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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

 

FORM 10-Q

 

 

(Mark One)

☒	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2018

OR

 

☐	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                      to                     

Commission file number 1-13926

 

 

DIAMOND OFFSHORE DRILLING, INC.

(Exact name of registrant as specified in its charter)

 

 

 

Delaware		76-0321760
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

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):

 

Large accelerated filer		☒		Accelerated filer		☐
Non-accelerated filer		☐  (Do not check if a smaller reporting company)		Smaller reporting company		☐
Emerging growth company		☐

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 13(a) of the Exchange 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 July 27, 2018 Common stock, $0.01 par value per share 137,434,458 shares

 

 

 

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DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2018

 

				PAGE NO.
COVER PAGE					1
TABLE OF CONTENTS					2
PART I. FINANCIAL INFORMATION					3
ITEM 1.		Financial Statements (Unaudited)
		Condensed Consolidated Balance Sheets			3
		Condensed Consolidated Statements of Operations			4
		Condensed Consolidated Statements of Comprehensive Income (Loss)			5
		Condensed Consolidated Statements of Cash Flows			6
		Notes to Unaudited Condensed Consolidated Financial Statements			7
ITEM 2.		Management’s Discussion and Analysis of Financial Condition and Results of Operations			21
ITEM 3.		Quantitative and Qualitative Disclosures About Market Risk			30
ITEM 4.		Controls and Procedures			30
PART II. OTHER INFORMATION					31
ITEM 1.		Legal Proceedings			31
ITEM 1A.		Risk Factors			31
ITEM 2.		Unregistered Sales of Equity Securities and Use of Proceeds			31
ITEM 6.		Exhibits			32
SIGNATURES					33

 

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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)

 

		June 30,				December 31,
		2018				2017
ASSETS
Current assets:
Cash and cash equivalents		$	144,168			$	376,037
Marketable securities			274,671				—
Accounts receivable, net of allowance for bad debts			203,131				256,730
Prepaid expenses and other current assets			154,408				157,625
Assets held for sale			67,815				96,261
Total current assets			844,193				886,653
Drilling and other property and equipment, net of accumulated depreciation			5,197,197				5,261,641
Other assets			71,389				102,276
Total assets		$	6,112,779			$	6,250,570
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable		$	54,717			$	38,755
Accrued liabilities			130,123				154,655
Taxes payable			14,522				29,878
Total current liabilities			199,362				223,288
Long-term debt			1,973,059				1,972,225
Deferred tax liability			124,350				167,299
Other liabilities			105,278				113,497
Total liabilities			2,402,049				2,476,309
Commitments and contingencies (Note 9)
Stockholders’ equity:
Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding)			—				—
Common stock (par value $0.01, 500,000,000 shares authorized; 144,374,006 shares issued and 137,430,916 shares outstanding at June 30, 2018; 144,085,292 shares issued and 137,227,782 shares outstanding at December 31, 2017)			1,444				1,441
Additional paid-in capital			2,013,862				2,011,397
Retained earnings			1,899,735				1,964,497
Accumulated other comprehensive income (loss)			23				(5	)
Treasury stock, at cost (6,943,090 and 6,857,510 shares of common stock at June 30, 2018 and December 31, 2017, respectively)			(204,334	)			(203,069	)
Total stockholders’ equity			3,710,730				3,774,261
Total liabilities and stockholders’ equity		$	6,112,779			$	6,250,570

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)

 

		Three Months Ended								Six Months Ended
		June 30,								June 30,
		2018				2017				2018				2017
Revenues:
Contract drilling		$	265,353			$	392,170			$	553,279			$	755,727
Revenues related to reimbursable expenses			3,508				7,119				11,092				17,788
Total revenues			268,861				399,289				564,371				773,515
Operating expenses:
Contract drilling, excluding depreciation			189,321				196,217				374,010				399,740
Reimbursable expenses			3,414				6,790				10,884				17,268
Depreciation			81,825				85,982				163,650				179,211
General and administrative			18,236				19,010				36,749				36,493
Impairment of assets			27,225				71,268				27,225				71,268
Restructuring and separation costs			1,265				—				4,276				—
Gain on disposition of assets			(50	)			(802	)			(560	)			(2,148	)
Total operating expenses			321,236				378,465				616,234				701,832
Operating (loss) income			(52,375	)			20,824				(51,863	)			71,683
Other income (expense):
Interest income			2,001				396				3,638				571
Interest expense, net of amounts capitalized			(29,585	)			(27,251	)			(57,903	)			(54,847	)
Foreign currency transaction gain (loss)			411				(927	)			858				160
Other, net			262				(62	)			842				(125	)
(Loss) income before income tax benefit			(79,286	)			(7,020	)			(104,428	)			17,442
Income tax benefit			10,012				22,969				54,475				22,046
Net (loss) income		$	(69,274	)		$	15,949			$	(49,953	)		$	39,488
(Loss) earnings per share, Basic and Diluted		$	(0.50	)		$	0.12			$	(0.36	)		$	0.29
Weighted-average shares outstanding:
Shares of common stock			137,429				137,224				137,362				137,199
Dilutive potential shares of common stock			—				3				—				36
Total weighted-average shares outstanding			137,429				137,227				137,362				137,235

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 (LOSS)

(Unaudited)

(In thousands)

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
Net (loss) income		$	(69,274	)		$	15,949			$	(49,953	)		$	39,488
Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Reclassification adjustment for gain included in net income			(1	)			(1	)			(3	)			(3	)
Investments in marketable securities:
Unrealized holding gain			31				—				31				—
Total other comprehensive gain (loss)			30				(1	)			28				(3	)
Comprehensive (loss) income		$	(69,244	)		$	15,948			$	(49,925	)		$	39,485

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)

 

