DIAMOND OFFSHORE DRILLING, INC. - Quarter Report: 2019 September (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 September 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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 October 25, 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 SEPTEMBER 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)

	September 30,			December 31,
	2019			2018
ASSETS
Current assets:
Cash and cash equivalents	$	209,132		$	154,073
Marketable securities		—			299,849
Accounts receivable, net of allowance for bad debts		237,621			168,620
Prepaid expenses and other current assets		66,669			163,396
Asset held for sale		1,000			—
Total current assets		514,422			785,938
Drilling and other property and equipment, net of
accumulated depreciation		5,150,876			5,184,222
Other assets		205,736			65,534
Total assets	$	5,871,034		$	6,035,694
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable	$	68,760		$	43,933
Accrued liabilities		190,204			172,228
Taxes payable		20,242			20,685
Total current liabilities		279,206			236,846
Long-term debt		1,975,275			1,973,922
Deferred tax liability		54,119			104,380
Other liabilities		257,110			135,893
Total liabilities		2,565,710			2,451,041
Commitments and contingencies (Note 8)
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; 144,769,078 shares issued and 137,694,313 shares outstanding at September 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		2,022,672			2,018,143
Retained earnings		1,486,971			1,769,415
Accumulated other comprehensive (loss) gain		(16	)		21
Treasury stock, at cost (7,074,765 and 6,945,309 shares of common stock at September 30, 2019 and December 31, 2018, respectively)		(205,751	)		(204,370	)
Total stockholders’ equity		3,305,324			3,584,653
Total liabilities and stockholders’ equity	$	5,871,034		$	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						Nine Months Ended
	September 30,						September 30,
	2019			2018			2019			2018
Revenues:
Contract drilling	$	242,315		$	280,691		$	676,284		$	833,970
Revenues related to reimbursable expenses		11,705			5,631			27,984			16,723
Total revenues		254,020			286,322			704,268			850,693
Operating expenses:
Contract drilling, excluding depreciation		201,568			188,456			593,779			562,466
Reimbursable expenses		11,423			5,574			27,479			16,458
Depreciation		88,693			81,884			263,844			245,534
General and administrative		18,830			33,308			51,436			70,057
Impairment of assets		—			—			—			27,225
Restructuring and separation costs		—			649			—			4,925
Loss (gain) on disposition of assets		6,340			(506	)		1,191			(1,066	)
Total operating expenses		326,854			309,365			937,729			925,599
Operating loss		(72,834	)		(23,043	)		(233,461	)		(74,906	)
Other income (expense):
Interest income		1,317			2,364			5,664			6,001
Interest expense, net of amounts capitalized		(31,098	)		(34,293	)		(92,182	)		(92,196	)
Foreign currency transaction (loss) gain		(77	)		(743	)		(1,883	)		115
Other, net		82			(179	)		520			664
Loss before income tax benefit		(102,610	)		(55,894	)		(321,342	)		(160,322	)
Income tax benefit		7,482			4,782			38,898			59,257
Net loss	$	(95,128	)	$	(51,112	)	$	(282,444	)	$	(101,065	)
Loss per share, Basic and Diluted	$	(0.69	)	$	(0.37	)	$	(2.05	)	$	(0.74	)
Weighted-average shares outstanding:
Shares of common stock		137,694			137,434			137,636			137,386
Dilutive potential shares of common stock		—			—			—			—
Total weighted-average shares outstanding		137,694			137,434			137,636			137,386

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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net loss	$	(95,128	)	$	(51,112	)	$	(282,444	)	$	(101,065	)
Other comprehensive gains (losses), net of tax:
Derivative financial instruments:
Reclassification adjustment for gain included in net loss		(2	)		(2	)		(5	)		(5	)
Investments in marketable securities:
Unrealized holding gain		-			6			23			37
Reclassification adjustment for gain included in net loss		(8	)		(31	)		(55	)		(31	)
Total other comprehensive (loss) gain		(10	)		(27	)		(37	)		1
Comprehensive loss	$	(95,138	)	$	(51,139	)	$	(282,481	)	$	(101,064	)

