UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number
(Exact name of registrant as specified in its charter)
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(State or other jurisdiction of incorporation or organization) |
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(I.R.S. Employer Identification No.) |
(Address of principal executive offices)
(Zip Code)
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(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Exchange Act:
Title of each class |
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Trading Symbol |
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Name of each exchange on which registered |
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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.
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).
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.
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Accelerated filer |
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Non-accelerated filer |
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Smaller reporting company |
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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 by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes
Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.
As of August 5, 2024 Common stock, $0.0001 par value per share
DIAMOND OFFSHORE DRILLING, INC.
TABLE OF CONTENTS FOR FORM 10-Q
QUARTER ENDED JUNE 30, 2024
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PAGE NO. |
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Condensed Consolidated Statements of Comprehensive Income |
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Condensed Consolidated Statements of Stockholders’ Equity |
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9 |
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Notes to Unaudited Condensed Consolidated Financial Statements |
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Management’s Discussion and Analysis of Financial Condition and Results of Operations |
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ITEM 5. |
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41 |
2
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements.
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except par value amounts)
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June 30, |
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December 31, |
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2024 |
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2023 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
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$ |
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$ |
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Restricted cash |
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Accounts receivable |
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Less: allowance for credit losses |
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Accounts receivable, net |
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Prepaid expenses and other current assets |
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Asset held for sale |
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Total current assets |
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Drilling and other property and equipment, net of |
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accumulated depreciation |
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Other assets |
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Total assets |
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$ |
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$ |
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LIABILITIES AND STOCKHOLDERS’ EQUITY |
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Current liabilities: |
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Accounts payable |
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$ |
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$ |
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Accrued liabilities |
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Taxes payable |
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Current finance lease liabilities |
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Total current liabilities |
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Long-term debt |
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Noncurrent finance lease liabilities |
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Deferred tax liability |
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Other liabilities |
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Total liabilities |
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Stockholders’ equity: |
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Preferred stock (par value $ |
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Common stock (par value $ |
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Additional paid-in capital |
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Treasury stock |
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Accumulated deficit |
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Accumulated other comprehensive income |
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Total stockholders’ equity |
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Total liabilities and stockholders’ equity |
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$ |
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$ |
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The accompanying notes are an integral part of the condensed consolidated financial statements.
3
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share data)
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Three Months Ended June 30, |
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2024 |
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2023 |
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Revenues: |
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Contract drilling |
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$ |
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$ |
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Revenues related to reimbursable expenses |
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Total revenues |
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Operating expenses: |
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Contract drilling, excluding depreciation |
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Reimbursable expenses |
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Depreciation |
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General and administrative |
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Gain on disposition of assets |
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Total operating expenses |
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Operating income |
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Other income (expense): |
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Interest income |
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Interest expense, net of amounts capitalized |
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Foreign currency transaction loss |
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Other, net |
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Income (loss) before income tax (expense) benefit |
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Income tax (expense) benefit |
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Net income |
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$ |
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$ |
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Earnings per share |
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Basic |
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$ |
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$ |
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Diluted |
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$ |
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$ |
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Weighted-average shares outstanding |
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Basic |
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Diluted |
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The accompanying notes are an integral part of the condensed consolidated financial statements.
4
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share data)
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Six Months Ended June 30, |
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2024 |
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2023 |
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Revenues: |
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Contract drilling |
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$ |
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$ |
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Revenues related to reimbursable expenses |
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Total revenues |
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Operating expenses: |
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Contract drilling, excluding depreciation |
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Reimbursable expenses |
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Depreciation |
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General and administrative |
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Gain on disposition of assets |
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Total operating expenses |
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Operating income |
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Other income (expense): |
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Interest income |
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Interest expense, net of amounts capitalized |
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Foreign currency transaction gain (loss) |
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Other, net |
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( |
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Income (loss) before income tax (expense) benefit |
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( |
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Income tax (expense) benefit |
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( |
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Net income |
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$ |
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$ |
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Earnings per share |
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Basic |
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$ |
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$ |
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Diluted |
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$ |
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$ |
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Weighted-average shares outstanding |
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Basic |
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Diluted |
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The accompanying notes are an integral part of the condensed consolidated financial statements.