		Six Months Ended
		June 30,
		2018				2017
Operating activities:
Net (loss) income		$	(49,953	)		$	39,488
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation			163,650				179,211
Loss on impairment of assets			27,225				71,268
Restructuring and separation costs			2,184				—
Gain on disposition of assets			(560	)			(2,148	)
Deferred tax provision			(61,160	)			(54,425	)
Stock-based compensation expense			2,468				2,651
Contract liabilities, net			(3,255	)			11,524
Contract assets, net			(956	)			—
Deferred contract costs, net			24,703				16,866
Other assets, noncurrent			742				(1,619	)
Other liabilities, noncurrent			(3,849	)			407
Other			393				1,202
Changes in operating assets and liabilities:
Accounts receivable			53,451				(64,489	)
Prepaid expenses and other current assets			28				(6,154	)
Accounts payable and accrued liabilities			(21,466	)			(12,291	)
Taxes payable			(2,878	)			(4,610	)
Net cash provided by operating activities			130,767				176,881
Investing activities:
Capital expenditures			(90,432	)			(71,889	)
Proceeds from maturities of marketable securities			300,000				—
Purchase of marketable securities			(573,837	)			—
Proceeds from disposition of assets, net of disposal costs			1,723				4,077
Other			—				23
Net cash used in investing activities			(362,546	)			(67,789	)
Financing activities:
Net repayment of short-term borrowings			—				(104,200	)
Other			(90	)			(156	)
Net cash used in financing activities			(90	)			(104,356	)
Net change in cash and cash equivalents			(231,869	)			4,736
Cash and cash equivalents, beginning of period			376,037				156,233
Cash and cash equivalents, end of period		$	144,168			$	160,969

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 July 27, 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.

 

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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 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 11.

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):

 

		Retained Earnings				Prepaid Expenses and Other Current Assets				Other Assets				Deferred Tax Liability
Balance as of January 1, 2018 before adoption		$	1,964,497			$	157,625			$	102,276			$	167,299
Adjustments for adoption of:
Topic 606			2,590				611				2,107				128
ASU 2016-16			(17,401	)			—				—				17,401
Balance as of January 1, 2018 after adoption		$	1,949,686			$	158,236			$	104,383			$	184,828

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 the 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 (i) requires lessees to recognize a right of use asset and a lease liability on the balance sheet for virtually all leases, (ii) updates previous accounting standards for lessors to align certain requirements with the updates to lessee accounting standards and the revenue recognition accounting standards and (iii) requires enhanced disclosure of qualitative and quantitative information about the entity’s leasing arrangements. This update is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. During our evaluation of ASU 2016-02, we concluded that our drilling contracts contain a lease component based on the updated definition of a lease. On March 28, 2018, the FASB held a meeting to approve certain additional amendments to ASU 2016-02, including a revision to the practical expedient that would allow a lessor to account for the combined lease and non-lease components under Topic 606, Revenue from Contracts with Customers, when the non-lease component is the predominant element of the combined component. As this content is still pending, we are not yet able to determine what, if any, impact our adoption will have on our revenue recognition patterns and related disclosures.

With respect to leases whereby we are the lessee, we expect to recognize lease liabilities and offsetting right of use assets corresponding to, at a minimum, our currently identified, undiscounted future minimum lease commitments of approximately $490 million, primarily related to certain leased subsea equipment. However, we are still evaluating the overall impact and will continue to refine our estimate prior to adoption of the ASU. We

 

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currently expect to elect the transition practical expedient package available in the ASU whereby we will not reassess (i) whether any of our expired or existing contracts contain a lease, (ii) the classification for any expired or existing leases and (iii) initial direct costs for any existing leases.

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.

 

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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.

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 primarily 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):

 

		June 30,				January 1,
		2018				2018
Trade receivables		$	194,425			$	247,453
Current contract assets (1)			1,567				611
Noncurrent contract assets (1)			2,107				2,107
Current contract liabilities (deferred revenue) (1)			(10,173	)			(11,371	)
Noncurrent contract liabilities (deferred revenue) (1)			(6,915	)			(8,972	)

 

(1)

Contract assets and contract liabilities may reflect balances that have been netted together on a contract basis. Net current contract asset and liability balances are included in “Prepaid expenses and other current assets” and “Accrued liabilities,” respectively, and net noncurrent contract asset and liability balances are included in “Other assets” and “Other liabilities,” respectively, in our unaudited Condensed Consolidated Balance Sheet as of June 30, 2018.

 

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

 

		Net Contract Balances
Contract assets at January 1, 2018		$	2,718
Contract liabilities at January 1, 2018			(20,343	)
Net balance at January 1, 2018			(17,625	)
Decrease due to amortization of revenue that was included in the beginning contract liability balance			7,048
Increase due to cash received, excluding amounts recognized as revenue during the period			(4,670	)
Increase due to revenue recognized during the period but contingent on future performance			2,306
Decrease due to transfer to receivables during the period			(611	)
Adjustments			138
Net balance at June 30, 2018		$	(13,414	)
Contract assets at June 30, 2018		$	3,674
Contract liabilities at June 30, 2018			(17,088	)

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 $56.1 million and $25.1 million are reported in “Prepaid expenses and other current assets” and “Other assets,” respectively, in our unaudited Condensed Consolidated Balance Sheet at June 30, 2018. During the three-month and six-month periods ended June 30, 2018, the amount of amortization of such costs was $14.3 million and $27.2 million, respectively. There was no impairment loss in relation to capitalized costs.

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

Transaction Price Allocated to Remaining Performance Obligations

The following table reflects revenue expected to be recognized in the future related to unsatisfied performance obligations as of June 30, 2018 (in thousands):

 

		For the Years Ending December 31,
		2018 (1)				2019				2020				2021				Total
Mobilization and contract preparation revenue		$	9,115			$	9,043			$	81			$	—			$	18,239
Capital modification revenue			6,598				9,170				387				—				16,155
Demobilization revenue			2,170				—				—				—				2,170
Other deferred revenue			343				681				681				194				1,899
Total		$	18,226			$	18,894			$	1,149			$	194			$	38,463

 

(1)	Represents the six-month period beginning July 1, 2018.

The revenue included above consists primarily 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 June 30, 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.

 

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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.     

