DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2019 June (Form 10-Q)

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, 2019


☐	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)

Securities registered pursuant to Section 12(b) of the Exchange Act:

Title of each class		Trading Symbol		Name of each exchange on which registered
Common Stock, $0.01 par value per share		DO		New York Stock Exchange

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 every Interactive Data File required to be submitted 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 such files). Yes ☒No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	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 31, 2019 Common stock, $0.01 par value per share 137,694,313 shares

DIAMOND OFFSHORE DRILLING, INC.

TABLE OF CONTENTS FOR FORM 10-Q

QUARTER ENDED JUNE 30, 2019

			PAGE NO.

COVER PAGE			1

TABLE OF CONTENTS			2

PART I. FINANCIAL INFORMATION			3

	ITEM 1.	Financial Statements (Unaudited)	3
		Condensed Consolidated Balance Sheets	3
		Condensed Consolidated Statements of Operations	4
		Condensed Consolidated Statements of Comprehensive Income or Loss	5
		Condensed Consolidated Statements of Stockholders’ Equity	6
		Condensed Consolidated Statements of Cash Flows	8
		Notes to Unaudited Condensed Consolidated Financial Statements	9

	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 6.	Exhibits	32

SIGNATURES			33

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,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	147,509		$	154,073
Marketable securities		149,945			299,849
Accounts receivable, net of allowance for bad debts		163,086			168,620
Prepaid expenses and other current assets		130,124			163,396
Total current assets		590,664			785,938
Drilling and other property and equipment, net of
accumulated depreciation		5,163,696			5,184,222
Other assets		222,876			65,534
Total assets	$	5,977,236		$	6,035,694
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	60,533		$	43,933
Accrued liabilities		192,194			172,228
Taxes payable		16,722			20,685
Total current liabilities		269,449			236,846
Long-term debt		1,974,816			1,973,922
Deferred tax liability		74,281			104,380
Other liabilities		259,793			135,893
Total liabilities		2,578,339			2,451,041
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; 144,764,125 shares issued and 137,690,627 shares outstanding at June 30, 2019; 144,383,662 shares issued and 137,438,353 shares outstanding at December 31, 2018)		1,448			1,444
Additional paid-in capital		2,021,095			2,018,143
Retained earnings		1,582,099			1,769,415
Accumulated other comprehensive (loss) gain		(6	)		21
Treasury stock, at cost (7,073,498 and 6,945,309 shares of common stock at June 30, 2019 and December 31, 2018, respectively)		(205,739	)		(204,370	)
Total stockholders’ equity		3,398,897			3,584,653
Total liabilities and stockholders’ equity	$	5,977,236		$	6,035,694

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

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,
	2019			2018			2019			2018
Revenues:
Contract drilling	$	207,273		$	265,353		$	433,970		$	553,279
Revenues related to reimbursable expenses		9,433			3,508			16,278			11,092
Total revenues		216,706			268,861			450,248			564,371
Operating expenses:
Contract drilling, excluding depreciation		224,782			189,321			392,210			374,010
Reimbursable expenses		9,313			3,414			16,057			10,884
Depreciation		88,253			81,825			175,151			163,650
General and administrative		15,294			18,236			32,605			36,749
Impairment of assets		—			27,225			—			27,225
Restructuring and separation costs		—			1,265			—			4,276
Gain on disposition of assets		(9,436	)		(50	)		(5,149	)		(560	)
Total operating expenses		328,206			321,236			610,874			616,234
Operating loss		(111,500	)		(52,375	)		(160,626	)		(51,863	)
Other income (expense):
Interest income		1,933			2,001			4,346			3,638
Interest expense, net of amounts capitalized		(31,159	)		(29,585	)		(61,084	)		(57,903	)
Foreign currency transaction (loss) gain		(721	)		411			(1,806	)		858
Other, net		105			262			438			842
Loss before income tax benefit		(141,342	)		(79,286	)		(218,732	)		(104,428	)
Income tax benefit		27,354			10,012			31,416			54,475
Net loss	$	(113,988	)	$	(69,274	)	$	(187,316	)	$	(49,953	)
Loss per share, Basic and Diluted	$	(0.83	)	$	(0.50	)	$	(1.36	)	$	(0.36	)
Weighted-average shares outstanding:
Shares of common stock		137,691			137,429			137,607			137,362
Dilutive potential shares of common stock		—			—			—			—
Total weighted-average shares outstanding		137,691			137,429			137,607			137,362

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME OR LOSS

(Unaudited)

(In thousands)

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Net loss	$	(113,988	)	$	(69,274	)	$	(187,316	)	$	(49,953	)
Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Reclassification adjustment for gain included in net loss		(2	)		(1	)		(3	)		(3	)
Investments in marketable securities:
Unrealized holding gain		9			31			23			31
Reclassification adjustment for gain included in net loss		(15	)		-			(47	)		-
Total other comprehensive (loss) gain		(8	)		30			(27	)		28
Comprehensive loss	$	(113,996	)	$	(69,244	)	$	(187,343	)	$	(49,925	)

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(Unaudited)

(In thousands, except number of shares)

	Three Months Ended June 30, 2019
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
April 1, 2019		144,606,992	$	1,446	$	2,019,555	$	1,696,087		$	2			7,026,789	$	(205,214	)	$	3,511,876
Net loss		—		—		—		(113,988	)		—			—		—			(113,988	)
Stock-based compensation, net of tax		157,133		2		1,540		—			—			46,709		(525	)		1,017
Net loss on investments		—		—		—		—			(6	)		—		—			(6	)
Net loss on derivative financial instruments		—		—		—		—			(2	)		—		—			(2	)
June 30, 2019		144,764,125	$	1,448	$	2,021,095	$	1,582,099		$	(6	)		7,073,498	$	(205,739	)	$	3,398,897

	Six Months Ended June 30, 2019
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
January 1, 2019		144,383,662	$	1,444	$	2,018,143	$	1,769,415		$	21			6,945,309	$	(204,370	)	$	3,584,653
Net loss		—		—		—		(187,316	)		—			—		—			(187,316	)
Stock-based compensation, net of tax		380,463		4		2,952		—			—			128,189		(1,369	)		1,587
Net loss on investments		—		—		—		—			(24	)		—		—			(24	)
Net loss on derivative financial instruments		—		—		—		—			(3	)		—		—			(3	)
June 30, 2019		144,764,125	$	1,448	$	2,021,095	$	1,582,099		$	(6	)		7,073,498	$	(205,739	)	$	3,398,897