5
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(Unaudited)
(In thousands)
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Three Months Ended June 30, |
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2024 |
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2023 |
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Net income |
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$ |
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$ |
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Other comprehensive income, net |
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Unrealized gain on marketable securities, net of tax |
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Comprehensive income |
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$ |
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$ |
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Six Months Ended June 30, |
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2024 |
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2023 |
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Net income |
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$ |
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$ |
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Other comprehensive loss, net |
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Unrealized loss on marketable securities, net of tax |
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( |
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Comprehensive income |
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$ |
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$ |
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The accompanying notes are an integral part of the condensed consolidated financial statements.
6
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)
(In thousands)
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Three Months Ended June 30, 2024 |
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Accumulated |
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Additional |
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Other |
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Total |
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Common Stock |
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Paid-In |
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Accumulated |
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Comprehensive |
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Treasury Stock |
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Stockholders’ |
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Shares |
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Amount |
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Capital |
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Deficit |
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Income |
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Shares |
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Amount |
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Equity |
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April 1, 2024 |
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$ |
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$ |
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$ |
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$ |
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$ |
( |
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$ |
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Net income |
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— |
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— |
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— |
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— |
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— |
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— |
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Stock-based compensation, net of tax |
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— |
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— |
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— |
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( |
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Unrealized gain on marketable securities, net of tax |
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— |
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— |
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— |
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— |
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— |
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— |
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Other |
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— |
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— |
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— |
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— |
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— |
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— |
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June 30, 2024 |
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$ |
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$ |
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$ |
( |
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$ |
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$ |
( |
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$ |
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Six Months Ended June 30, 2024 |
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Accumulated |
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Additional |
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Other |
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Total |
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Common Stock |
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Paid-In |
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Accumulated |
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Comprehensive |
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Treasury Stock |
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Stockholders’ |
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Shares |
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Amount |
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Capital |
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Deficit |
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Income |
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Shares |
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Amount |
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Equity |
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January 1, 2024 |
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$ |
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$ |
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$ |
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$ |
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$ |
( |
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$ |
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Net income |
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— |
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— |
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— |
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— |
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— |
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— |
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Stock-based compensation, net of tax |
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— |
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— |
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— |
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( |
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Unrealized loss on marketable securities, net of tax |
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— |
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— |
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— |
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— |
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( |
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— |
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— |
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( |
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Other |
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— |
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— |
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— |
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— |
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— |
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— |
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June 30, 2024 |
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$ |
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$ |
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$ |
( |
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$ |
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$ |
( |
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$ |
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The accompanying notes are an integral part of the condensed consolidated financial statements.
7
CONDENSED CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY
(Unaudited)
(In thousands)
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Three Months Ended June 30, 2023 |
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Retained |
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Additional |
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Earnings |
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Total |
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Common Stock |
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Paid-In |
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(Accumulated |
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Treasury Stock |
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Stockholders’ |
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Shares |
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Amount |
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Capital |
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Deficit) |
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Shares |
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Amount |
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Equity |
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April 1, 2023 |
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$ |
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$ |
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$ |
( |
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$ |
( |
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$ |
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Net income |
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— |
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— |
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— |
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— |
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— |
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Stock-based compensation, net of tax |
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— |
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— |
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( |
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June 30, 2023 |
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$ |
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$ |
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$ |
( |
) |
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$ |
( |
) |
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$ |
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Six Months Ended June 30, 2023 |
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Retained |
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Additional |
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Earnings |
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Total |
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Common Stock |
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Paid-In |
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(Accumulated |
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Treasury Stock |
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Stockholders’ |
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Shares |
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Amount |
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Capital |
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Deficit) |
|
|
Shares |
|
|
Amount |
|
|
Equity |
|
|||||||
January 1, 2023 |
|
|
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
|
|
|
$ |
( |
) |
|
$ |
|
|||||
Net income |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
— |
|
|
|
|
||
Stock-based compensation, net of tax |
|
|
|
|
|
— |
|
|
|
|
|
|
— |
|
|
|
|
|
|
( |
) |
|
|
|
||||
June 30, 2023 |
|
|
|
|
$ |
|
|
$ |
|
|
$ |
( |
) |
|
|
|
|
$ |
( |
) |
|
$ |
|
The accompanying notes are an integral part of the condensed consolidated financial statements.
