018, accrued costs associated with the 2017 Reduction Plan were $1.9 million, primarily related to severance payments to former employees, which are payable over a two-year period.

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9. Income Taxes

Effective January 1, 2018, we adopted ASU 2016-16, which required us to record the income tax consequences of two historical intra-entity transfers of rigs, for which previous accounting guidance precluded us from recognizing such income tax effects. We adopted the new accounting guidance using the modified retrospective approach, whereby we recorded the $17.4 million cumulative effect of applying the new standard as an adjustment to opening retained earnings with an offset to a deferred income tax liability. See Note 1.

Additionally, in response to our interpretation of the Tax Reform Act, which was signed into law in late December 2017, we recorded a provisional net tax expense of $1.1 million during the fourth quarter of 2017, which included a charge relating to the one-time mandatory repatriation of previously deferred earnings of certain non-US subsidiaries that are owned either wholly or partially by our U.S. subsidiaries, inclusive of the utilization of certain tax attributes offset by a provisional liability for uncertain tax positions related to such attributes. Due to the timing of the enactment of the Tax Reform Act, there has been and continues to be a significant amount of uncertainty as to the appropriate application of a number of the underlying provisions, pending further guidance and clarification from the relevant authorities. In 2018, the U.S. Department of the Treasury and Internal Revenue Service issued additional guidance which we believe clarified certain of our tax positions taken in 2017 and, consequently, we reversed a $43.3 million liability for an uncertain tax position related to the toll charge in accordance with the Securities and Exchange Commission’s Staff Accounting Bulletin No. 118, or SAB 118. SAB 118 allowed companies to report the income tax effects of the Tax Reform Act as a provisional amount based on a reasonable estimate, subject to adjustment during a reasonable measurement period, not to exceed twelve months, until the accounting and analysis under Topic 740 is complete.

We are still in the process of evaluating our estimate as it relates to the tax effect of (i) the mandatory, deemed repatriation aspect of the Tax Reform Act, (ii) the amount of deferred tax assets and liabilities subject to the income tax rate change from 35% to 21% and (iii) the ability to more likely than not realize the benefit of deferred tax assets, including net operating losses and foreign tax credits. We will continue to monitor developments in these areas and adjust our estimates throughout 2018, as and if necessary, as additional guidance and clarification becomes available.

10. 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.

Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At March 31, 2018, our active drilling rigs were located offshore 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.

The following table provides information about disaggregated revenue by equipment-type and primary geographical market (in thousands):

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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 condensed consolidated financial statements (including the notes thereto) included in Item 1 of Part I of this report and our audited consolidated financial statements (including the notes thereto), Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 1A, “Risk Factors” included in our Annual Report on Form 10-K for the year ended December 31, 2017. References to “Diamond Offshore,” “we,” “us” or “our” mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.

We provide contract drilling services to the energy industry around the globe with a fleet of 17 floaters, of which four rigs are currently cold stacked. In addition, we have one jack-up rig that is currently being marketed for sale. See “– Contract Drilling Backlog.”

Market Overview

Oil prices rose to the $70-per-barrel range in April 2018, rebounding from the historical 12-year low of less than $30 per barrel in January 2016. The higher commodity price is in part due to continued production cuts by certain members of the Organization of Petroleum Exporting Countries, or OPEC, which are scheduled to remain in place throughout 2018. However, the offshore contract drilling market has continued to stagnate, as the increase in oil prices has not yet resulted in a measurable increase in demand for offshore contract drilling services or higher dayrates. Capital spending for offshore exploration and development remained at a relatively low level at the start of 2018.

The offshore contract drilling market continues to be burdened by an oversupply of drilling rigs based on current demand. Contract rollovers, or the availability of a drilling rig at completion of a contract if options for future work are not exercised or further work secured, continue to add to the uncontracted supply of rigs. Such rollovers have predominately been for higher-specification floaters, which have been slow to contract despite the higher crude oil price. Industry reports indicate that there remain approximately 40 newbuild floaters on order with scheduled deliveries between 2018 and 2021, most of which have not yet been contracted for future work. Industry analysts also report that there are over 90 speculative jack-up rigs currently on order with scheduled deliveries between 2018 and 2020.