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 September 30, 2019
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
July 1, 2019		144,764,125	$	1,448	$	2,021,095	$	1,582,099		$	(6	)		7,073,498	$	(205,739	)	$	3,398,897
Net loss		—		—		—		(95,128	)		—			—		—			(95,128	)
Stock-based compensation, net of tax		4,953		—		1,577		—			—			1,267		(12	)		1,565
Net loss on investments		—		—		—		—			(8	)		—		—			(8	)
Net loss on derivative financial instruments		—		—		—		—			(2	)		—		—			(2	)
September 30, 2019		144,769,078	$	1,448	$	2,022,672	$	1,486,971		$	(16	)		7,074,765	$	(205,751	)	$	3,305,324

	Nine Months Ended September 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		—		—		—		(282,444	)		—			—		—			(282,444	)
Stock-based compensation, net of tax		385,416		4		4,529		—			—			129,456		(1,381	)		3,152
Net loss on investments		—		—		—		—			(32	)		—		—			(32	)
Net loss on derivative financial instruments		—		—		—		—			(5	)		—		—			(5	)
September 30, 2019		144,769,078	$	1,448	$	2,022,672	$	1,486,971		$	(16	)		7,074,765	$	(205,751	)	$	3,305,324

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 September 30, 2018
										Accumulated
					Additional					Other								Total
	Common Stock				Paid-In		Retained			Comprehensive			Treasury Stock					Stockholders’
	Shares		Amount		Capital		Earnings			Gains (Losses)			Shares		Amount			Equity
July 1, 2018		144,374,006	$	1,444	$	2,013,862	$	1,899,735		$	23			6,943,090	$	(204,334	)	$	3,710,730
Net loss		—		—		—		(51,112	)		—			—		—			(51,112	)
Stock-based compensation, net of tax		4,506		—		1,568		—			—			964		(20	)		1,548
Net loss on investments		—		—		—		—			(25	)		—		—			(25	)
Net loss on derivative financial instruments		—		—		—		—			(2	)		—		—			(2	)
September 30, 2018		144,378,512	$	1,444	$	2,015,430	$	1,848,623		$	(4	)		6,944,054	$	(204,354	)	$	3,661,139

	Nine Months Ended September 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		—		—		—		(101,065	)		—			—		—			(101,065	)
Anti-dilution payments		—		—		—		3			—			—		—			3
Stock options exercised		3,773		—		—		—			—			—		—			—
Stock-based compensation, net of tax		289,447		3		4,033		—			—			86,544		(1,285	)		2,751
Net gain on investments		—		—		—		—			6			—		—			6
Net loss on derivative financial instruments		—		—		—		—			(5	)		—		—			(5	)
September 30, 2018		144,378,512	$	1,444	$	2,015,430	$	1,848,623		$	(4	)		6,944,054	$	(204,354	)	$	3,661,139

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)

	Nine Months Ended
	September 30,
	2019			2018
Operating activities:
Net loss	$	(282,444	)	$	(101,065	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation		263,844			245,534
Loss on impairment of assets		—			27,225
Loss (gain) on disposition of assets		1,191			(1,066	)
Deferred tax provision		(48,323	)		(69,109	)
Stock-based compensation expense		4,533			4,036
Contract liabilities, net		15,060			(6,589	)
Contract assets, net		302			(4,395	)
Deferred contract costs, net		49,866			34,901
Other assets, noncurrent		180			823
Other liabilities, noncurrent		(90	)		(4,298	)
Other		2,408			3,969
Changes in operating assets and liabilities:
Accounts receivable		(27,177	)		57,881
Prepaid expenses and other current assets		(128	)		4,901
Accounts payable and accrued liabilities		7,115			(11,836	)
Taxes payable		(548	)		7,844
Net cash (used in) provided by operating activities		(14,211	)		188,756
Investing activities:
Capital expenditures		(249,819	)		(159,751	)
Proceeds from maturities of marketable securities		2,300,000			775,000
Purchase of marketable securities		(1,996,996	)		(1,047,453	)
Proceeds from disposition of assets, net of disposal costs		16,097			69,533
Net cash provided by (used in) investing activities		69,282			(362,671	)
Financing activities:
Other		(12	)		(269	)
Net cash used in financing activities		(12	)		(269	)
Net change in cash and cash equivalents		55,059			(174,184	)
Cash and cash equivalents, beginning of period		154,073			376,037
Cash and cash equivalents, end of period	$	209,132		$	201,853

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 October 25, 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 9.

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.