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY – Continued

(Unaudited)

(In thousands, except number of shares)

	Three Months Ended June 30, 2018
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
April 1, 2018		144,249,563	$	1,442	$	2,012,993	$	1,969,006		$	(7	)		6,906,592	$	(203,802	)	$	3,779,632
Net loss		—		—		—		(69,274	)		—			—		—			(69,274	)
Anti-dilution adjustment		—		—		—		3			—			—		—			3
Stock options exercised		3,773		—		—		—			—			—		—			—
Stock-based compensation, net of tax		120,670		2		869		—			—			36,498		(532	)		339
Net gain on investments		—		—		—		—			31			—		—			31
Net loss on derivative financial instruments		—		—		—		—			(1	)		—		—			(1	)
June 30, 2018		144,374,006	$	1,444	$	2,013,862	$	1,899,735		$	23			6,943,090	$	(204,334	)	$	3,710,730

	Six Months Ended June 30, 2018
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
December 31, 2017		144,085,292	$	1,441	$	2,011,397	$	1,964,497		$	(5	)		6,857,510	$	(203,069	)	$	3,774,261
Impact of change in accounting principle		—		—		—		(14,812	)		—			—		—			(14,812	)
Adjusted balance at January 1, 2018		144,085,292	$	1,441	$	2,011,397	$	1,949,685		$	(5	)		6,857,510	$	(203,069	)	$	3,759,449
Net loss		—		—		—		(49,953	)		—			—		—			(49,953	)
Anti-dilution payments		—		—		—		3			—			—		—			3
Stock options exercised		3,773		—		—		—			—			—		—			—
Stock-based compensation, net of tax		284,941		3		2,465		—			—			85,580		(1,265	)		1,203
Net gain on investments		—		—		—		—			31			—		—			31
Net loss on derivative financial instruments		—		—		—		—			(3	)		—		—			(3	)
June 30, 2018		144,374,006	$	1,444	$	2,013,862	$	1,899,735		$	23			6,943,090	$	(204,334	)	$	3,710,730

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

DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Unaudited)

(In thousands)

	Six Months Ended
	June 30,
	2019			2018
Operating activities:
Net loss	$	(187,316	)	$	(49,953	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation		175,151			163,650
Loss on impairment of assets		—			27,225
Gain on disposition of assets		(5,149	)		(560	)
Deferred tax provision		(31,125	)		(61,160	)
Stock-based compensation expense		2,956			2,468
Contract liabilities, net		14,017			(3,255	)
Contract assets, net		(566	)		(956	)
Deferred contract costs, net		26,879			24,703
Other assets, noncurrent		(118	)		742
Other liabilities, noncurrent		3			(3,849	)
Other		(1,300	)		2,577
Changes in operating assets and liabilities:
Accounts receivable		5,534			53,451
Prepaid expenses and other current assets		(2,002	)		28
Accounts payable and accrued liabilities		9,961			(21,466	)
Taxes payable		(9,608	)		(2,878	)
Net cash (used in) provided by operating activities		(2,683	)		130,767
Investing activities:
Capital expenditures		(172,335	)		(90,432	)
Proceeds from maturities of marketable securities		2,025,000			300,000
Purchase of marketable securities		(1,872,107	)		(573,837	)
Proceeds from disposition of assets, net of disposal costs		15,573			1,723
Net cash used in investing activities		(3,869	)		(362,546	)
Financing activities:
Other		(12	)		(90	)
Net cash used in financing activities		(12	)		(90	)
Net change in cash and cash equivalents		(6,564	)		(231,869	)
Cash and cash equivalents, beginning of period		154,073			376,037
Cash and cash equivalents, end of period	$	147,509		$	144,168

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

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, 2018 (File No. 1-13926).

As of July 26, 2019, 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 or loss, statements of stockholders’ equity 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.

Recently Adopted Accounting Pronouncements

In February 2016, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or 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 most 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 an entity's leasing arrangements.

We adopted ASU 2016-02 effective January 1, 2019 using an optional transition method requiring leases existing at, or entered into after, January 1, 2019 to be recognized and measured under the new accounting standard. Prior period amounts have not been adjusted and continue to be reflected in accordance with our historical accounting for leases. In our adoption of ASU 2016-02, we also utilized a transition practical expedient package whereby we did 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. The adoption of this standard resulted in the recording of operating lease assets and offsetting operating lease liabilities of $146.8 million as of January 1, 2019, with no related impact on our unaudited Condensed Consolidated Statements of Stockholders’ Equity. See Note 10.

Upon adoption of ASU 2016-02, we concluded that our drilling contracts contain a lease component for the use of our drilling rigs based on the updated definition of a lease. However, ASU 2016-02 provides for a practical expedient for lessors whereby, under certain circumstances, the lessor may combine the lease and non-lease components and account for the combined component in accordance with the accounting treatment for the predominant component. We have determined that our current drilling contracts qualify for this practical expedient and have combined the lease and service components of our standard drilling contracts. We continue to account for the combined component under ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606) and its related amendments, or collectively Topic 606.

Accounting Pronouncements Not Yet Adopted

In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments, or ASU 2016-13. ASU 2016-13 requires changes to the recognition of credit losses on financial instruments not accounted for at fair value through net income, including loans, debt securities, trade receivables, net investments in leases and available-for-sale debt securities. The amended standard broadens the information that an entity must consider in developing its estimate of expected credit losses, requiring an entity to estimate credit losses over the life of an exposure based on historical information, current information and reasonable and supportable forecasts. The guidance is effective for interim and annual periods beginning after December 15, 2019 and will be applied using a modified retrospective method with a cumulative effect adjustment to beginning retained earnings. We are currently evaluating the effect the guidance will have on our consolidated financial statements.

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. 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.

Dayrate and other revenue for activities that correspond to a distinct time increment within the contract term are recognized in the period in which the services are performed. 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 is allocated across the single performance obligation and recognized ratably in proportion to the actual services performed 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). Such consideration may include mobilization, demobilization, contract preparation and capital modification revenue that is stipulated in our drilling contracts.