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 six months ended June 30, 2018 (in thousands, except per share data):    

 

		June 30, 2018
		Balances as reported				Adjustments				Balances without adoption of Topic 606
Unaudited Condensed Consolidated Balance Sheets
Prepaid and other current assets		$	154,408			$	(1,174	)		$	153,234
Other assets			71,389				(2,107	)			69,282
Accrued liabilities			130,123				739				130,862
Deferred tax liability			124,350				(402	)			123,948
Retained earnings			1,899,735				(3,619	)			1,896,116
Unaudited Condensed Consolidated Statements of Operations
Contract drilling revenue		$	553,279			$	(1,303	)		$	551,976
Income tax benefit			54,475				274				54,749
Loss per share, Basic and Diluted			(0.36	)			(0.01	)			(0.37	)
Unaudited Condensed Consolidated Statements of Cash Flows
Cash flow from operating activities:
Net loss		$	(49,953	)		$	(1,029	)		$	(50,982	)
Adjustments to reconcile net loss to net cash
Deferred tax provision			(61,160	)			(274	)			(61,434	)
Contract liabilities			(3,255	)			739				(2,516	)
Contract assets			(956	)			564				(392	)

3. Impairment of Assets

2018 Impairment. During the second quarter of 2018, we recorded an impairment loss of $27.2 million to recognize a reduction in fair value of the Ocean Scepter, a jack-up rig that was reported in “Assets held for sale” in our unaudited Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017. We estimated the fair value of the impaired jack-up rig using a market approach based on a signed agreement to sell the rig, including estimated costs to sell. We consider this valuation approach to be a Level 3 fair value measurement due to the level of estimation involved as the sale had not yet been completed at the time of our analysis. The Ocean Scepter was sold in July 2018.

During the second quarter of 2018, we evaluated four of our drilling rigs with indicators of impairment. Based on our assumptions and analysis at that time, we determined that the undiscounted probability-weighted cash flow for each rig was in excess of its respective carrying value. As a result, we concluded that no impairment of these rigs had occurred at June 30, 2018.

As of June 30, 2018, there were nine rigs in our drilling fleet, not previously written down to scrap, for which there were no current indicators that their carrying amounts may not be recoverable and, thus, were not evaluated for impairment. If market fundamentals in the offshore oil and gas industry deteriorate further or a projected market recovery is further delayed, we may be required to recognize additional impairment losses in future periods.

2017 Impairments. During the second quarter of 2017, we evaluated seven of our drilling rigs with indicators of impairment and determined that the carrying values of one ultra-deepwater and one deepwater semisubmersible rig were impaired (we collectively refer to these two rigs as the “2017 Impaired Rigs”).

 

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We estimated the fair value of the 2017 Impaired Rigs using an income approach, whereby the fair value of each rig was estimated based on a calculation of the rig’s future net cash flows. These calculations utilized significant unobservable inputs, including estimated proceeds that may be received on ultimate disposition of the rig, and are representative of Level 3 fair value measurements due to the significant level of estimation involved and lack of transparency as to the inputs used. During the second quarter of 2017, we recorded an impairment loss of $71.3 million related to our 2017 Impaired Rigs.

4. Supplemental Financial Information

Condensed Consolidated Balance Sheets Information

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

 

		June 30,				December 31,
		2018				2017
Trade receivables		$	194,425			$	247,453
Value added tax receivables			13,645				14,067
Related party receivables			113				205
Other			407				464
			208,590				262,189
Allowance for bad debts			(5,459	)			(5,459	)
Total		$	203,131			$	256,730

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

 

		June 30,				December 31,
		2018				2017
Rig spare parts and supplies		$	23,887			$	28,383
Deferred contract costs			56,110				51,297
Prepaid BOP lease			3,873				3,873
Prepaid insurance			4,407				3,091
Prepaid taxes			58,417				67,212
Other			7,714				3,769
Total		$	154,408			$	157,625

Accrued liabilities consist of the following (in thousands):

 

		June 30,				December 31,
		2018				2017
Rig operating expenses		$	30,055			$	48,894
Payroll and benefits			32,929				46,560
Deferred revenue			10,173				11,371
Accrued capital project/upgrade costs			12,714				3,698
Interest payable			28,234				28,234
Personal injury and other claims			6,048				5,699
Other			9,970				10,199
Total		$	130,123			$	154,655

Includes $2.2 million and $13.6 million in accrued costs at June 30, 2018 and December 31, 2017, respectively, related to a restructuring plan that was implemented in late 2017. See Note 10.

 

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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):

 

		Six Months Ended June 30,
		2018				2017
Accrued but unpaid capital expenditures at period end		$	12,714			$	3,649
Common stock withheld for payroll tax obligations (1)			1,265				473
Cash interest payments			56,531				51,603
Cash income taxes paid, net of (refunds):
Foreign			4,035				33,319
State			2				94

 

(1)

Represents the cost of 85,580 shares and 28,386 shares of common stock withheld to satisfy payroll tax obligations incurred as a result of the vesting of restricted stock units in the six months ended June 30, 2018 and 2017, respectively. These costs for the six months ended June 30, 2018 are presented as a deduction from stockholders’ equity in “Treasury stock” in our unaudited Condensed Consolidated Balance Sheets at June 30, 2018.

5. Earnings (Loss) 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):

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
Net (loss) income – basic and diluted numerator		$	(69,274	)		$	15,949			$	(49,953	)		$	39,488
Weighted average shares – basic (denominator):			137,429				137,224				137,362				137,199
Dilutive effect of stock-based awards			—				3				—				36
Weighted average shares including conversions – diluted (denominator)			137,429				137,227				137,362				137,235
(Loss) earnings per share:
Basic		$	(0.50	)		$	0.12			$	(0.36	)		$	0.29
Diluted		$	(0.50	)		$	0.12			$	(0.36	)		$	0.29

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

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
Employee and director:
Stock options			—				—				—				1
Stock appreciation rights			1,144				1,301				1,207				1,355
Restricted stock units			1,194				1,274				1,133				933

6. Marketable Securities

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

 

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

 

		June 30, 2018
		Amortized Cost				Unrealized Gain				Market Value
U.S. Treasury bills (due within one year)		$	274,636			$	35			$	274,671

Proceeds from maturities of U.S. Treasury bills were $300.0 million during the three-month and six-month periods ended June 30, 2018. There were no sales of U.S. Treasury bills during the three-month and six-month periods ended June 30, 2018.

7. Financial Instruments and Fair Value Disclosures

Financial instruments that potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities. We generally place our excess cash investments in U.S. Treasury bills 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 June 30, 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:

 

Level 1		Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury bills. Our Level 1 assets at June 30, 2018 consisted of cash held in money market funds of $114.0 million, time deposits of $20.9 million and investments in U.S. Treasury bills of $274.7 million. Our Level 1 assets at December 31, 2017 consisted of cash held in money market funds of $337.1 million and time deposits of $20.9 million.
Level 2		Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. We had no Level 2 assets or liabilities as of June 30, 2018 or December 31, 2017.
Level 3		Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. Our Level 3 assets at June 30, 2018 and December 31, 2017 consisted of nonrecurring measurements of certain of our drilling rigs for which we recorded impairment losses during 2018 and 2017.