Asset Held for Sale

The $1.0 million net book value of the Ocean Confidence, a previously impaired semisubmersible rig that was cold stacked in 2015, has been reported as “Asset held for sale” in our Condensed Consolidated Balance Sheets at September 30, 2019.

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):

	September 30,			December 31,
	2019			2018
Trade receivables	$	185,934		$	160,463
Current contract assets ⁽¹⁾		8,638			6,832
Noncurrent contract assets ⁽¹⁾		—			2,107
Current contract liabilities (deferred revenue) ⁽¹⁾		(6,056	)		(2,803	)
Noncurrent contract liabilities (deferred revenue) ⁽¹⁾		(29,531	)		(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		5,385
Increase due to cash received, excluding amounts recognized as revenue during the period		(20,444	)
Increase due to revenue recognized during the period but contingent on future performance		3,537
Decrease due to transfer to receivables during the period		(2,796	)
Adjustments		(1,044	)
Net balance at September 30, 2019	$	(26,949	)
Contract assets at September 30, 2019	$	8,638
Contract liabilities at September 30, 2019		(35,587	)

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 September 30, 2019 (in thousands):

	For the Years Ending December 31,
	2019 ⁽¹⁾		2020		2021		2022		Total
Mobilization and contract preparation revenue	$	714	$	2,270	$	632	$	124	$	3,740
Capital modification revenue		1,612		4,934		228		—		6,774
Blended rate revenue		—		21,410		7,007		—		28,417
Total	$	2,326	$	28,614	$	7,867	$	124	$	38,931

⁽¹⁾	Represents the three-month period beginning October 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 September 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 third quarter of 2019, we evaluated three of our drilling rigs that had 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 September 30, 2019.

As of September 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):

	September 30,			December 31,
	2019			2018
Trade receivables	$	185,934		$	160,463
Federal income tax receivables		38,574			—
Value added tax receivables		18,266			13,237
Related party receivables		132			174
Other		174			205
		243,080			174,079
Allowance for bad debts		(5,459	)		(5,459	)
Total	$	237,621		$	168,620

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

	September 30,		December 31,
	2019		2018
Deferred contract costs	$	26,252	$	70,021
Rig spare parts and supplies		17,331		20,256
Current contract assets		8,638		6,832
Prepaid rig costs		4,041		5,247
Prepaid insurance		3,587		2,742
Prepaid taxes		826		54,412
Other		5,994		3,886
Total	$	66,669	$	163,396

Accrued liabilities consist of the following (in thousands):

	September 30,		December 31,
	2019		2018
Accrued capital project/upgrade costs	$	39,169	$	37,379
Payroll and benefits		38,370		47,564
Interest payable		36,813		28,234
Rig operating expenses		35,422		42,323
Current operating lease liability		19,143		-
Personal injury and other claims		6,790		5,544
Deferred revenue		6,056		2,803
Shorebase and administrative costs		4,871		6,217
Other		3,570		2,164
Total	$	190,204	$	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 9.

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):

	Nine Months Ended September 30,
	2019			2018
Accrued but unpaid capital expenditures at period end	$	39,169		$	19,413
Common stock withheld for payroll tax obligations ⁽¹⁾		1,381			1,285
Cash interest payments		76,219			76,219
Cash income taxes paid, net of (refunds):
Foreign		13,227			5,941
U.S. Federal		—			(7,389	)
State		(15	)		2

⁽¹⁾

Represents the cost of 129,456 shares and 86,544 shares of common stock withheld to satisfy payroll tax obligations incurred as a result of the vesting of restricted stock units in the nine-month periods ended September 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 September 30, 2019 and 2018, respectively.

5. Loss Per Share

We present basic and diluted net income (loss) per share on our unaudited 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 September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018
Employee and director:
Stock appreciation rights		970		1,071		995		1,161
Restricted stock units		1,261		1,182		1,188		1,150

6. 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. The market for our services is the offshore oil and gas industry, and our 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 September 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).

	September 30, 2019
	Fair Value Measurements Using
	Level 1		Level 2		Level 3		Assets at Fair Value
Money market funds	$	196,388	$	—	$	—	$	196,388

	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 September 30, 2019 or December 31, 2018.

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 September 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).