Contract Balances

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

	June 30,			December 31,
	2019			2018
Trade receivables	$	153,638		$	160,463
Current contract assets ⁽¹⁾		7,398			6,832
Noncurrent contract assets ⁽¹⁾		2,107			2,107
Current contract liabilities (deferred revenue) ⁽¹⁾		(9,521	)		(2,803	)
Noncurrent contract liabilities (deferred revenue) ⁽¹⁾		(25,023	)		(17,723	)

⁽¹⁾

Contract assets and contract liabilities may reflect balances which 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 Sheets.

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, 2019	$	8,939
Contract liabilities at January 1, 2019		(20,526	)
Net balance at January 1, 2019		(11,587	)
Decrease due to amortization of revenue included in the beginning contract liability balance		3,681
Increase due to cash received, excluding amounts recognized as revenue during the period		(17,698	)
Increase due to revenue recognized during the period but contingent on future performance		2,535
Decrease due to transfer to receivables during the period		(926	)
Adjustments		(1,044	)
Net balance at June 30, 2019	$	(25,039	)
Contract assets at June 30, 2019	$	9,505
Contract liabilities at June 30, 2019		(34,544	)

Transaction Price Allocated to Remaining Performance Obligations

The following table reflects the specified types of revenue expected to be recognized in the future related to unsatisfied performance obligations as of June 30, 2019 (in thousands):

	For the Years Ending December 31,
	2019 ⁽¹⁾		2020		2021		2022		Total
Mobilization and contract preparation revenue	$	3,071	$	571	$	632	$	124	$	4,398
Capital modification revenue		3,364		4,937		229		—		8,530
Blended rate revenue		—		16,933		5,542		—		22,475
Total	$	6,435	$	22,441	$	6,403	$	124	$	35,403

⁽¹⁾	Represents the six-month period beginning July 1, 2019.

The revenue included above consists of expected fixed mobilization and upgrade revenue for both wholly and partially unsatisfied performance obligations as well as expected variable mobilization and upgrade revenue for partially unsatisfied performance obligations, which has been estimated for purposes of allocating across the entire corresponding performance obligations. Revenue expected to be recognized in the future related to the blending of rates when a contract has operating dayrates that decrease over the initial contract term is also included. 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, 2019. 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 Topic 606 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.

3. Impairment of Assets

2019 Evaluation. During the second quarter of 2019, we evaluated three 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, 2019.

As of June 30, 2019, there were ten 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.

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 marketed for sale at that time. We estimated the fair value of the impaired jack-up rig using a market approach based on a signed agreement to sell the rig, less estimated costs to sell. We considered 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.

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,
	2019			2018
Trade receivables	$	153,638		$	160,463
Value added tax receivables		14,314			13,237
Related party receivables		133			174
Other		460			205
		168,545			174,079
Allowance for bad debts		(5,459	)		(5,459	)
Total	$	163,086		$	168,620

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

	June 30,		December 31,
	2019		2018
Deferred contract costs	$	45,736	$	70,021
Prepaid taxes		45,621		54,412
Rig spare parts and supplies		17,873		20,256
Current contract assets		7,398		6,832
Prepaid insurance		4,490		2,742
Other		9,006		9,133
Total	$	130,124	$	163,396

Accrued liabilities consist of the following (in thousands):

	June 30,		December 31,
	2019		2018
Payroll and benefits	$	43,340	$	47,564
Rig operating expenses		39,980		42,323
Accrued capital project/upgrade costs		32,916		37,379
Interest payable		28,234		28,234
Current operating lease liability		19,697		—
Personal injury and other claims		5,408		5,544
Deferred revenue		9,521		2,803
Shorebase and administrative costs		5,190		6,217
Other		7,908		2,164
Total	$	192,194	$	172,228

We adopted ASU 2016-02 effective January 1, 2019, which required us to recognize a right of use asset and a lease liability on the balance sheet for most leases. See Note 10.

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,
	2019			2018
Accrued but unpaid capital expenditures at period end	$	32,916		$	12,714
Common stock withheld for payroll tax obligations ⁽¹⁾		1,369			1,265
Cash interest payments		56,531			56,531
Cash income taxes paid, net of (refunds):
Foreign		10,025			4,035
State		(15	)		2

⁽¹⁾

Represents the cost of 128,189 shares and 85,580 shares of common stock withheld to satisfy payroll tax obligations incurred as a result of the vesting of restricted stock units in the six-month periods ended June 30, 2019 and 2018, respectively. These costs are presented as a deduction from stockholders’ equity in “Treasury stock” in our unaudited Condensed Consolidated Balance Sheets at June 30, 2019 and 2018, respectively.

5. Loss Per Share

We present basic and diluted net income (loss) per share on our Condensed Consolidated Statements of Operations. Basic net income (loss) per share excludes dilution and is computed by dividing net income (loss) by the weighted-average number of common shares outstanding for the period. Diluted net income (loss) per share reflects the potential dilution that could occur if securities or other contracts to issue common stock (common share equivalents) were exercised or converted into common stock, unless the effect would be antidilutive. For all periods in which we experience a net loss, all shares of common stock issuable upon exercise of outstanding stock appreciation rights and vesting of outstanding restricted stock units have been excluded from the calculation of weighted-average shares because their inclusion would be antidilutive.

The following table sets forth the share effects of stock-based awards excluded from the computations of diluted loss per share (in thousands).

	Three Months Ended June 30,				For the Six Months Ended June 30,
	2019		2018		2019		2018
Employee and director:
Stock appreciation rights		994		1,144		1,008		1,207
Restricted stock units		1,273		1,194		1,151		1,133

6. Marketable Securities

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

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

June 30, 2019

Amortized

Cost

Unrealized

Gain

Market

Value

U.S. Treasury bills (due within one year)

149,935

149,945

December 31, 2018

Amortized Cost

Unrealized

Gain

Market

Value

U.S. Treasury bills (due within one year)

299,813

299,849

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, 2019.

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 customer. 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 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.

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.

Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. Assets measured at fair value are summarized below (in thousands).