Given the oversupply of rigs, competition for the limited number of offshore drilling jobs remains intense. In some cases, dayrates have been negotiated at break-even or below-cost levels in order to enable the drilling contractor to recover a portion of operating costs for rigs that would otherwise be uncontracted or stacked. Customers have also indicated a preference for “hot” rigs rather than reactivated cold-stacked rigs. This preference incentivizes the drilling contractor to contract rigs at lower rates for the sole purpose of maintaining the rigs in an active state and allowing for at least partial cost recovery. Higher specification floaters are also being bid in all markets to keep those rigs active and avoid the higher stacking costs for such rigs. Despite these factors, certain drilling contractors have announced the reactivation of stacked rigs or plans to reactivate certain rigs if contracts are awarded.

Looking forward, there has been a recent uptick in rig tenders, primarily for work in the North Sea and Australia floater markets commencing in 2019 and beyond. However, many of these tenders are limited to single-well jobs, with options for future wells.

See “– Contract Drilling Backlog” for future commitments of our rigs during 2018 through 2020.

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Contract Drilling Backlog

Contract drilling backlog, as presented below, includes only firm commitments (typically represented by signed contracts) and is calculated by multiplying the contracted operating dayrate by the firm contract period. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog.

The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 2 “Revenue from Contracts with Customers” in our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report. Contract drilling backlog includes only future dayrate revenue as described above, while the disclosure in Note 2 excludes dayrate revenue and reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related to non-distinct promises within our signed contracts. See “– Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows.”

The following table reflects our contract drilling backlog as of April 1, 2018 (based on information available at that time), January 1, 2018 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2017), and April 1, 2017 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2017) (in thousands).

The following table reflects the amount of our contract drilling backlog by year as of April 1, 2018 (in thousands).

The following table reflects the percentage of rig days committed by year as of April 1, 2018. 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).

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

Revenue Recognition. Effective January 1, 2018, we adopted Accounting Standards Update, or ASU, No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09, which supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition. Under the new guidance, revenue is recognized when a customer obtains control of promised goods or services and in an amount that reflects the consideration the entity expects to receive in exchange for those goods or services. Revenues for reporting periods beginning after January 1, 2018 are presented under Topic 606, while prior period amounts have not been adjusted and continue to be reported under the previous revenue recognition guidance.

Revenue recognition under ASU 2014-09 differs from our previous revenue recognition pattern only as it relates to demobilization revenue. Such revenue, which was previously recognized upon completion of a contract, will be estimated at contract inception and recognized over the term of the contract under the new revenue recognition guidance. See “– Critical Accounting Policies,” Note 1 “General Information - Change in Accounting Principles - Revenue Recognition and Note 2 “Revenue from Contracts with Customers” in our unaudited condensed consolidated financial statements included in Item 1 of Part I this report.

Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half years. During the remainder of 2018, we expect to spend approximately an aggregate 200 days for special surveys and rig upgrades for the Ocean Valiant and Ocean Apex and repairs to the Ocean Courage. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ – Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our current insurance policy, which will renew effective May 1, 2018, we carry physical damage insurance for certain losses other than those caused by named windstorms in the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.

In addition, under our current insurance policy, which will renew effective May 1, 2018, 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 are $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.

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, 2017. Effective January 1, 2018, we adopted ASU, No. 2014-09, which supersedes the revenue recognition requirements in ASU Topic 605, Revenue Recognition and ASU No. 2016-16, Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory. See “ – Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows” and Note 1 “General Information - Change in Accounting Principles,” Note 2 “Revenue from Contracts with Customers” and Note 9 “Income Taxes” in our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report. There were no other material changes to these policies during the three months ended March 31, 2018.

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Results of Operations

Our operating results for contract drilling services are dependent on three primary metrics or key performance indicators: revenue-earning days, rig utilization and average daily revenue. The following table presents these three key performance indicators and other comparative data relating to our revenues and operating expenses for the three months ended March 31, 2018 and 2017.

Three Months Ended March 31, 2018 and 2017

Net income for the first quarter of 2018 decreased $4.2 million or 18%, compared to the first quarter of 2017, and reflected lower margins from our contract drilling services, primarily driven by lower contract drilling revenue. The reduction in net income was partially offset by lower depreciation expense and an income tax benefit recorded during the first quarter of 2018. Contract drilling services contributed operating income of $103.2 million for the first quarter of 2018, compared to operating income of $160.0 million in the same period of 2017, reflecting continued stagnation of the contract drilling market during the first quarter of 2018.