	September 30, 2019				December 31, 2018
	Fair Value		Carrying Value		Fair Value		Carrying Value
3.45% Senior Notes due 2023	$	187.5	$	249.5	$	185.0	$	249.5
7.875% Senior Notes due 2025		392.5		497.2		415.0		496.8
5.70% Senior Notes due 2039		242.5		497.3		305.0		497.2
4.875% Senior Notes due 2043		346.9		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.

7. Drilling and Other Property and Equipment

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

	September 30,			December 31,
	2019			2018
Drilling rigs and equipment	$	7,911,380		$	8,210,824
Land and buildings		64,102			63,757
Office equipment and other		91,952			91,819
Cost		8,067,434			8,366,400
Less: accumulated depreciation		(2,916,558	)		(3,182,178	)
Drilling and other property and equipment, net	$	5,150,876		$	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 nine months ended September 30, 2019, we disposed of certain other property and equipment and recognized an aggregate net pre-tax loss of $15.5 million. During the third quarter of 2019, we transferred the net book value of the Ocean Confidence, a previously impaired semisubmersible rig, to “Asset held for sale” in our unaudited Condensed Consolidated Balance Sheets at September 30, 2019.

8. 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 September 30, 2019 our estimated liability for personal injury claims was $21.1 million, of which $6.2 million and $14.9 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 September 30, 2019 in the aggregate amount of $34.8 million under certain customs, performance, tax and VAT bonds and letters of credit. Agreements relating to approximately $26.2 million of tax and customs bonds can require collateral at any time. As of September 30, 2019, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements, aggregating $8.6 million, cannot require collateral except in events of default.

9. 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 Company (formerly named Baker Hughes, a GE Company) 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 nine months ended September 30, 2019 was $9.7 million and $28.6 million, respectively, of which $0.8 million and $2.9 million, respectively, related to short-term leases. Total operating lease expense for the three and nine months ended September 30, 2018 was $7.5 million and $22.5 million, respectively.

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

	Nine Months Ended September 30, 2019
Operating cash flows used for operating leases	$	30,235
Right-of-use assets obtained in exchange for lease liabilities		16,564
Weighted-average remaining lease term	6.8 years
Weighted-average discount rate		8.64	%

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 September 30, 2019 were as follows (in thousands):

2019 (excluding nine months ended September 30, 2019)	$	8,372
2020		30,627
2021		28,696
2022		28,252
2023		28,236
2024		28,315
Thereafter		46,448
Total lease payments		198,946
Less: interest		(49,582	)
Total lease liability	$	149,364
Amounts recognized in unaudited Condensed Consolidated Balance Sheets:
Accrued liabilities	$	19,143
Other liabilities		130,221
Total operating lease liability	$	149,364

Operating lease assets, including prepaid rent balances related to the leases with GE, totaling $165.3 million are included in “Other assets” in our unaudited Condensed Consolidated Balance Sheets as of September 30, 2019.

As of September 30, 2019, we had two additional operating leases for mooring equipment to be used on our rigs that had not yet commenced. The first agreement, which was entered into during the first quarter of 2019 and commenced in October 2019, provides for fixed lease payments of approximately $12 million in the aggregate to be paid over a lease term of 9.5 years. The second agreement, which was entered into in the third quarter of 2019 and is expected to commence in January 2020, provides for fixed lease payments of approximately $5 million in the aggregate to be paid over a lease term of five years.

10. Segments and Geographic Area Analysis

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

Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At September 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 September 30, 2019
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	110,854	$	1,479	$	112,333
South America		49,326		10		49,336
Europe		49,341		3,852		53,193
Australia		32,794		6,364		39,158
Total	$	242,315	$	11,705	$	254,020

	Nine Months Ended September 30, 2019
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses		Total
United States	$	366,907	$	5,029	$	371,936
South America		131,748		17		131,765
Europe		113,364		8,689		122,053
Australia		64,265		14,249		78,514
Total	$	676,284	$	27,984	$	704,268

	Three Months Ended September 30, 2018
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses			Total
United States	$	155,695	$	1,916		$	157,611
South America		49,410		(32	)		49,378
Europe		30,809		1,996			32,805
Australia/Asia		44,777		1,751			46,528
Total	$	280,691	$	5,631		$	286,322

	Nine Months Ended September 30, 2018
	Total Contract Drilling Revenues		Revenues Related to Reimbursable Expenses			Total
United States⁽¹⁾	$	482,337	$	5,224		$	487,561
South America		129,966		(31	)		129,935
Europe		60,938		5,116			66,054
Australia/Asia		160,729		6,414			167,143
Total	$	833,970	$	16,723		$	850,693

⁽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.