	June 30, 2019
	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Assets at Fair Value
U.S. Treasury bills	$	149,945	$	—	$	—	$	149,945
Money market funds		134,319		—		—		134,319
Total short-term investments	$	284,264	$	—	$	—	$	284,264

	Year ended December 31, 2018
	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Assets at Fair Value
U.S. Treasury bills	$	299,849	$	—	$	—	$	299,849
Money market funds		135,822		—		—		135,822
Total short-term investments	$	435,671	$	—	$	—	$	435,671

We had no Level 2 or Level 3 assets or liabilities as of June 30, 2019 or December 31, 2018 that were required to be valued at fair value on a recurring basis.

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.

Our senior notes are not measured at fair value; however, under the GAAP fair value hierarchy, our long-term debt would be considered Level 2 liabilities. The fair value of our senior notes was derived using a third-party pricing service at June 30, 2019 and December 31, 2018. 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, 2019				December 31, 2018
	Fair Value		Carrying Value		Fair Value		Carrying Value
3.45% Senior Notes due 2023	$	210.0	$	249.5	$	185.0	$	249.5
7.875% Senior Notes due 2025		475.0		497.1		415.0		496.8
5.70% Senior Notes due 2039		335.0		497.3		305.0		497.2
4.875% Senior Notes due 2043		465.0		748.9		416.3		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,
	2019			2018
Drilling rigs and equipment	$	8,228,429		$	8,210,824
Land and buildings		63,795			63,757
Office equipment and other		91,887			91,819
Cost		8,384,111			8,366,400
Less: accumulated depreciation		(3,220,415	)		(3,182,178	)
Drilling and other property and equipment, net	$	5,163,696		$	5,184,222

In April 2019, we sold the Ocean Guardian, a previously impaired semisubmersible rig, for a net pre-tax gain of $14.3 million. In addition, during the six months ended June 30, 2019, we disposed of certain other property and equipment and recognized an aggregate net pre-tax loss of $9.2 million.

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.

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. Additionally, tax authorities in Brazil have issued tax assessments on intercompany revenue between our subsidiaries doing business in Brazil that, if upheld by the Brazilian courts, could result in additional taxes, interest and penalties for which the fully assessed amounts would be material to our financial statements. 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 insurance policies, 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 $5.0 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. 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 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, 2019 our estimated liability for personal injury claims was $25.2 million, of which $4.9 million and $20.3 million were recorded in “Accrued liabilities” and “Other liabilities,” respectively, in our unaudited Condensed Consolidated Balance Sheets. At December 31, 2018 our estimated liability for personal injury claims was $27.9 million, of which $5.2 million and $22.7 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 and volume of personal injuries claimed;

•

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, 2019 in the amount of $41.7 million under certain customs, performance, tax and VAT bonds and letters of credit. Agreements relating to approximately $33.2 million of tax and customs bonds can require collateral at any time. As of June 30, 2019, 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.

10. Leases and Lease Commitments

Our leasing activities primarily consist of operating leases for shorebase offices, office and information technology equipment, employee housing, vehicles, onshore storage yards and certain rig equipment and tools. Our leases have terms ranging from one month to ten years, some of which include options to extend the lease for up to five years and/or to terminate the lease within one year.

Additionally, we are participants in four sale and leaseback arrangements with a subsidiary of General Electric Company, or GE, pursuant to the 2016 sale of certain blowout preventers and related well control equipment, or Well Control Equipment, on our drillships and corresponding agreements to lease back that equipment under ten-year operating leases for approximately $26 million per year in the aggregate with renewal options for two successive five-year periods. At the time of the transactions with GE, the carrying value of the Well Control Equipment exceeded the aggregate proceeds received from the sale, resulting in the recognition of prepaid rent, which was being amortized over the respective terms of the leases. On January 1, 2019, as a result of the adoption of ASU 2016-02, the aggregate remaining prepaid rent balances of $3.9 million and $10.6 million, previously recorded as “Prepaid expenses and other current assets” and “Other assets,” respectively, were reclassified to a right-of-use lease asset within “Other assets” in our unaudited Condensed Consolidated Balance Sheets and continue to be amortized over the remaining terms of the leases. In connection with the sale and leaseback transactions, we also entered into a ten-year service agreement with a subsidiary of Baker Hughes, a GE company, or BHGE, another GE affiliate, pertaining to the Well Control Equipment. Such services include management of maintenance, certification and reliability with respect to such equipment.

In applying 2016-02, we utilize an exemption for short-term leases whereby we do not record leases with terms of one year or less on the balance sheet. We have also made an accounting policy election not to separate lease components from non-lease components for each of our classes of underlying assets, except for subsea equipment, which includes the Well Control Equipment discussed above. At inception, the consideration for the overall Well Control Equipment arrangement was allocated between the lease and service components based on an estimation of

stand-alone selling price of each component, which maximized observable inputs. The costs associated with the service portion of the agreement are accounted for separately from the cost attributable to the equipment leases based on that allocation and thus, are not included in our right-of-use lease asset or lease liability balances. The non-lease components for each of our other classes of assets generally relate to maintenance, monitoring and security services and are not separated from their respective lease components.

The lease term used for calculating our right-of-use assets and lease liabilities is determined by considering the noncancelable lease term, as well as any extension options that we are reasonably certain to exercise. The determination to include option periods is generally made by considering the activity in the region or for the rig corresponding to the respective lease, among other contract-based and market-based factors. We have used our incremental borrowing rate to discount future lease payments as the rate implicit in our leases is not readily determinable. To arrive at our incremental borrowing rate, we consider our unsecured borrowings and then adjust those rates to assume full collateralization and to factor in the individual lease term and payment structure.

Total operating lease expense for the three and six months ended June 30, 2019 was $9.5 million and $18.9 million, respectively, of which $0.8 million and $2.1 million, respectively, related to short-term leases. Total operating lease expense for the three and six months ended June 30, 2018 was $7.4 million and $15.0 million, respectively.