8
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
|
|
Six Months Ended |
|
|
|||||
|
|
2024 |
|
|
2023 |
|
|
||
Operating activities: |
|
|
|
|
|
|
|
||
Net income |
|
$ |
|
|
$ |
|
|
||
Adjustments to reconcile net income to net cash |
|
|
|
|
|
|
|
||
provided by operating activities: |
|
|
|
|
|
|
|
||
Depreciation |
|
|
|
|
|
|
|
||
Gain on disposition of assets |
|
|
( |
) |
|
|
( |
) |
|
Deferred tax provision |
|
|
( |
) |
|
|
( |
) |
|
Stock-based compensation expense |
|
|
|
|
|
|
|
||
Contract liabilities, net |
|
|
|
|
|
( |
) |
|
|
Contract assets, net |
|
|
( |
) |
|
|
( |
) |
|
Deferred contract costs, net |
|
|
|
|
|
|
|
||
Other assets, noncurrent |
|
|
|
|
|
|
|
||
Other liabilities, noncurrent |
|
|
( |
) |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
||
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
||
Accounts receivable |
|
|
|
|
|
( |
) |
|
|
Prepaid expenses and other current assets |
|
|
( |
) |
|
|
( |
) |
|
Current income tax assets |
|
|
|
|
|
( |
) |
|
|
Accounts payable and accrued liabilities |
|
|
( |
) |
|
|
|
|
|
Taxes payable |
|
|
|
|
|
( |
) |
|
|
Net cash provided by operating activities |
|
|
|
|
|
|
|
||
Investing activities: |
|
|
|
|
|
|
|
||
Capital expenditures |
|
|
( |
) |
|
|
( |
) |
|
Proceeds from disposition of assets, net of disposal costs |
|
|
|
|
|
|
|
||
Net cash used in investing activities |
|
|
( |
) |
|
|
( |
) |
|
Financing activities: |
|
|
|
|
|
|
|
||
Borrowings under revolving credit facility |
|
|
|
|
|
|
|
||
Repayments under revolving credit facility |
|
|
|
|
|
( |
) |
|
|
Principal payments of finance leases |
|
|
( |
) |
|
|
( |
) |
|
Net cash used in financing activities |
|
|
( |
) |
|
|
( |
) |
|
Net change in cash, cash equivalents and restricted cash |
|
|
|
|
|
( |
) |
|
|
Cash, cash equivalents and restricted cash, beginning of period |
|
|
|
|
|
|
|
||
Cash, cash equivalents and restricted cash, end of period |
|
$ |
|
|
$ |
|
|
The accompanying notes are an integral part of the condensed consolidated financial statements.
9
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,” “Company,” “we,” “us” or “our,” should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2023.
Planned Merger with Noble Corporation plc
On June 9, 2024, Diamond Offshore Drilling, Inc. (or DODI) entered into an Agreement and Plan of Merger (or the Merger Agreement) with Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (or Noble), Dolphin Merger Sub 1, Inc., a Delaware corporation and indirect wholly owned subsidiary of Noble (or Merger Sub 1) and Dolphin Merger Sub 2, Inc., a Delaware corporation and indirect wholly owned subsidiary of Noble (or Merger Sub 2). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (1) Merger Sub 1 will merge with and into DODI, with DODI surviving as a wholly-owned indirect subsidiary of Noble (or the First Merger and the effective time thereof, the
First Merger Effective Time), and subsequently DODI, as the surviving entity in the First Merger, will merge with and into Merger Sub 2, with Merger Sub 2 surviving as an indirect wholly-owned subsidiary of Noble (or the Second Merger and the effective thereof, the Effective Time; and the First Merger together with the Second Merger, the Merger) and (2) at the First Merger Effective Time, each outstanding share of common stock of DODI (other than any Cancelled Shares and any Appraisal Shares (each as defined in the Merger Agreement)) will be converted into the right to receive the following consideration (or collectively, the Merger Consideration): (i) $
Interim Financial Information
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with United States generally accepted accounting principles (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, 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.
Restricted Cash
We classify such restricted cash accounts in current assets if the restrictions are expected to expire or otherwise be resolved within one year or if such funds are considered to offset current liabilities. At June 30, 2024 and December 31, 2023, our restricted cash was considered to be current and was recorded in “Restricted cash” in our unaudited Condensed Consolidated Balance Sheets.