11. 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.

Several of our rigs are owned by Swiss branches of entities incorporated in the United Kingdom that have historically been taxed under a special tax regime pursuant to Swiss corporate income tax rules. On September 3, 2019, the Swiss federal government, along with the Canton of Zug, enacted tax legislation, which we refer to as “Swiss Tax Reform”, effective as of January 1, 2020. Swiss Tax Reform significantly changed Swiss corporate income tax rules by, among other things, abolishing special tax regimes. The legislation also provides transition rules under which companies can maintain their current basis of taxation through January 1, 2022.

The abolition of special tax regimes will require us to determine our Swiss tax liability on a net income basis beginning on January 1, 2022, thus also requiring deferred taxes to be computed on the difference between the Swiss tax basis and U.S. GAAP basis of certain items, including property, plant and equipment. There are still many uncertainties in the application of Swiss Tax Reform, including the values to be used to measure depreciable property. Therefore, we have recorded an $85.0 million deferred tax asset for the difference in basis of certain of our rigs between Swiss tax and U.S. GAAP, fully offset by a reserve for an uncertain tax position.

As further clarification is issued by the Swiss tax authorities, deferred tax balances and the reserve for uncertain tax positions may need to be adjusted. The potential changes could have a material effect on our consolidated financial statements.

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 15 floater rigs (four drillships and 11 semisubmersibles), of which two rigs are currently cold-stacked. The Ocean Confidence, an additional cold-stacked semisubmersible rig, is being marketed for sale and has been excluded from our active fleet. The reactivation and upgrade of the Ocean Onyx is nearly complete, and we expect the rig to begin operating under contract during the first quarter of 2020.

Market Overview

At the end of the third quarter of 2019, the average price for Brent crude oil was at the $60-per-barrel level. Industry-wide floater utilization was approximately 66% based on industry analyst reports, which was relatively unchanged from the previous quarter but an increase from approximately 58% for the comparable quarter of 2018. During 2019, there has been a slight improvement in average dayrates in some geographic markets; however, dayrates remain low compared to previous periods, as the increase in oil prices from earlier lows has not resulted in significantly higher dayrates at a sustained or consistent level. Some industry analysts indicate that, based on historical data, utilization rates will have to increase to the 80%-range before pricing power shifts to the drilling contractor from the customer.

During the first nine months 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. Presently, many of these tenders have been limited to single-well contracts, 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, some industry analysts have reported a three-rig decrease in the global supply of floater rigs during the third quarter of 2019. However, the offshore contract drilling market remains oversupplied, providing for a challenging offshore drilling market in the near term. As of the date of this report, industry analysts report that there are approximately 80 stacked or uncontracted floaters and approximately 30 newbuild floaters currently under construction that are scheduled for delivery during the remainder of 2019 through 2022. Of these rigs under construction, some industry analysts report that only one rig is currently contracted for future work. In addition, during the next twelve months, approximately 70 contracted floaters are estimated to be rolling off their current contracts, which will further add to the over-supply of floaters.

As a result of these challenges, we and other offshore drillers are continuing to actively seek ways to drive efficiency, reduce non-productive time on rigs and provide technical innovation to customers. We anticipate that these efficiencies and innovations will result in the faster drilling and completion of wells, leading to lower overall well costs to the benefit of our customers.

See “– Contract Drilling Backlog” for future commitments of our rigs during 2019 through 2024.

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 October 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 October 1, 2018 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2018) (in thousands).

October 1,

2019 ⁽¹⁾

January 1,

2019 ⁽¹⁾

October 1,

2018 ⁽¹⁾

Contract Drilling Backlog

1,835,000

1,973,000

2,040,000

⁽¹⁾

Contract drilling backlog as of October 1, 2019, January 1, 2019 and October 1, 2018 excludes future commitment amounts totaling approximately $130.0 million, $135.0 million and $135.0 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 October 1, 2019 (in thousands).

	For the Years Ending December 31,
	Total		2019 ⁽¹⁾		2020		2021		2022		2023-2024
Contract Drilling Backlog ⁽²⁾	$	1,835,000	$	222,000	$	783,000	$	456,000	$	247,000	$	127,000

⁽¹⁾	Represents the three-month period beginning October 1, 2019.