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 six-month period ended June 30, 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 six-month period ended June 30, 2018 and the year ended December 31, 2017 of $27.2 million and $99.3 million, respectively.

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

 

		June 30, 2018
		Fair Value Measurements Using
		Level 1				Level 2				Level 3				Assets at Fair Value				Total Losses for Period Ended (1)
Recurring fair value measurements:
Assets:
Short-term investments		$	409,616			$	—			$	—			$	409,616
Nonrecurring fair value measurements:
Assets:
Impaired assets (2)		$	—			$	—			$	67,815			$	67,815			$	27,225

 

(1)	Represents impairment loss of $27.2 million recognized during the second quarter of 2018 related to a jack-up drilling rig whose carrying value was impaired. See Note 3.

(2)	Represents the total book value as of June 30, 2018 of a jack-up rig that was written down to its estimated fair value during the second quarter of 2018 and which is reported as “Assets held for sale” in our unaudited Condensed Consolidated Balance Sheet at June 30, 2018. See Note 3.

 

		December 31, 2017
		Fair Value Measurements Using
		Level 1				Level 2				Level 3				Assets at Fair Value				Total Losses for Year Ended (1)
Recurring fair value measurements:
Assets:
Short-term investments		$	358,019			$	—			$	—			$	358,019
Nonrecurring fair value measurements:
Assets:
Impaired assets (2)		$	—			$	—			$	97,261			$	97,261			$	99,313

 

(1)	Represents impairment losses of $71.3 million and $28.0 million recognized during the second and fourth quarters of 2017, respectively, related to three drilling rigs whose carrying values were impaired. See Note 3.

(2)

Represents the total book value as of December 31, 2017 of two floaters, which were written down to their estimated fair values during the second quarter of 2017, and one jack-up rig, which was written down to its estimated fair value during the fourth quarter of 2017. Of the total fair value, $96.3 million and $1.0 million were reported as “Assets held for sale” and “Drilling and other property and equipment, net of accumulated depreciation,” respectively, in our unaudited Condensed Consolidated Balance Sheet at December 31, 2017. See Note 3.

 

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We believe that the carrying amounts of our other financial assets and liabilities (excluding long-term debt), which are not measured at fair value in our unaudited Condensed Consolidated Balance Sheets, approximate fair value based on the following assumptions:

 

•

Cash and cash equivalents — The carrying amounts approximate fair value because of the short maturity of these instruments.

 

•

Accounts receivable and accounts payable — The carrying amounts approximate fair value based on the nature of the instruments.

We consider our senior notes to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service at June 30, 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).

 

		June 30, 2018								December 31, 2017
		Fair Value				Carrying Value				Fair Value				Carrying Value
3.45% Senior Notes due 2023		$	221.9			$	249.4			$	223.1			$	249.4
7.875% Senior Notes due 2025			518.1				496.6				523.1				496.5
5.70% Senior Notes due 2039			400.0				497.2				405.0				497.2
4.875% Senior Notes due 2043			540.0				748.9				547.5				748.9

We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange.

8. Drilling and Other Property and Equipment

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

 

		June 30,				December 31,
		2018				2017
Drilling rigs and equipment		$	8,064,663			$	7,971,406
Land and buildings			63,554				63,309
Office equipment and other			87,702				82,691
Cost			8,215,919				8,117,406
Less: accumulated depreciation			(3,018,722	)			(2,855,765	)
Drilling and other property and equipment, net		$	5,197,197			$	5,261,641

9. 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. On June 1, 2018, we filed petitions with the Patent Trial and Appeal Board to challenge the validity of each of the Transocean patents through an administrative process referred to as an Inter Partes Review. 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.

 

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Asbestos Litigation. We are one of several unrelated defendants in lawsuits filed in Louisiana state courts alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted in the lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.

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

Personal Injury Claims. Under our current insurance policies, which renewed effective May 1, 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 June 30, 2018 our estimated liability for personal injury claims was $29.0 million, of which $5.3 million and $23.7 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:

 

•

the severity of personal injuries claimed;

 

•

significant changes in the volume of personal injury claims;

 

•

the unpredictability of legal jurisdictions where the claims will ultimately be litigated;

 

•

inconsistent court decisions; and

 

•

the risks and lack of predictability inherent in personal injury litigation.

Letters of Credit and Other. We were contingently liable as of June 30, 2018 in the amount of $11.2 million under certain performance, tax, bid and customs bonds and letters of credit. Agreements relating to approximately $5.5 million of tax and customs bonds can require collateral at any time. As of June 30, 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.

 

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10. Restructuring and Separation Costs

In late 2017, our management approved and initiated a plan to restructure our worldwide operations, which included a reduction in workforce at our corporate facilities and onshore bases that we refer to as the 2017 Reduction Plan. During the three-month and six-month periods ended June 30, 2018, we incurred an additional $1.3 million and $4.3 million, respectively, in severance and related costs for redundant employees identified in 2018. As of June 30, 2018, accrued costs related to severance payments to former employees were $2.2 million, of which $0.7 million is payable during the remainder of 2018 and $1.5 million is payable in 2019.

11. 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.

12. 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 June 30, 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.

 

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

 

		Three Months Ended June 30, 2018
		Floater Rigs				Jack-up Rigs(1)				Total Contract Drilling Revenues				Revenues Related to Reimbursable Expenses				Total
United States		$	158,554			$	3,648			$	162,202			$	1,172			$	163,374
South America			26,288				—				26,288				—				26,288
Europe			18,738				—				18,738				1,742				20,480
Australia/Asia			58,125				—				58,125				594				58,719
Total		$	261,705			$	3,648			$	265,353			$	3,508			$	268,861

 

(1)	Loss-of-hire insurance proceeds related to early contract terminations for two jack-up rigs that previously worked in Mexico.

 

		Six Months Ended June 30, 2018
		Floater Rigs				Jack-up Rigs (1)				Total Contract Drilling Revenues				Revenues Related to Reimbursable Expenses				Total
United States		$	318,228			$	8,413			$	326,641			$	3,309			$	329,950
South America			80,556				—				80,556				1				80,557
Europe			30,130				—				30,130				3,120				33,250
Australia/Asia			115,952				—				115,952				4,662				120,614
Total		$	544,866			$	8,413			$	553,279			$	11,092			$	564,371

 

(1)	Loss-of-hire insurance proceeds related to early contract terminations for two jack-up rigs that previously worked in Mexico.