10
Asset Held for Sale
Accounting Principles Not Yet Adopted
In December 2023, the Financial Accounting Standards Board (or FASB) issued Accounting Standards Update (or ASU) No. 2023-09, Income Tax (Topic 740): Improvements to Income Tax Disclosures (or ASU 2023-09). ASU 2023-09 requires business entities on an annual basis to (i) disclose specific categories in the rate reconciliation and (ii) provide additional information for reconciling items that meet certain quantitative thresholds. The new guidance is effective for public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. We are in the process of evaluating the impact of adopting this new guidance on our consolidated financial statement disclosures.
In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures (or ASU 2023-07). ASU 2023-07 modifies the disclosure and presentation requirements of reportable segments and requires the disclosure of significant segment expenses that are regularly provided to the chief operating decision maker and included within each reported measure of segment profit and loss. In addition, the new guidance enhances interim disclosure requirements, clarifies circumstances in which an entity can disclose multiple segment measures of profit or loss, provides new segment disclosure requirements for entities with a single reportable segment, and contains other disclosure requirements. ASU 2023-07 is effective for annual periods beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024, with early adoption permitted. We are in the process of evaluating the impact of adopting this new guidance on our consolidated financial statement disclosures.
2. Revenue from Contracts with Customers
Our contracts with customers provide for an offshore drilling rig and drilling services on a dayrate contract basis. The integrated services provided under our contracts primarily include (i) provision of an offshore drilling rig, the work crew and supplies of equipment and services necessary to operate the rig, (ii) mobilization and demobilization of the rig to and from the drill site and (iii) performance of rig preparation activities and/or modifications required for each contract.
We account for the integrated services provided within our drilling contracts as a single performance obligation satisfied over time, comprised of a series of distinct time increments in which we provide drilling services. The total transaction price is recognized for each drilling contract by estimating both fixed and variable consideration expected to be earned over the contract term.
Revenues Related to Managed Rigs
In 2021, we entered into an arrangement with an offshore drilling company whereby we agreed to provide management and marketing services (or the MMSA) for certain of their rigs. The MMSA provided for (i) a daily fixed fee, based on status of the drilling rig, (ii) marketing fees based on a percentage of the earned dayrate of a drilling contract secured by us on behalf of the rig owner, (iii) a variable management fee and (iv) reimbursement of direct costs incurred. The fixed and variable fees were recognized in “Contract drilling” revenue in our unaudited Condensed Consolidated Statements of Operations. Revenue related to the reimbursement of expenses incurred and billed to the rig owner were recorded as “Revenues related to reimbursable expenses” in our unaudited Condensed Consolidated Statements of Operations.
We may enter into certain drilling contracts directly with a customer. We are considered principal or agent under these transactions and recognize revenue under the terms of the contract. Such amounts are reported as “Contract drilling” revenue in our unaudited Condensed Consolidated Statements of Operations. In addition, we charter the related drilling rig from the rig owner to satisfy our performance obligation under the contract. We have determined that the arrangement to charter the rig is an operating lease, and the related charter fee has been reported as lease expense within "Contract drilling, excluding depreciation" in our unaudited Condensed Consolidated Statements of Operations.
11
The marketing arrangements for each of the managed rigs, the West Auriga and the West Vela, were terminated in 2023, and the management and charter agreements for the West Auriga were terminated in the first quarter of 2024. The West Auriga was returned to its owner at the end of February 2024. We also received notice of termination of the management agreement for the West Vela in April 2024, which became effective in July 2024. The termination of the management agreement had no effect on the bareboat charter agreement for the West Vela, which will continue in accordance with its terms until the completion of the rig’s existing drilling contract and any option periods.