⁽²⁾

Contract drilling backlog as of October 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 October 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, but excluding rigs classified as held for sale, multiplied by the number of days in a particular year).

	For the Years Ending December 31,
	2019 ⁽¹⁾			2020			2021			2022			2023-2024
Rig Days Committed ⁽²⁾		76	%		71	%		39	%		17	%		4	%

⁽¹⁾	Represents the three-month period beginning October 1, 2019.

⁽²⁾	As of October 1, 2019, includes approximately 185 rig days, 425 rig days and 55 rig 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 185 days during the fourth quarter of 2019 for upgrades, contract preparation and mobilization of rigs, which includes an aggregate of approximately 90 days for the completion of upgrades, reactivation activities and contract preparation for the Ocean Onyx prior to its contract commencement, an aggregate of approximately 60 days for special surveys and rig upgrades for the Ocean BlackHornet and Ocean BlackRhino and an aggregate of approximately 35 days for mobilization and contract preparation activities for other rigs. In 2020, we expect to spend an additional 90 days for contract preparation for the Ocean Onyx, an aggregate of approximately 240 days for upgrades for the Ocean BlackRhino and a special survey and upgrades for the Ocean BlackLion, approximately 60 days for the mobilization of and contract preparation for the Ocean Monarch prior to its contract in Myanmar and approximately 35 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, upgrades, contract preparation, 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 left 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 9 “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 nine months ended September 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 nine-month periods ended September 30, 2019 and 2018.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(In thousands, except days, daily amounts and percentages)
REVENUE-EARNING DAYS ⁽¹⁾		959			841			2,451			2,474
UTILIZATION ⁽²⁾		65	%		54	%		55	%		53	%
AVERAGE DAILY REVENUE ⁽³⁾	$	252,600		$	333,400		$	275,900		$	333,600
REVENUE RELATED TO CONTRACT DRILLING SERVICES	$	242,315		$	280,691		$	676,284		$	833,970
REVENUE RELATED TO REIMBURSABLE EXPENSES		11,705			5,631			27,984			16,723
TOTAL REVENUES	$	254,020		$	286,322		$	704,268		$	850,693
CONTRACT DRILLING EXPENSE, EXCLUDING DEPRECIATION	$	201,568		$	188,456		$	593,779		$	562,466
REIMBURSABLE EXPENSES	$	11,423		$	5,574		$	27,479		$	16,458
OPERATING LOSS
Contract drilling services, net	$	40,747		$	92,235		$	82,505		$	271,504
Reimbursable expenses, net		282			57			505			265
Depreciation		(88,693	)		(81,884	)		(263,844	)		(245,534	)
General and administrative expense		(18,830	)		(33,308	)		(51,436	)		(70,057	)
Impairment of assets		-			-			-			(27,225	)
Restructuring and separation costs		-			(649	)		-			(4,925	)
(Loss) gain on disposition of assets		(6,340	)		506			(1,191	)		1,066
Total Operating Loss	$	(72,834	)	$	(23,043	)	$	(233,461	)	$	(74,906	)
Other income (expense):
Interest income		1,317			2,364			5,664			6,001
Interest expense, net of amounts capitalized		(31,098	)		(34,293	)		(92,182	)		(92,196	)
Foreign currency transaction (loss) gain		(77	)		(743	)		(1,883	)		115
Other, net		82			(179	)		520			664
Loss before income tax benefit		(102,610	)		(55,894	)		(321,342	)		(160,322	)
Income tax benefit		7,482			4,782			38,898			59,257
NET LOSS	$	(95,128	)	$	(51,112	)	$	(282,444	)	$	(101,065	)

⁽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 September 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 September 30, 2019 and 2018

Net results for the third quarter of 2019 decreased $44.0 million compared to the third 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 operating income of $40.7 million during the third quarter of 2019, compared to operating income of $92.2 million in the third quarter of 2018. Our results for the third quarter of 2019 were also negatively impacted by a net pre-tax loss of $6.3 million on the disposal of certain property and equipment during the quarter and by higher depreciation expense of $6.8 million, primarily due to capital expenditures made since the latter part of 2018. These unfavorable impacts to our net results were partially offset by a decrease in general and administrative expense of $14.5 million and an incremental tax benefit of $2.7 million recognized during the third quarter of 2019.