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Operating Results. Contract drilling revenue decreased $75.6 million during the first quarter of 2018 compared to the first quarter of 2017, primarily due to 226 fewer revenue-earning days ($79.6 million), combined with the effect of lower average daily revenue earned ($0.8 million). Comparing the two quarters, revenue-earning days decreased primarily due to fewer revenue-earning days for previously-owned and currently held-for-sale rigs that operated during the first quarter of 2017 (141 days) and incremental downtime attributable to the warm stacking of rigs between contracts (110 incremental days). The decrease in aggregate revenue-earning days was partially offset by an increase in revenue efficiency for our working rigs, or 27 fewer non-productive days. In addition, we recognized $4.8 million in loss of hire insurance proceeds during the first quarter of 2018 related to contract terminations for two jack-up rigs in a prior year.

Contract drilling expense, excluding depreciation, decreased $18.8 million during the first quarter of 2018 compared to the first quarter of 2017, primarily due to reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense in the first quarter of 2017 ($17.8 million), and $1.0 million in net cost savings related to our current rig fleet. During the first quarter of 2018, our contract drilling expense reflected favorable reductions in labor and related costs, repairs, maintenance and inspection and mobilization costs, partially offset by higher costs for fuel, boat and helicopter charges and costs associated with our Pressure Control by the Hour^® program. General and administrative costs increased $1.0 million during the first quarter of 2018, compared to the first quarter of 2017, as reductions in personnel costs were offset by higher professional expenses, including consulting and audit and advisory services associated with our information systems, the impact of the Tax Cuts and Jobs Act of 2017 enacted in December 2017, or the Tax Reform Act, and legal services. Depreciation expense decreased $11.4 million during the first quarter of 2018, compared to the first quarter of 2017, primarily due to a lower depreciable asset base as a result of asset impairments recognized during 2017.

Restructuring and Separation Costs. In late 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our corporate facilities and onshore bases. During the first quarter of 2018, we recognized and paid $3.0 million in restructuring and other employee separation related costs for additional redundant employees that were identified in early 2018.

Interest Expense, Net of Amounts Capitalized. Interest expense increased $0.7 million during the first quarter of 2018 compared to the first quarter of 2017, primarily as a result of incremental interest expense of $2.6 million associated with our senior notes issued in August 2017 at a higher interest rate than the senior notes that were retired in the third quarter of 2017. Higher interest cost associated with our senior notes was partially offset by the reversal of contingent interest associated with a Brazilian non-income tax contingency for which the statute of limitations expired and interest capitalized in connection with certain qualifying software implementation projects.

Income Tax Benefit. We recorded a net income tax benefit of $44.5 million for the first quarter of 2018, compared to net income tax expense of $0.9 million for the same quarter of 2017. Income tax benefit for the 2018 period included a tax benefit of $43.3 million due to the reversal of an uncertain tax position related to the toll charge recognized in the fourth quarter of 2017 for the deemed repatriation of previously deferred earnings of our non-U.S. subsidiaries in response to the Tax Reform Act. Further guidance issued by the U.S. Department of the Treasury and Internal Revenue Service in 2018 clarified certain of our tax positions taken and, consequently, we reversed our liability for an uncertain tax position related to the toll charge. Other than the reversal of the uncertain tax position, the difference in the amount of income tax benefit recognized in the 2018 period, compared to the income tax expense recorded in the first quarter of 2017, was in large part due to the mix of our domestic and international pre-tax earnings and losses for the periods, the limitation on the deductibility of interest expense as a result of the Tax Reform Act and the recording of a valuation allowance against such interest, and the effect of a lower U.S. statutory tax rate as a result of the Tax Reform Act.

Liquidity and Capital Resources

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

Based on our cash available for current operations and contractual backlog of $2.2 billion as of April 1, 2018, of which $0.9 billion is expected to be realized during the remainder of 2018, we believe future capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our Credit Agreement, as needed. See “– Sources and Uses of Cash – Capital Expenditures.”

Certain of our international rigs are owned and operated, directly or indirectly, by Diamond Foreign Asset Company, or DFAC. As of December 31, 2017, all unremitted earnings of DFAC were deemed repatriated as a

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result of the Tax Reform Act, and U.S. taxes were provided for those earnings. We intend to indefinitely reinvest earnings of DFAC and its foreign subsidiaries to finance our foreign activities. Earnings of DFAC subsequent to December 31, 2017 could become subject to U.S. income tax if remitted, or if deemed remitted as a dividend; however, it is not practical to estimate this potential liability.