 

		Three Months Ended June 30, 2017
		Floater Rigs				Jack-up Rigs				Total Contract Drilling Revenues				Revenues Related to Reimbursable Expenses				Total
United States		$	157,069			$	—			$	157,069			$	2,335			$	159,404
South America			111,498				—				111,498				(240	)			111,258
Europe			44,533				—				44,533				1,194				45,727
Australia/Asia			72,883				—				72,883				3,593				76,476
Mexico			—				6,187				6,187				237				6,424
Total		$	385,983			$	6,187			$	392,170			$	7,119			$	399,289

 

		Six Months Ended June 30, 2017
		Floater Rigs				Jack-up Rigs				Total Contract Drilling Revenues				Revenues Related to Reimbursable Expenses				Total
United States		$	292,668			$	—			$	292,668			$	4,456			$	297,124
South America			214,179				—				214,179				(222	)			213,957
Europe			100,268				—				100,268				3,159				103,427
Australia/Asia			138,561				—				138,561				10,009				148,570
Mexico			—				10,051				10,051				386				10,437
Total		$	745,676			$	10,051			$	755,727			$	17,788			$	773,515

 

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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. The Ocean Scepter was sold in July 2018. See “– Contract Drilling Backlog.”

Market Overview

Oil prices rose during the first half of 2018, closing above $70-per-barrel at the end of the second quarter. Despite the recovering commodity price, the offshore contract drilling market continues 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 during the first half of 2018.

In addition, the recovery of the offshore contract drilling industry continues to be challenged by an oversupply of drilling rigs, which has not yet been equalized by an increase in demand or through the retirement of rigs. Industry reports indicate that there remain approximately 40 newbuild floaters, most of which have not yet been contracted for future work, and over 90 speculative jack-up rigs currently on order with scheduled deliveries between 2018 and 2021. In addition, contract rollovers of currently contracted rigs are expected to add to the oversupply of rigs, if options for future work are not exercised or further work is not secured for these rigs. Industry analysts currently report that there could be nearly 50 contract rollovers in the second half of 2018.

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, the number of rig tenders, primarily for work in the North Sea and Australia floater markets commencing in 2019 and beyond, has increased. However, many of these tenders are limited to single-well jobs, with options for future wells. Although some geographic areas appear to be improving, other markets show little or no sign of recovery.

Given the current market conditions, contract drillers continue to seek ways to improve operating efficiencies, decrease non-productive time and ultimately reduce the cost of drilling and enhance cash flow for both the offshore driller and the customer.

See “– Contract Drilling Backlog” for future commitments of our rigs during 2018 through 2022.

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.

 

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The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 2 “Revenue from Contracts with Customers” to our 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 July 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 July 1, 2017 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2017) (in thousands).

 

		July 1, 2018(1)				January 1, 2018				July 1, 2017
Contract Drilling Backlog
Floaters		$	2,211,000			$	2,417,000			$	2,787,000
Jack-ups			—				—				156,000
Total		$	2,211,000			$	2,417,000			$	2,943,000

 

(1)	Contract drilling backlog as of July 1, 2018 excludes future commitment amounts totaling $135.0 million payable by a customer in the form of a guarantee of gross margin to be earned on future contracts or by direct payment, pursuant to terms of an existing contract.

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

 

						For the Years Ending December 31,
		Total				2018 (1)				2019				2020				2021-2022
Contract Drilling Backlog(2)		$	2,211,000			$	521,000			$	847,000			$	575,000			$	268,000

 

(1)	Represents the six-month period beginning July 1, 2018.

(2)

Contract drilling backlog as of July 1, 2018 excludes future commitment amounts of $30.0 million for 2019, $30.0 million for 2020 and $75.0 million for the 2021 through 2023 period payable by a customer in the form of a guarantee of gross margin to be earned on future contracts or by direct payment at the end of each of the three respective periods, pursuant to terms of an existing contract.

The following table reflects the percentage of rig days committed by year as of July 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).

 

						For the Years Ending December 31,
		2018 (1)				2019				2020				2021-2022
Rig Days Committed (2)			59	%			50	%			34	%			9	%

 

(1)	Represents the six-month period beginning July 1, 2018.

(2)	As of July 1, 2018, includes approximately 200, 340 and 95 currently known, scheduled days for contract preparation, mobilization of rigs, surveys and extended repair and maintenance projects for the remainder of 2018 and for the years 2019 and 2020, respectively.

Recent Agreements with Anadarko and BP. We recently entered into a series of contracts with each of Anadarko Petroleum Corporation, or Anadarko, and BP Exploration & Production Inc. and certain of its affiliates, or, collectively, BP. We agreed with Anadarko to extend the existing contract for the Ocean BlackHawk, which was scheduled to expire in June 2019, until April 2021. The operating dayrate under the extended contract will remain at $495,000 until April 2020, when it will adjust to a lower rate that is subject to a possible one-time capped increase based on then-prevailing market rates. Anadarko retains its option to extend the contract further subject to notice and mutually agreed rates. Commencing on March 1, 2019, Anadarko will temporarily suspend dayrate payments for the Ocean BlackHawk until the rig completes regulatory maintenance and equipment re-certifications. We and Anadarko also agreed to the early termination of the existing contract for the Ocean BlackHornet, which was scheduled to expire in April 2020, to be effective when the Ocean BlackHawk completes its regulatory maintenance and equipment re-certifications, expected by the end of June 2019.

BP agreed to contract the Ocean BlackHornet and another drillship to be named later, each for a term of at least two years plus two one-year unpriced options, commencing after completion of the respective drillship’s current contract and subsequent special survey, shipyard period, verification and/or any other necessary assurance activities. The operating dayrate for each contract will be within an agreed range of dayrates and will be determined within the range based on then-prevailing market rates. We and BP also agreed to the early termination of the existing contract for the Ocean GreatWhite (which was scheduled to expire in January 2020) effective July 1, 2018, and for BP to pay us a fee to be recorded by us in the fiscal quarter ending September 30, 2018. In addition to such fee and new drilling contracts, BP agreed to either pay us a total of $135 million through a series of designated payments during 2019 through 2023 or contract one or more additional drilling units owned by us so that we receive gross margin at least equal to the respective designated payment amount.