Supplemental information related to leases is as follows (in thousands, except weighted-average data):

	Six Months Ended June 30, 2019
Operating cash flows used for operating leases	$	20,659
Right-of-use assets obtained in exchange for lease liabilities		16,300
Weighted-average remaining lease term	7.0 years
Weighted-average discount rate		8.63	%

Future minimum rental payments under noncancelable operating leases as of December 31, 2018 were as follows (in thousands):

2019	$	28,373
2020		27,144
2021		26,565
2022		26,281
2023		26,280
Thereafter		64,062
Total lease payments	$	198,705

Maturities of lease liabilities as of June 30, 2019 are as follows (in thousands):

2019 (excluding six months ended June 30, 2019)	$	17,079
2020		30,597
2021		28,702
2022		28,252
2023		28,236
2024		28,315
Thereafter		46,448
Total lease payments		207,629
Less: interest		(52,990	)
Total lease liability	$	154,639
Amounts recognized in unaudited Condensed Consolidated Balance Sheets:
Accrued liabilities	$	19,697
Other liabilities		134,942
Total operating lease liability	$	154,639

Operating lease assets, including prepaid rent balances related to the GE transaction, totaling $171.0 million are included in “Other assets” in our unaudited Condensed Consolidated Balance Sheets as of June 30, 2019.

As of June 30, 2019, we had an additional operating lease for mooring equipment to be used on a rig that has not yet commenced. The agreement, which is expected to commence in September 2019, provides for fixed lease payments of approximately $12 million in the aggregate to be paid over a lease term of 9.5 years.

11. 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, 2019, our active drilling rigs were located offshore three 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 and, unless otherwise noted, reflect earnings attributable to our floater rigs (drillships and semisubmersibles).

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

	Three Months Ended June 30, 2019
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses			Total
United States	$	117,423	$	1,603		$	119,026
South America		29,139		(23	)		29,116
Europe		39,413		2,930			42,343
Australia		21,298		4,923			26,221
Total	$	207,273	$	9,433		$	216,706

	Six Months Ended June 30, 2019
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	256,055	$	3,551	$	259,606
South America		82,423		6		82,429
Europe		64,022		4,836		68,858
Australia		31,470		7,885		39,355
Total	$	433,970	$	16,278	$	450,248

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

⁽¹⁾	Includes $3.6 million in loss-of-hire insurance proceeds received in 2018 related to early contract terminations in prior years for two jack-up rigs that previously worked in Mexico.

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

⁽¹⁾	Includes $8.4 million in loss-of-hire insurance proceeds received in 2018 related to early contract terminations in prior years for two jack-up rigs that previously worked in Mexico.

12. Income Taxes

In June 2019, the Internal Revenue Service issued final regulations with respect to the calculation of the toll charge associated with the deemed repatriation of previously deferred earnings of our non-U.S. subsidiaries, or Transition Tax, in response to the Tax Cuts and Jobs Act enacted in 2017. Based on the new regulations, we recorded a net tax benefit of $14.2 million in the second quarter of 2019, primarily to reverse a previously recorded uncertain tax position related to the Transition Tax.

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, Item 1A, “Risk Factors,” included in Part II 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, 2018. 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 16 floater rigs (four drillships and 12 semisubmersibles), of which three rigs are currently cold-stacked. The reactivation and upgrade of the Ocean Onyx is continuing, and we expect the rig to begin contract preparation activities in late 2019 for an early 2020 contract commencement. The Ocean Guardian was sold during the second quarter of 2019.

Market Overview

During the second quarter of 2019, the average price for Brent crude oil was in the high $60-per-barrel level, and overall floater demand and offshore utilization increased marginally, with industry-wide floater utilization averaging near 66% at the end of June 2019, based on industry analyst reports. Within the floater rig class, the ultra-deepwater floaters remain the most distressed asset class, with industry-wide utilization reported at 63% at the end of the second quarter of 2019. In general, dayrates remain low compared to previous periods, as the increase in oil prices from earlier lows has not resulted in significantly higher dayrates. Industry analysts indicate that, based on historical data, utilization rates have had to increase to the 80%-range before pricing power has shifted to the drilling contractor from the customer. Some analysts believe that the offshore contract drilling market will recover over the next two years, as additional offshore projects are expected to be sanctioned to replace oil and gas reserves and to meet predicted growing energy demand. However, many of these are expected to be greenfield, or new oil and gas development, projects for which drilling does not typically commence until the second, third or fourth year of development. Capital investments in offshore projects will also compete with onshore shale in the U.S.

During the first half of 2019, the number of contract tenders for 2020 and 2021 floater project commencements increased, primarily for work in the North Sea and Australia markets. Industry analysts also predict that there will be additional opportunities in the West Africa market in the near term. Presently, many of these tenders have been 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 at this time.

From a supply perspective, industry analysts have reported that despite a decrease in the global supply of floater rigs over the past four years, the offshore contract drilling market remains oversupplied. Rig attrition has slowed, with only five floaters having been retired during 2019 as of the date of this report. However, recent mergers and acquisitions in the offshore drilling industry could result in additional rig retirements as drillers assess and optimize their fleets. Industry analysts report that there are approximately 100 cold-stacked floaters, which could potentially be reactivated, but reactivation costs can be substantial and generally increase the longer a rig remains cold stacked. In addition, industry reports indicate that approximately 40 newbuild floaters remain on order with deliveries currently scheduled between 2019 and 2022, most of which have not yet been contracted for future work, and approximately 50 projected contracted floater rollovers are estimated to occur during the remainder of 2019. These factors provide for a continued, challenging offshore drilling market in the near term.

As a result of these challenges, we and other offshore drillers are actively seeking ways to drive efficiency, reduce non-productive time on rigs and provide technical innovation to customers. New rig technology, automation and other operating and supply chain efficiencies are resulting in the faster drilling and completion of wells, leading to lower well costs for customers.

See “– Contract Drilling Backlog” for future commitments of our rigs during 2019 through 2023.

Contract Drilling Backlog

Our 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. Our utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts. In addition, under certain circumstances, our customers may seek to terminate or renegotiate our contracts, which could adversely affect our reported backlog.

The backlog information presented below does not, nor is it intended to, align with the disclosures related to revenue expected to be recognized in the future related to unsatisfied performance obligations, which are presented in Note 2 “Revenue from Contracts with Customers” 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, 2019 (based on information available at that time), January 1, 2019 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2018), and July 1, 2018 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2018) (in thousands).

July 1,

2019 ⁽¹⁾

January 1,

2019 ⁽¹⁾

July 1,

2018

Contract Drilling Backlog

1,984,000

1,973,000

2,211,000

⁽¹⁾

Contract drilling backlog as of July 1, 2019 and January 1, 2019 excludes future commitment amounts totaling approximately $130.0 million and $135 million, respectively, 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, 2019 (in thousands).