To the extent available, we expect to utilize the operating cash flows generated by and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each entity’s respective working capital requirements and capital commitments. At March 31, 2018 and December 31, 2017, we had cash available for current operations of $429.7 million and $376.0 million, respectively.

A substantial portion of our cash flows has historically been invested in the enhancement of our drilling fleet. We determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We also make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments thereto if required. See “– Sources and Uses of Cash – Capital Expenditures.”

We pay dividends at the discretion of our Board of Directors, or Board, and any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Board’s consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. We did not pay any dividends in 2017 or during the first quarter of 2018.

Depending on market conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any shares of our outstanding common stock during the three-month periods ended March 31, 2018 and 2017.

We may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control.

Sources and Uses of Cash

During the three-month period ended March 31, 2018, our primary sources of cash were an aggregate $83.8 million generated by operating activities and proceeds of $1.4 million, primarily from the sale of the Ocean Victory in January 2018. Cash usage during the three months ended March 31, 2018 was primarily for capital expenditures, aggregating $31.5 million.

Cash Flow from Operations. Cash flow from operations for the three months ended March 31, 2018 decreased $14.9 million compared to the three months ended March 31, 2017, due to an increase in cash expenditures for contract drilling services and other working capital requirements ($31.3 million), including payment of $14.7 million, in restructuring and separation costs. The reduction in cash flow from operations during the first three months of 2018 was partially offset by an increase in cash collected from the performance of contract drilling services ($4.5 million) and lower income taxes payments, net of refunds ($11.9 million), compared to the prior year period.

Capital Expenditures. As of the date of this report, we expect total capital expenditures for 2018 to aggregate approximately $220.0 million for our capital maintenance and replacement programs.

At March 31, 2018, we had no significant purchase obligations, except for those related to our direct rig operations, which arise during the normal course of business.

Other Obligations. As of March 31, 2018, the total net unrecognized tax benefits related to uncertain tax positions was $63.6 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

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Credit Agreement

At March 31, 2018, we had no borrowings outstanding under our Credit Agreement, and were in compliance with all covenants thereunder. As of April 26, 2018, we had $1.5 billion available under our Credit Agreement to provide liquidity for our payment obligations.

Credit Ratings

Our current credit rating is Ba3 from Moody’s Investor Services and B+ from S&P Global Ratings with a negative outlook from both. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. Any downgrade in our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that we could issue, and could further restrict our access to capital markets and our ability to raise funds by issuing additional debt. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.

Other Commercial Commitments - Letters of Credit

We were contingently liable as of March 31, 2018 in the amount of $20.9 million under certain performance, tax, supersedeas bid and customs bonds and letters of credit. Agreements relating to approximately $15.2 million of tax, supersedeas, and customs bonds can require collateral at any time. As of March 31, 2018, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration (in thousands).

Off-Balance Sheet Arrangements

At March 31, 2018 and December 31, 2017, we had no off-balance sheet debt or other off-balance sheet arrangements.

New Accounting Pronouncements

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

Forward-Looking Statements

We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “would,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

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These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, those described or referenced under “Risk Factors” in Item 1A in our Annual Report on Form 10-K for the year ended December 31, 2017.

The risks and uncertainties referenced above are not exhaustive. Other sections of this report and our other filings with the Securities and Exchange Commission include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we may refer to reports published by third parties that purport to describe trends or developments in energy production or drilling and exploration activity. While we believe that these reports are reliable, we have not independently verified the information included in such reports. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

There were no material changes in our market risk components for the three months ended March 31, 2018. See “Quantitative and Qualitative Disclosures About Market Risk” included in Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2017 for further information.

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ITEM 4. Controls and Procedures.

We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.

Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of March 31, 2018. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of March 31, 2018.

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our first fiscal quarter of 2018 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings.

Information related to certain legal proceedings is included in Note 7 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

ITEM 1A. Risk Factors.

Our Annual Report on Form 10-K for the year ended December 31, 2017 includes a detailed discussion of certain material risk factors facing our company. No material changes have been made to such risk factors as of March  31, 2018.

ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds.

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

(c) During the three months ended March 31, 2018, in connection with the vesting of restricted stock units held by our officers and certain of our employees, which were awarded under an equity incentive compensation plan, we acquired shares of our common stock in satisfaction of tax withholding obligations that were incurred on the vesting date. The date of acquisition, number of shares and average effective acquisition price per share were as follows:

Issuer Purchases of Equity Securities

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ITEM 6. Exhibits

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

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