Contract Balances
The following table provides information about receivables, contract assets and contract liabilities related to our contracts with customers (in thousands):
|
|
June 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Trade receivables |
|
$ |
|
|
$ |
|
||
Current contract assets (1) |
|
|
|
|
|
|
||
Current contract liabilities (deferred revenue) (1) |
|
|
( |
) |
|
|
( |
) |
Noncurrent contract liabilities (deferred revenue) (1) |
|
|
( |
) |
|
|
( |
) |
Changes in the contract assets and the contract liabilities balances during the period are as follows (in thousands):
|
|
Contract |
|
|
Contract |
|
||
|
|
Assets |
|
|
Liabilities |
|
||
Balance as of January 1, 2024 |
|
$ |
|
|
$ |
( |
) |
|
Decrease due to amortization of revenue included in the beginning contract liability balance |
|
|
— |
|
|
|
|
|
Increase due to cash received, excluding amounts recognized as revenue during the period |
|
|
— |
|
|
|
( |
) |
Increase due to revenue recognized during the period but contingent on future performance |
|
|
|
|
|
— |
|
|
Decrease due to transfer to receivables during the period |
|
|
( |
) |
|
|
— |
|
Adjustments |
|
|
( |
) |
|
|
— |
|
Balance as of June 30, 2024 |
|
$ |
|
|
$ |
( |
) |
|
|
|
|
|
|
|
|
||
|
|
|
|
|
|
|
Transaction Price Allocated to Remaining Performance Obligations
The following table reflects revenue expected to be recognized in the future related to unsatisfied performance obligations as of June 30, 2024 (in thousands):
|
|
For the Year Ending December 31, |
|
|||||||||||||||||
|
|
(1) |
|
|
|
|
|
|
|
|
Total |
|
||||||||
Mobilization and contract preparation revenue |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
Capital modification revenue |
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
— |
|
|
|
( |
) |
Blended rate/other revenue |
|
|
( |
) |
|
|
( |
) |
|
|
— |
|
|
|
— |
|
|
|
( |
) |
Total |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
|
$ |
( |
) |
12
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. 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 FASB ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), and its related amendments and have excluded estimated variable consideration related to wholly unsatisfied performance obligations or to distinct future time increments within our contracts, including dayrate revenue.
13
3. Supplemental Financial Information
Unaudited Condensed Consolidated Balance Sheets Information
Accounts receivable, net of allowance for credit losses, consist of the following (in thousands):
|
|
June 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Trade receivables |
|
$ |
|
|
$ |
|
||
Insurance claim receivable (1) |
|
|
|
|
|
|
||
Value added tax receivables |
|
|
|
|
|
|
||
Related party receivables |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
|
|
|
|
|
|
|
||
Allowance for credit losses (2) |
|
|
( |
) |
|
|
( |
) |
Total |
|
$ |
|
|
$ |
|
Prepaid expenses and other current assets consist of the following (in thousands):
|
|
June 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Collateral deposit |
|
$ |
|
|
$ |
|
||
Deferred contract costs |
|
|
|
|
|
|
||
Prepaid taxes |
|
|
|
|
|
|
||
Rig spare parts and supplies |
|
|
|
|
|
|
||
Prepaid insurance |
|
|
|
|
|
|
||
Current contract assets |
|
|
|
|
|
|
||
Software maintenance agreements and subscriptions |
|
|
|
|
|
|
||
Prepaid rig costs |
|
|
|
|
|
|
||
Deferred survey costs |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
Accrued liabilities consist of the following (in thousands):
|
|
June 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Rig operating costs |
|
$ |
|
|
$ |
|
||
Contract advances |
|
|
|
|
|
|
||
Payroll and benefits |
|
|
|
|
|
|
||
Deferred revenue |
|
|
|
|
|
|
||
Interest payable |
|
|
|
|
|
|
||
Current operating lease liability |
|
|
|
|
|
|
||
Accrued capital project/upgrade costs |
|
|
|
|
|
|
||
Personal injury and other claims |
|
|
|
|
|
|
||
Shorebase and administrative costs |
|
|
|
|
|
|
||
Deposit for equipment sale |
|
|
|
|
|
|
||
Other |
|
|
|
|
|
|
||
Total |
|
$ |
|
|
$ |
|
14
Unaudited Condensed Consolidated Statements of Cash Flows Information
Noncash operating, investing and financing activities excluded from the unaudited Condensed Consolidated Statements of Cash Flows and other supplemental cash flow information are as follows (in thousands):
|
|
Six Months Ended |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Accrued but unpaid capital expenditures at period end |
|
$ |
|
|
$ |
|
||
Common stock withheld for payroll tax obligations (1) |
|
|
|
|
|
|
||
Cash interest payments |
|
|
|
|
|
|
||
Cash income taxes paid, net of (refunds): |
|
|
|
|
|
|
||
Foreign |
|
|
|
|
|
|
||
U.S. Federal |
|
|
|
|
|
( |
) |
|
State |
|
|
|
|
|
|
4. Financial Instruments and Fair Value Disclosures
Concentrations of Credit Risk and Allowance for Credit Losses
Our credit risk arises primarily from trade receivables. The market for our services is the offshore oil and gas industry, and our customer base consists primarily of major and independent oil and gas companies, as well as government-owned oil companies. At June 30, 2024, we believed that we had potentially significant concentrations of credit risk due to the number of rigs we had contracted and our limited number of customers, as some of our customers have contracted for multiple rigs.