 

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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 ratably over the term of the contract under the new revenue recognition guidance. See “– Critical Accounting Policies,” Note 1 “General Information - Changes in Accounting Principles - Revenue Recognition” and Note 2 “Revenue from Contracts with Customers” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of 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 55 days for a special survey and rig upgrades for the Ocean Apex and 145 days for a special survey, reactivation activities and contract preparation for the Ocean Endeavor. In 2019, we expect to spend approximately an additional 90 days for contract preparation for the Ocean Endeavor prior to its contract commencement, an aggregate of 200 days for special surveys and rig upgrades for the Ocean BlackHawk and Ocean BlackHornet and an aggregate of 50 days for the mobilization/demobilization of the Ocean Apex and the Ocean Monarch offshore Australia. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See “ – Contract Drilling Backlog.”

Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico, as defined by the relevant insurance policy. If a named windstorm in the U.S. Gulf of Mexico causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial condition, results of operations and cash flows. Under our current insurance policy, which renewed effective May 1, 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, 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 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 - Changes in Accounting Principles,” Note 2 “Revenue from Contracts with Customers” and Note 11 “Income Taxes” to 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 six months ended June 30, 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-month and six-month periods ended June 30, 2018 and 2017.

 

		Three Months Ended June 30,								Six Months Ended June 30,
		2018				2017				2018				2017
		(In thousands, except day amounts and percentages)
REVENUE-EARNING DAYS (1)
Floaters			825				987				1,633				1,969
Jack-ups			—				82				—				134
UTILIZATION (2)
Floaters			53	%			47	%			53	%			47	%
Jack-ups			—				86	%			—				49	%
AVERAGE DAILY REVENUE (3)
Floaters		$	317,200			$	390,900			$	333,700			$	378,600
Jack-ups			—				74,900				—				74,900
REVENUE RELATED TO CONTRACT DRILLING SERVICES		$	265,353			$	392,170			$	553,279			$	755,727
REVENUE RELATED TO REIMBURSABLE EXPENSES			3,508				7,119				11,092				17,788
TOTAL REVENUES		$	268,861			$	399,289			$	564,371			$	773,515
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION		$	189,321			$	196,217			$	374,010			$	399,740
REIMBURSABLE EXPENSES		$	3,414			$	6,790			$	10,884			$	17,268
OPERATING (LOSS) INCOME
Contract drilling services, net		$	76,032			$	195,953			$	179,269			$	355,987
Reimbursable expenses, net			94				329				208				520
Depreciation			(81,825	)			(85,982	)			(163,650	)			(179,211	)
General and administrative expense			(18,236	)			(19,010	)			(36,749	)			(36,493	)
Impairment of assets			(27,225	)			(71,268	)			(27,225	)			(71,268	)
Restructuring and separation costs			(1,265	)			—				(4,276	)			—
Gain on disposition of assets			50				802				560				2,148
Total Operating (Loss) Income		$	(52,375	)		$	20,824			$	(51,863	)		$	71,683
Other income (expense):
Interest income			2,001				396				3,638				571
Interest expense, net of amounts capitalized			(29,585	)			(27,251	)			(57,903	)			(54,847	)
Foreign currency transaction loss (gain)			411				(927	)			858				160
Other, net			262				(62	)			842				(125	)
(Loss) income before income tax benefit			(79,286	)			(7,020	)			(104,428	)			17,442
Income tax benefit			10,012				22,969				54,475				22,046
NET (LOSS) INCOME		$	(69,274	)		$	15,949			$	(49,953	)		$	39,488

 

(1)	A revenue-earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days.

(2)	Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all specified rigs in our fleet (including five and ten cold-stacked floater rigs at June 30, 2018 and 2017, respectively).

(3)	Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per revenue-earning day.

 

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Three Months Ended June 30, 2018 and 2017

Net results for the second quarter of 2018 decreased $85.2 million compared to the second quarter of 2017, reflecting lower margins from our contract drilling services, primarily driven by lower contract drilling revenue and a lower tax benefit recognized. The reduction in net results was partially offset by the favorable impact of lower depreciation expense and lower impairment charges recognized in the second quarter of 2018, compared to the same period of 2017. Contract drilling services contributed operating income of $76.0 million for the second quarter of 2018, compared to operating income of $196.0 million in the second quarter of 2017.

Operating Results. Contract drilling revenue decreased $126.8 million during the second quarter of 2018 compared to the second quarter of 2017, primarily due to 244 fewer revenue-earning days ($89.8 million), combined with the effect of lower average daily revenue earned ($40.6 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 second quarter of 2017 (148 days), an increase in non-productive days (65 days) and incremental downtime for planned shipyard projects, including related mobilization days (31 days). Average daily revenue decreased during the second quarter of 2018, compared to the same period of 2017, primarily due to substantially lower dayrates earned by the Ocean Valor, which is earning a reduced standby rate until October 2018, and the Ocean Patriot, which began working under a new contract in the North Sea during the first quarter of 2018. The decrease in revenue was partially offset by $3.6 million in loss-of-hire insurance proceeds related to contract terminations of two jack-up rigs in a prior year, which were recognized during the second quarter of 2018.

Contract drilling expense, excluding depreciation, decreased $6.9 million during the second quarter of 2018 compared to the second quarter of 2017, reflecting reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense in the second quarter of 2017 ($18.7 million), partially offset by increased costs for our current rig fleet ($11.8 million). The increase in contract drilling expense during the second quarter of 2018 for our current floater fleet related primarily to higher maintenance and repair costs ($16.0 million), which included incremental costs for the Ocean Courage and costs associated with the Ocean Valiant’s special survey, combined with higher costs for fuel and inspections ($5.2 million) and other ($0.5 million). These costs were partially offset by reductions in overhead and shorebase support costs ($3.3 million), labor and related costs ($2.4 million), agency fees ($2.1 million) as a result of the termination of our agency arrangement in Brazil in December 2017 and amortized mobilization and moving costs ($2.1 million). Depreciation expense decreased $4.2 million during the second quarter of 2018, compared to the same period of 2017, primarily due to a lower depreciable asset base as a result of asset impairments recognized during 2017.