	For the Years Ending December 31,
	Total		2019 ⁽¹⁾		2020		2021		2022		2023
Contract Drilling Backlog ⁽²⁾	$	1,984,000	$	459,000	$	817,000	$	376,000	$	247,000	$	85,000

⁽¹⁾	Represents the six-month period beginning July 1, 2019.

⁽²⁾

Contract drilling backlog as of July 1, 2019 excludes future gross margin commitments totaling approximately $130.0 million, which is comprised of $30.0 million for 2019, approximately $25.0 million for 2020 and an aggregate $75.0 million for the 2021 through 2023 period. These amounts are 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, 2019. 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,
	2019 ⁽¹⁾			2020			2021			2022			2023
Rig Days Committed ⁽²⁾		74	%		68	%		29	%		16	%		5	%

⁽¹⁾	Represents the six-month period beginning July 1, 2019.

⁽²⁾	As of July 1, 2019, includes approximately 380 days, 360 days and 55 days currently known and scheduled for contract preparation, mobilization of rigs, surveys and extended repair and maintenance projects for the remainder of 2019 and for the years 2020 and 2021, respectively.

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

Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs. The inspection interval for our North Sea rigs is two-and-one-half years. In addition, our operating income is negatively impacted by planned downtime for upgrades, contract preparation and mobilization of rigs; however, in some cases, we may be compensated for all or a portion of this downtime. We expect to spend approximately 380 days during the remainder of 2019 for upgrades, contract preparation and mobilization of rigs, which includes an aggregate of approximately 185 days for the completion of upgrades, reactivation activities and contract preparation for the Ocean Onyx prior to its contract commencement and an aggregate of approximately 155 days for special surveys and rig upgrades for the Ocean BlackHawk, Ocean BlackHornet and Ocean BlackRhino. In 2020, we expect to spend an aggregate of approximately 240 days for upgrades for the Ocean BlackRhino and a special survey and upgrades for the Ocean BlackLion, approximately 70 days for the mobilization of and contract preparation for the Ocean Monarch prior to its contract in Myanmar and approximately 50 days for mobilizations of other rigs. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, rig mobilizations and other shipyard projects. See “ – Contract Drilling Backlog.”

Regulatory Compliance. In May 2019, the U.S. Department of the Interior’s Bureau of Safety and Environmental Enforcement, which governs offshore drilling in the U.S. Outer Continental Shelf, or OCS, issued its final Well Control Rule on blowout preventer systems and well control regulations. The final Well Control Rule leaves 274 of the original 342 well control rule provisions unchanged, identified 68 provisions for revision and added 33 provisions to improve operations in the OCS. Based on our review of the final Well Control Rule, we do not believe that we will have any foreseeable material compliance issues and do not believe that any additional material equipment modifications will be required for our rigs currently working in the OCS.

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, 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. Under these policies 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 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 $5.0 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, 2018. Effective January 1,

2019, we adopted the Financial Accounting Standards Board Accounting Standards Update No. 2016-02, Leases (Topic 842), or ASU 2016-02, which, among other things, requires lessees to recognize a right of use asset and a lease liability for most leases. See Note 1 “General Information - Recently Adopted Accounting Pronouncements” and Note 10 “Leases and Lease Commitments” 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, 2019.

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, 2019 and 2018.

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In thousands, except days, daily amounts and percentages)
REVENUE-EARNING DAYS ⁽¹⁾		758			825			1,492			1,633
UTILIZATION ⁽²⁾		51	%		53	%		49	%		53	%
AVERAGE DAILY REVENUE ⁽³⁾	$	273,400		$	317,200		$	290,900		$	333,700
REVENUE RELATED TO CONTRACT DRILLING SERVICES	$	207,273		$	265,353		$	433,970		$	553,279
REVENUE RELATED TO REIMBURSABLE EXPENSES		9,433			3,508			16,278			11,092
TOTAL REVENUES	$	216,706		$	268,861		$	450,248		$	564,371
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION	$	224,782		$	189,321		$	392,210		$	374,010
REIMBURSABLE EXPENSES	$	9,313		$	3,414		$	16,057		$	10,884
OPERATING LOSS
Contract drilling services, net	$	(17,509	)	$	76,032		$	41,760		$	179,269
Reimbursable expenses, net		120			94			221			208
Depreciation		(88,253	)		(81,825	)		(175,151	)		(163,650	)
General and administrative expense		(15,294	)		(18,236	)		(32,605	)		(36,749	)
Impairment of assets		-			(27,225	)		-			(27,225	)
Restructuring and separation costs		-			(1,265	)		-			(4,276	)
Gain on disposition of assets		9,436			50			5,149			560
Total Operating Loss	$	(111,500	)	$	(52,375	)	$	(160,626	)	$	(51,863	)
Other income (expense):
Interest income		1,933			2,001			4,346			3,638
Interest expense, net of amounts capitalized		(31,159	)		(29,585	)		(61,084	)		(57,903	)
Foreign currency transaction (loss) gain		(721	)		411			(1,806	)		858
Other, net		105			262			438			842
Loss before income tax benefit		(141,342	)		(79,286	)		(218,732	)		(104,428	)
Income tax benefit		27,354			10,012			31,416			54,475
NET LOSS	$	(113,988	)	$	(69,274	)	$	(187,316	)	$	(49,953	)

⁽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 three and five cold-stacked rigs at June 30, 2019 and 2018, respectively).

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

Three Months Ended June 30, 2019 and 2018

Net results for the second quarter of 2019 decreased $44.7 million compared to the second quarter of 2018, reflecting lower margins from our contract drilling services, primarily driven by lower contract drilling revenue combined with an increase in contract drilling expenses. Contract drilling services contributed a $17.5 million operating loss during the second quarter of 2019, compared to operating income of $76.0 million in the second quarter of 2018. Our results for the second quarter of 2019 were also negatively impacted by higher depreciation expense of $6.4 million, primarily due to capital expenditures made since the latter part of 2018 and the completion of software implementation projects. These unfavorable impacts to our net results were partially offset by a $9.4 million net gain on the disposition of assets and an incremental tax benefit of $17.3 million recognized during the second quarter of 2019, combined with the absence of an impairment charge and restructuring costs recorded in the second quarter of 2018.