Operating Results. Contract drilling revenue decreased $38.4 million during the third quarter of 2019 compared to the third quarter of 2018, primarily due to lower average daily revenue earned ($77.5 million), partially offset by the effect of 118 incremental revenue-earning days ($39.1 million). The decrease in average daily revenue reflects the impact of lower dayrates earned under contracts that commenced after the third quarter of 2018, the completion of a long-term contract for the Ocean BlackHornet in July 2019, which was at a significantly higher dayrate than available in the current market, and a reduction in upgrade and mobilization revenue recognized during the quarter. Revenue-earning days increased, compared to the third quarter of 2018, due to fewer non-productive days (138 days) and fewer days for planned shipyard projects and mobilization of rigs (72 days), partially offset by the unfavorable impact of fewer revenue-earning days for the Ocean Guardian, which operated throughout the third quarter of 2018 but was sold in 2019 (92 days).

Contract drilling expense, excluding depreciation, increased $13.1 million during the third quarter of 2019 compared to the third quarter of 2018, primarily due to higher costs for repairs and maintenance ($5.3 million), overhead and shorebase support ($4.9 million), labor and personnel ($1.9 million), equipment rental ($1.6 million) and other rig costs ($2.6 million). In addition, during the third quarter of 2019, we deferred fewer contract costs associated with contract preparation activities, including mobilization of rigs, than during the third quarter of 2018 ($8.3 million). These cost increases were partially offset by the absence of costs for the Ocean Guardian ($6.3 million) and a reduction in fuel and moving costs ($5.2 million).

General and administrative expense decreased $14.5 million, compared to the third quarter of 2018, primarily due to the absence of a $17.5 million charge in the third quarter of 2018 for settlement of a legal claim, partially offset by an adjustment in the 2019 period related to a long-term incentive compensation plan.

Income Tax Benefit. We recorded a net income tax benefit of $7.5 million (7.3% effective tax rate) for the third quarter of 2019, compared to an income tax benefit of $4.8 million (8.6% effective tax rate) for the same quarter of 2018. 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.

Nine Months Ended September 30, 2019 and 2018

Net results for the first nine months of 2019 decreased $181.4 million compared to the same period of 2018, reflecting lower margins from our contract drilling services, primarily driven by lower contract drilling revenue. Contract drilling services contributed operating income of $82.5 million during the first nine months of 2019, compared to $271.5 million in the first nine months of 2018. Our results for the first nine months of 2019 were also negatively impacted by higher depreciation expense of $18.3 million, primarily due to capital expenditures and the completion of software implementation projects in 2019, and a lower income tax benefit recognized ($20.4 million), compared to the prior year period. These unfavorable impacts to our net results were partially offset by a reduction in general and

administrative expense ($18.6 million) in the first nine months of 2019 and the absence of impairment and restructuring charges recorded in the 2018 period.

Operating Results. Contract drilling revenue decreased $157.7 million during the first nine months of 2019 compared to the same period of 2018, primarily due to lower average daily revenue earned ($141.4 million), the effect of 23 fewer revenue-earning days ($7.9 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.

Contract drilling expense, excluding depreciation, increased $31.3 million during the first nine months of 2019 compared to the same period of 2018, primarily due to incremental amortization of previously deferred contract preparation and mobilization costs ($30.0 million), combined with increased costs for our current floater fleet for labor and personnel ($8.7 million), repairs and maintenance ($9.2 million), equipment rental ($5.1 million), catering ($2.3 million) and overhead, shorebase support and other rig costs ($4.8 million). These increases were partially offset by reduced costs for the previously-owned Ocean Guardian ($20.2 million) and lower fuel costs ($8.6 million) for our current fleet.

General and administrative expense decreased $18.6 million, primarily due to the absence of a $17.5 million charge recorded in the third quarter of 2018 for settlement of a legal claim.

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 nine months of 2018, we recognized $4.9 million in restructuring and other employee separation related costs pursuant to this plan. Restructuring activities associated with the plan were substantially completed in 2018.

Impairment of Assets. During the first nine months 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 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.