Impairment of Assets. During the second quarter of 2018, we recorded an impairment loss of $27.2 million to recognize a reduction in fair value (less costs to sell) of the Ocean Scepter, a jack-up rig that was reported in “Assets held for sale” in our unaudited Condensed Consolidated Balance Sheets at June 30, 2018 and December 31, 2017. The Ocean Scepter was sold in July 2018. During the second quarter of 2017, we recognized an aggregate impairment charge of $71.3 million with respect to the carrying values of two semisubmersible floaters, one of which was sold during the first quarter of 2018. See Notes 1 and 3 to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

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 second quarter of 2018, we recognized $1.3 million in restructuring and other employee separation related costs for redundant employees, including additional personnel identified in 2018.

Interest Expense, Net of Amounts Capitalized. Interest expense increased $2.3 million during the second quarter of 2018 compared to the second quarter of 2017, primarily as a result of incremental interest expense 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.

Income Tax Benefit. We recorded a net income tax benefit of $10.0 million for the second quarter of 2018, compared to $23.0 million for the same quarter of 2017. The difference was in large part due to the mix of our domestic and international pre-tax earnings and losses for the periods, combined with the effect of a lower U.S. statutory tax rate as a result of the Tax Cuts and Jobs Act enacted in December 2017, or the Tax Reform Act, and the income tax treatment of impairment losses recognized in the second quarters of 2018 and 2017.

 

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Six Months Ended June 30, 2018 and 2017

Net results for the first six months of 2018 decreased $89.4 million compared to the first six months of 2017, primarily driven by lower contract drilling revenue, partially offset by the favorable impact of reduced depreciation expense, a lower impairment charge and a higher income tax benefit recorded during the first half of 2018. Contract drilling services contributed operating income of $179.3 million for the first half of 2018, compared to operating income of $356.0 million in the same period of 2017, reflecting continued challenges in the contract drilling market during the first half of 2018.

Operating Results. Contract drilling revenue decreased $202.4 million during the first six months of 2018 compared to the first six months of 2017, primarily due to 470 fewer revenue-earning days ($169.3 million), combined with the effect of lower average daily revenue earned ($41.5 million). Revenue-earning days decreased during the first six months of 2018, primarily due to fewer revenue-earning days for previously-owned and currently held-for-sale rigs that operated during the first half of 2017 (289 days), incremental downtime attributable to the warm stacking of rigs between contracts (158 days) and an increase in non-productive days (38 days), partially offset by incremental revenue earning days for fewer planned shipyard projects, including related mobilization days (15 days). Average daily revenue decreased during the first six months of 2018, compared to the same period of 2017, primarily due to lower dayrates earned by the Ocean Valor and the Ocean Patriot during the first six months of 2018. The decrease in revenue was partially offset by $8.4 million in loss-of-hire insurance proceeds recognized during the first half of 2018 related to contract terminations for two jack-up rigs in a prior year.

Contract drilling expense, excluding depreciation, decreased $25.7 million during the first six months of 2018 compared to the same period in 2017, primarily due to reduced costs for currently cold-stacked and previously-owned rigs, which had incurred contract drilling expense in the first six months of 2017 ($33.9 million), partially offset by increased costs for our current rig fleet. Contract drilling expense for our current fleet increased $8.2 million during the first six months of 2018, reflecting increased costs for fuel, repairs and maintenance, including costs for the Ocean Courage, and costs associated with our Pressure Control by the Hour^® program. Contract drilling expense for the first half of 2018 also reflected reductions in labor and personnel costs, agency fees, amortized rig mobilization costs, shorebase support costs and overhead, primarily as a result of our continuing cost control initiatives. Depreciation expense decreased $15.6 million during the first half of 2018 compared to the same period of 2017, primarily due to a lower depreciable asset base as a result of asset impairments recognized during 2017.

Interest Expense, Net of Amounts Capitalized. Interest expense increased $3.1 million during the first half of 2018 compared to the same period of 2017, primarily as a result of incremental interest expense of $5.2 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 $54.5 million for the six-month period ended June 30, 2018, compared to $22.0 million for the comparable 2017 period. 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 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. Notwithstanding the reversal of the uncertain tax position, the difference in the amount of income tax benefit recognized in the 2018 period, compared to the comparable period of 2017, was in large part due to the mix of our domestic and international pre-tax earnings and losses for the periods, combined with the effect of a lower U.S. statutory tax rate as a result of the Tax Reform Act and the income tax treatment of impairment losses recognized in the second quarters of 2018 and 2017.

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, all of which was available to provide liquidity for our payment obligations as of July 27, 2018. See “ – Credit Agreement.” In addition, as of July 1, 2018, our contractual backlog was $2.2 billion of which $0.5 billion is expected to be realized during the remainder of 2018.

 

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Certain of our international rigs are owned and operated, directly or indirectly, by our Cayman Islands subsidiary Diamond Foreign Asset Company, or DFAC. As of December 31, 2017, all unremitted earnings of DFAC were deemed repatriated as a 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 June 30, 2018 and December 31, 2017, we had cash available for current operations of $144.2 million and $376.0 million, respectively. We also had investments in U.S. Treasury bills of $274.7 million at June 30, 2018, which mature at various times through August 2018.

We have historically invested a significant portion of our cash flows in the enhancement of our drilling fleet. The amount of cash required to meet our capital commitments is determined by evaluating the need to upgrade our rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs. We make periodic assessments of our capital spending programs based on current and expected industry conditions and make adjustments thereto if required.

Based on our cash available for current operations and contractual backlog, 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.”

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 half 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 six-month periods ended June 30, 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 six-month period ended June 30, 2018, our primary sources of cash were an aggregate $130.8 million generated by operating activities and proceeds of $1.7 million, primarily from the sale of the Ocean Victory in January 2018. Cash usage during the six-month period ended June 30, 2018 was primarily $273.8 million for purchases of marketable securities, net of maturities, and for capital expenditures aggregating $90.4 million.

Cash Flow from Operations. Cash flow from operations for the six-month period ended June 30, 2018 decreased $46.1 million compared to the six-month period ended June 30, 2017, primarily due to lower cash receipts for contract drilling services ($103.9 million), partially offset by a net decrease in cash expenditures for contract drilling services and other working capital requirements ($28.4 million) and lower income tax payments, net of refunds ($29.4 million).