Operating Results. Contract drilling revenue decreased $58.1 million during the second quarter of 2019 compared to the second quarter of 2018, primarily due to lower average daily revenue earned ($33.2 million), the effect of 67 fewer revenue-earning days ($21.3 million) and the absence of $3.6 million in loss-of-hire insurance proceeds recognized during the second quarter of 2018 related to contract terminations for two jack-up rigs in a prior year. Comparing the two quarters, average daily revenue decreased primarily due to a lower dayrate earned by the Ocean GreatWhite, which commenced operations under a new contract in the U.K. during the first quarter of 2019. Revenue-earning days decreased, compared to the second quarter of 2018, due to incremental downtime for planned shipyard projects and mobilization of rigs (95 days) and fewer revenue-earning days for the Ocean Guardian, which operated throughout the second quarter of 2018 but was sold in 2019 (91 days), partially offset by the favorable impact of fewer non-productive days (119 days). Unplanned downtime for the Ocean Monarch for rig maintenance in the second quarter of 2019 was more than offset by lower unplanned downtime for the Ocean Courage, which was out-of-service for repairs during the second quarter of 2018, and incremental revenue-earning days for the Ocean Apex, which was warm stacked during the 2018 period.

Contract drilling expense, excluding depreciation, increased $35.5 million during the second quarter of 2019 compared to the second quarter of 2018, primarily due to incremental amortization of previously deferred contract preparation and mobilization costs ($30.2 million) and increased costs for our current floater fleet associated with labor and personnel ($6.7 million), equipment rental ($2.8 million) and overhead, shorebase support and other rig costs ($4.2 million). These increases were partially offset by reduced costs for the previously-owned Ocean Guardian ($6.8 million).

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 subsequently sold in July 2018. See Note 3 “Impairment of Assets” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Gain (loss) on disposition of assets. During the second quarter of 2019, we recognized a pre-tax gain of $14.3 million on the sale of the Ocean Guardian, a previously impaired rig. Additionally, we recognized an aggregate net pre-tax loss of $4.9 million on the disposal of certain other property and equipment during the quarter.

Income Tax Benefit. We recorded a net income tax benefit of $27.4 million for the second quarter of 2019, compared to an income tax benefit of $10.0 million for the same quarter of 2018. In June 2019, the Internal Revenue Service, or IRS, issued final regulations with respect to the calculation of the toll charge associated with the deemed repatriation of previously deferred earnings of our non-U.S. subsidiaries, or Transition Tax, in response to the Tax Cuts and Jobs Act enacted in 2017, commonly referred to as the Tax Reform Act. Based on the new regulations, we recorded a net tax benefit of $14.2 million in the second quarter of 2019.

Other than the adjustment to the Transition Tax liability, the difference in the amount of tax benefit recognized between the periods was in large part due to the mix of our domestic and international pre-tax earnings and losses for the periods.

Six Months Ended June 30, 2019 and 2018

Net results for the first half of 2019 decreased $137.4 million compared to the first half of 2018, reflecting lower margins from our contract drilling services, primarily driven by lower contract drilling revenue. Contract drilling services contributed operating income of $41.8 million during the first half of 2019, compared to $179.3 million in the first half of 2018. Our results for the first six months of 2019 were also negatively impacted by higher depreciation expense of $11.5 million, primarily due to recent capital expenditures and the completion of software implementation projects, and a lower income tax benefit recognized, compared to the prior year period ($23.1 million). These unfavorable impacts to our net results were partially offset by a $5.2 million net gain on the disposition of assets during the first half of 2019 and the absence of impairment and restructuring charges recorded in the 2018 period.

Operating Results. Contract drilling revenue decreased $119.3 million during the first half of 2019 compared to the same period of 2018, primarily due to lower average daily revenue earned ($63.9 million), the effect of 141 fewer revenue-earning days ($47.0 million) and the absence of $8.4 million in loss-of-hire insurance proceeds recognized during the 2018 period. Comparing the two periods, average daily revenue decreased primarily due to lower dayrates earned by some of our rigs as a result of renegotiating certain existing contracts during 2018 and a lower dayrate earned by the Ocean GreatWhite, which commenced operations under a new contract in the U.K during the first quarter of 2019. Revenue-earning days decreased, compared to the prior year period, due to incremental downtime for planned shipyard projects (155 days) and fewer revenue-earning days for the Ocean Guardian (120 days), which was sold in April 2019, partially offset by the favorable impact of fewer mobilization and non-productive days (135 days).

Contract drilling expense, excluding depreciation, increased $18.2 million during the first half of 2019 compared to the first half of 2018, primarily due to incremental amortization of previously deferred contract preparation and mobilization costs ($34.9 million), combined with increased costs for our current floater fleet for equipment rental ($2.8 million) and overhead, shorebase support and other rig costs ($3.6 million). These increases were partially offset by reduced costs for cold-stacked and previously-owned rigs, including the sold Ocean Guardian ($14.1 million), as well as lower costs for labor and personnel ($1.9 million) and fuel ($7.1 million) for our current fleet.

Restructuring and Separation Costs. In late 2017, our management approved and initiated a plan to restructure our worldwide operations, which also included a reduction in workforce at our corporate facilities and onshore bases. During the first half of 2018, we recognized $4.3 million in restructuring and other employee separation related costs pursuant to this plan. Restructuring activities associated with the plan were substantially completed in 2018.

Gain (loss) on disposition of assets. In April 2019, we sold the previously-impaired Ocean Guardian and recognized a pre-tax gain of $14.3 million. In addition, during the first six months ended June 30, 2019, we recognized an aggregate net pre-tax loss of $9.2 million on the disposal of certain other property and equipment.

Income Tax Benefit. We recorded a net income tax benefit of $31.4 million for the first six months of 2019, compared to an income tax benefit of $54.5 million for the same period of 2018. 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 Transition Tax as a result of further guidance issued by the IRS that clarified certain of our tax positions taken and, consequently, allowed us to reverse the previously recognized liability. Pursuant to final regulations issued by the IRS in June 2019, we reduced our Transition Tax liability and recorded a net $14.2 million income tax benefit associated with the reduction in our estimate.