Income Tax Benefit. We recorded a net income tax benefit of $38.9 million (12.1% effective tax rate) for the first nine months of 2019, compared to an income tax benefit of $59.3 million (37% effective tax rate) 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 toll charge associated with the deemed repatriation of previously deferred earnings of our non-U.S. subsidiaries, or Transition Tax, under the Tax Cuts and Jobs Act enacted in 2017, or tax Reform Act, as a result of further guidance issued by the Internal Revenue Service, or IRS. This additional guidance clarified certain of our tax positions taken and, consequently, allowed us to reverse the previously recognized liability. Income tax benefit for the 2019 period included a tax benefit of $14.2 million associated with the reduction of our Transition Tax liability pursuant to final regulations issued by the IRS in June 2019.

Other than these discrete tax adjustments, the difference in the amount of income tax benefit recognized in the 2019 period, compared to the same 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 have principally relied on our cash flows from operations and cash reserves to meet our liquidity needs. We have also utilized borrowings under our credit agreements, which currently provide for maximum borrowings of up to $1.2 billion, all of which was available to us as of October 25, 2019. In addition, as of October 1, 2019, our contractual backlog was $1.8 billion, of which $0.2 billion is expected to be realized during the fourth quarter of 2019. Also, during the fourth quarter of 2019, we expect to receive a $30.0 million payment from a customer for an unfulfilled gross margin commitment pursuant to terms of an existing contract. At September 30, 2019, we had cash available for current operations of $209.1 million.

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.

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.”

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 financial condition, credit ratings, market conditions and other factors beyond our control at the time we seek such access.

Sources and Uses of Cash

During the nine-month period ended September 30, 2019, net cash usage for operating activities and capital expenditures was $14.2 million and $249.8 million, respectively. Our primary sources of cash during the same period were $303.0 million in proceeds from maturities of marketable securities, net of purchases, and proceeds from the disposition of assets, including $15.0 million from the sale of the Ocean Guardian in the second quarter of 2019.

Cash Flow from Operations. Cash flow from operations for the nine-month period ended September 30, 2019 decreased $203.0 million compared to the nine-month period ended September 30, 2018, primarily due to lower cash receipts for contract drilling services ($205.5 million) and higher income tax payments, net of refunds, primarily in our foreign tax jurisdictions ($14.7 million). Incremental cash used for operations during the 2019 period was partially offset by a net decrease in cash expenditures related to contract drilling, shorebase support and general and administrative costs ($17.2 million).

Rig Reactivation, Upgrades and Other Capital Expenditures. As of the date of this report, we expect capital expenditures for the final quarter of 2019 to be approximately $110 million to $130 million for a total spend of approximately $360 million to $380 million in 2019. 2019 capital expenditures include spending associated with 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 September 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 September 30, 2019, the total net unrecognized tax benefits related to uncertain tax positions was $148.4 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 9 “Leases and Lease Commitments” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report.

Credit Ratings

On September 25, 2019, S&P Global Ratings, or S&P, downgraded our corporate and senior unsecured notes credit ratings to CCC+ from B. The rating outlook from S&P changed to stable from negative. Our current corporate credit rating from Moody’s Investor Services, or Moody’s, is B2 and our current senior unsecured notes credit rating from Moody’s is B3. The rating outlook from Moody’s is negative. These credit ratings are below investment grade and could raise our cost of financing. Consequently, 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

See Note 8 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of our other commercial commitments.

Off-Balance Sheet Arrangements

At September 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 and other planned downtime;

•

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;

•

assets held for sale;

•

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 nine months ended September 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 September 30, 2019. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of September 30, 2019.

There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our third 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 8 “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 September 30, 2019.

ITEM 6. Exhibits.


Exhibit No.		Description of Exhibit

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*		Inline XBRL Taxonomy Extension Schema Document.

101.CAL*		Inline XBRL Taxonomy Calculation Linkbase Document.

101.LAB*		Inline XBRL Taxonomy Label Linkbase Document.

101.PRE*		Inline XBRL Presentation Linkbase Document.

101.DEF*		Inline XBRL Definition Linkbase Document.

104*		The cover page of our Quarterly Report on Form 10-Q for the quarter ended September 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 October 28, 2019	By:	/s/ Scott Kornblau
		Scott Kornblau
		Senior Vice President and Chief Financial Officer


Date October 28, 2019		/s/ Beth G. Gordon
		Beth G. Gordon
		Vice President and Controller (Chief Accounting Officer)