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 June 30, 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 June 30, 2018, the total net unrecognized tax benefits related to uncertain tax positions was $63.3 million. Due to the high degree of uncertainty regarding the timing of future cash outflows associated with the liabilities recognized in these balances, we are unable to make reasonably reliable estimates of the period of cash settlement with the respective taxing authorities.

 

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Credit Agreement

At June 30, 2018, we had no borrowings outstanding under our Credit Agreement, and were in compliance with all covenants thereunder.

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 June 30, 2018 in the amount of $11.2 million under certain performance, tax, bid and customs bonds and letters of credit. Agreements relating to approximately $5.5 million of tax and customs bonds can require collateral at any time. As of June 30, 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).

 

						For the Years Ending December 31,
		Total				2018				2019
Other Commercial Commitments
Performance bonds		$	1,000			$	—			$	1,000
Tax bond			5,326				5,326				—
Bid bond			3,200				3,200				—
Other			1,677				810				867
Total obligations		$	11,203			$	9,336			$	1,867

Off-Balance Sheet Arrangements

At June 30, 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, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “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

 

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forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

 

•

market conditions and the effect of such conditions on our future results of operations;

 

•

sources and uses of and requirements for financial resources and sources of liquidity;

 

•

contractual obligations and future contract negotiations;

 

•

interest rate and foreign exchange risk;

 

•

operations outside the United States;

 

•

business strategy;

 

•

growth opportunities;

 

•

competitive position, including without limitation, competitive rigs entering the market;

 

•

expected financial position;

 

•

cash flows and contract backlog;

 

•

the extension of the Ocean BlackHawk contract, including future dayrates, revenues and extensions, and the timing of future maintenance activities and the early release of the Ocean BlackHornet contract;

 

•

new drilling contracts with and future payments from BP, including the timing, duration, commencement, dayrates and revenue associated therewith and any future drilling contracts;

 

•

idling drilling rigs or reactivating stacked rigs;

 

•

outcomes of litigation and legal proceedings;

 

•

declaration and payment of dividends;

 

•

financing plans;

 

•

market outlook;

 

•

tax planning and effects of the Tax Reform Act;

 

•

debt levels and the impact of changes in the credit markets and credit ratings for our debt;

 

•

budgets for capital and other expenditures;

 

•

timing and duration of required regulatory inspections for our drilling rigs;

 

•

timing and cost of completion of capital projects;

 

•

delivery dates and drilling contracts related to capital projects or rig acquisitions;

 

•

plans and objectives of management;

 

•

scrapping retired rigs;

 

•

assets held for sale;

 

•

purchasing or constructing rigs;

 

•

asset impairments and impairment evaluations;

 

•

our internal controls and internal control over financial reporting;

 

•

performance of contracts;

 

•

purchases of our securities;

 

•

compliance with applicable laws; and

 

•

availability, limits and adequacy of insurance or indemnification.

These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, 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.

 

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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

The information included in this Item 3 constitutes “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Statements” in Item 2 of Part I of this report.

At June 30, 2018, we had investments in U.S. Treasury bills of $274.7 million, which expose us to interest rate risk arising from changes in the level or volatility of interest rates. We monitor our sensitivity to interest rate risk by evaluating the change in the value of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is performed by applying an instantaneous change in interest rates by varying magnitudes on a static balance sheet to determine the effect such a change in rates would have on the recorded market value of our investments and the resulting effect on stockholders’ equity. The analysis provides the sensitivity of the market value of our financial instruments to selected changes in market rates and prices which we believe are reasonably possible over a one-year period.

The sensitivity analysis estimates the change in the market value of our interest sensitive assets and liabilities that were held on June 30, 2018, due to instantaneous parallel shifts in the yield curve of 100 basis points, with all other variables held constant. Based on this analysis, our estimated market risk exposure related to our investment in U.S. Treasury bills would have been $0.1 million.

The interest rates on certain types of assets and liabilities may fluctuate in advance of changes in market interest rates, while interest rates on other types may lag behind changes in market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and does not provide a precise forecast of the effect of changes in market interest rates on our earnings or stockholders’ equity. Further, the computations do not contemplate any actions we could undertake in response to changes in interest rates.

There were no other material changes in our market risk components for the six months ended June 30, 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.

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 June 30, 2018. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2018.

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

 

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PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings.

Information related to certain legal proceedings is included in Note 9 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 June  30, 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 June 30, 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

 

Period

Total Number of Shares Acquired

Average Price Paid per Share

Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs

Maximum Number of Shares that May Yet Be Purchased Under the Plans or Programs

April 1, 2018 through April 30, 2018

36,498

$

14.66

N/A

N/A

May 1, 2018 through May 31, 2018

—

—

N/A

N/A

June 1, 2018 through June 30, 2018

—

—

N/A

N/A

Total

36,498

$

14.66

N/A

N/A

 

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ITEM 6. Exhibits.

 

Exhibit No.		Description of Exhibit
3.1		Amended and Restated By-Laws (as amended through July  23, 2018) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed July 24, 2018).
10.1*		The Diamond Offshore Drilling, Inc. Incentive Compensation Plan (Amended and Restated as of January 1, 2018, as amended June 28, 2018).
10.2		Executive Retention Agreement, dated June  29, 2018, between Diamond Offshore Drilling, Inc. and Ronald Woll (incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed July 2, 2018).
31.1*		Rule 13a-14(a) Certification of the Chief Executive Officer.
31.2*		Rule 13a-14(a) Certification of the Chief Financial Officer.
32.1*		Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer.
101.INS*		XBRL Instance Document.
101.SCH*		XBRL Taxonomy Extension Schema Document.
101.CAL*		XBRL Taxonomy Calculation Linkbase Document.
101.LAB*		XBRL Taxonomy Label Linkbase Document.
101.PRE*		XBRL Presentation Linkbase Document.
101.DEF*		XBRL Definition Linkbase Document.

 

*	Filed or furnished herewith.

 

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SIGNATURES

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

 

		DIAMOND OFFSHORE DRILLING, INC.                              (Registrant)

 

Date        July 30, 2018				By:		/s/ Scott Kornblau
						Scott Kornblau
						Senior Vice President and Chief Financial Officer
						/s/ Beth G. Gordon
Date        July 30, 2018						Beth G. Gordon
						Vice President and Controller (Chief Accounting Officer)

 

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