Other than these discrete tax adjustments, the difference in the amount of income tax benefit recognized in the 2019 period, compared to the comparable period of 2018, was in large part due to the mix of our domestic and international pre-tax earnings and losses for the periods.

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 credit agreements that provide for maximum borrowings of up to $1.2 billion, all

of which was available to us as of July 26, 2019. In addition, as of July 1, 2019, our contractual backlog was $2.0 billion, of which $0.5 billion is expected to be realized during the second half of 2019.

Our worldwide earnings and cash balances are available to finance both our domestic and foreign activities. We record the withholding income tax impact, if any, associated with the potential distribution of earnings of our foreign subsidiaries; however, we have not provided income tax on the outside basis difference of our international subsidiaries as management does not intend to dispose of these subsidiaries. We expect to utilize existing structuring alternatives to mitigate any potential liability should a disposition take place.

At June 30, 2019, we had cash available for current operations of $147.5 million and investments in U.S. Treasury bills of $149.9 million.

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 to them if required.

Based on our cash available and contract drilling backlog, we believe our 2019 capital spending and debt service requirements will be funded from our cash and cash equivalents, future operating cash flows and borrowings under our credit agreements, as needed. We expect, based on our current forecast, to utilize a portion of the availability under our credit agreements, commencing in the first half of 2020, to meet our short-term liquidity requirements. See “– Sources and Uses of Cash – Rig Reactivation, Upgrades and Other Capital Expenditures.”

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 period ended June 30, 2019.

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. We have an effective automatic shelf registration statement under which we may publicly issue debt, equity or hybrid securities. 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, 2019, net cash usage for operating activities and capital expenditures was $2.7 million and $172.3 million, respectively. Our primary sources of cash during the same period were $152.9 million in proceeds from maturities of marketable securities, net of purchases, and $15.6 million in proceeds from the disposition of assets, primarily from the sale of the Ocean Guardian.

Cash Flow from Operations. Cash flow from operations for the six-month period ended June 30, 2019 decreased $133.5 million compared to the six-month period ended June 30, 2018, primarily due to lower cash receipts for contract drilling services ($143.7 million) and higher cash expenditures for interest and bank fees ($3.2 million) and income tax payments, net of refunds ($6.0 million), partially offset by a net decrease in cash expenditures related to contract drilling, shorebase support and general and administrative costs ($19.4 million).

Rig Reactivation, Upgrades and Other Capital Expenditures. As of the date of this report, we expect capital expenditures in 2019 to be approximately $360 million to $380 million for projects under our capital maintenance and replacement programs, including equipment upgrades for the Ocean BlackHawk, Ocean BlackHornet and Ocean Courage and other large shipyard projects. In addition, other specific projects for 2019 include (i) approximately $110 million in capitalized costs associated with the reactivation and upgrade of the Ocean Onyx and (ii) approximately $20 million associated with the reactivation of the Ocean Endeavor.

At June 30, 2019, 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, 2019, the total net unrecognized tax benefits related to uncertain tax positions was $63.5 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.

We have various obligations corresponding to our lease arrangements. See Note 10 “Leases and Lease Commitments” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Credit Ratings

Our current corporate credit ratings from S&P Global Ratings, or S&P, and Moody’s Investor Services, or Moody’s, are B and B2, respectively, and our current senior unsecured notes credit rating from Moody’s is B3. The rating outlook from both S&P and Moody’s is negative. These credit ratings are below investment grade and could raise our cost of financing. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. These ratings could limit our ability to pursue other business opportunities.

Other Commercial Commitments - Letters of Credit

We were contingently liable as of June 30, 2019 in the amount of $41.7 million under certain tax, customs, performance and value-added tax, or VAT, bonds and letters of credit. Agreements relating to approximately $33.2 million of tax and customs bonds can require collateral at any time. As of June 30, 2019, 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		2019 ⁽¹⁾		2020		2021		2022
Other Commercial Commitments
Tax bonds	$	25,114	$	5,949	$	-	$	3,394	$	15,771
Custom bonds		9,308		8,382		742		184		—
Performance bonds		7,100		—		1,000		6,100		—
VAT bonds		227		227		-		—		—
Total obligations	$	41,749	$	14,558	$	1,742	$	9,678	$	15,771

⁽¹⁾

Represents the six-month period beginning July 1, 2019.

Off-Balance Sheet Arrangements

At June 30, 2019 and December 31, 2018, we had no off-balance sheet debt or other off-balance sheet arrangements.

New Accounting Pronouncements

See Note 1 “General Information – Recently Adopted Accounting Pronouncements” and “ – Accounting Pronouncements Not Yet Adopted” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of recently issued accounting pronouncements.

Forward-Looking Statements

We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the

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

•

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;

•

future amounts 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, including the timing and revenue associated therewith;

•

idling drilling rigs or reactivating stacked rigs;

•

outcomes of litigation and legal proceedings;

•

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;

•

process and timing for acquiring regulatory permits and approvals for our drilling operations;

•

timing and cost of completion of capital projects;

•

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

•

the reactivation of and future contracts for the Ocean Onyx;

•

plans and objectives of management;

•

scrapping retired rigs;

•

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;

•

future issuances 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, 2018 and Item 1A, “Risk Factors,” included in Part II of this report.

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

ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.

There were no material changes in our market risk components for the six months ended June 30, 2019. 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, 2018 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, 2019. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2019.

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 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. Legal Proceedings.

Information related to certain legal proceedings is included in Note 9 “Commitments and Contingencies” 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, 2018 includes a detailed discussion of certain material risk factors facing our company. In our Quarterly Report on Form 10-Q for the quarter ended March 31, 2019, we restated one such risk factor. No material changes have been made to such risk factors as of June 30, 2019.

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).

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 - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL 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.

104*		The cover page of our Quarter Report on Form 10-Q for the quarter ended June 30, 2019, formatted in Inline XBRL (included with the Exhibit 101 attachments).

*	Filed or furnished herewith.

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 August 5, 2019	By:	/s/ Scott Kornblau
		Scott Kornblau
		Senior Vice President and Chief Financial Officer


Date August 5, 2019		/s/ Beth G. Gordon
		Beth G. Gordon
		Vice President and Controller (Chief Accounting Officer)