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, we perform a credit review on that customer, including a review of its credit ratings and financial statements. Based on our credit review, we may require that the customer have a bank issue a letter of credit on its behalf, prepay for the services in advance or provide other credit enhancements. We currently have two customers for which prepayments are required and full payment is due prior to commencement of the contracts in the second half of 2024 and the beginning of 2025, respectively. At June 30, 2024, no amounts were owed by these two customers.
Pursuant to FASB ASU No. 2016-13, Financial Instruments – Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments and its related amendments (or ASU 2016-13), we have reviewed our historical credit loss experience over a look-back period of ten years, which we deem to be representative of both up-turns and down-cycles in the offshore drilling industry. Based on this review, we developed a credit loss factor using a weighted-average ratio of our actual credit losses to revenues during the look-back period. We also considered current and future anticipated economic conditions in determining our credit loss factor, including crude oil prices and liquidity of credit markets. In applying the requirements of ASU 2016-13 and its related amendments (or collectively, CECL), we determined that it would be appropriate to segregate our trade receivables into three credit loss risk pools based on customer credit ratings, each of which represents a tier of increasing credit risk. We calculated a credit loss factor based on historical loss rate information and applied a multiple of our credit loss factor to each of these risk pools, considering the impact of current and future economic information and the level of risk associated with these pools, to calculate our current estimate of credit losses. Trade receivables that are fully covered by allowances for credit losses are excluded from these risk pools for purposes of calculating our current estimate of credit losses.
At June 30, 2024, $
15
December 31, 2023, respectively, including $
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. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges.
Assets and liabilities measured at fair value are summarized below (in thousands).
|
|
June 30, 2024 |
|
|||||||||||||||||
|
|
Fair Value Measurements Using |
|
|
|
|
||||||||||||||
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Assets (Liabilities) |
|
|
Total Losses for |
|
|||||
Recurring fair value measurements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Short-term investments (1) |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
||
stock units (2) |
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
( |
) |
|
|
December 31, 2023 |
|
|||||||||||||||||
|
|
Fair Value Measurements Using |
|
|
|
|
||||||||||||||
|
|
Level 1 |
|
|
Level 2 |
|
|
Level 3 |
|
|
Assets (Liabilities) |
|
|
Total Losses for Year Ended (2) |
|
|||||
Recurring fair value measurements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||
Short-term investments (1) |
|
$ |
|
|
$ |
— |
|
|
$ |
— |
|
|
$ |
|
|
$ |
— |
|
||
stock units (2) |
|
$ |
( |
) |
|
$ |
— |
|
|
$ |
— |
|
|
$ |
( |
) |
|
$ |
( |
) |
16
We believe that the carrying amounts of our other financial assets and liabilities (excluding our 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:
Our long-term debt is not measured at fair value on a recurring basis; however, under the GAAP fair value hierarchy, such indebtedness would be considered Level 2 liabilities. The fair value of the instrument was derived using valuation specialists at June 30, 2024 and December 31, 2023.
Fair values and related carrying values of our Second Lien Notes (as defined below in Note 6 “Long-Term Debt”) are shown below (in millions).
|
|
June 30, 2024 |
|
|
December 31, 2023 |
|
||||||||||
|
|
Fair Value |
|
|
Carrying Value |
|
|
Fair Value |
|
|
Carrying Value |
|
||||
Second Lien Notes |
|
$ |
|
|
$ |
|
|
$ |
|
|
$ |
|
We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Certain inputs and value drivers are observed and obtained in active markets from similar assets or liabilities while 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.
5. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows (in thousands):
|
|
June 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
Drilling rigs and equipment |
|
$ |
|
|
$ |
|
||
Finance lease right of use asset |
|
|
|
|
|
|
||
Land and buildings |
|
|
|
|
|
|
||
Office equipment and other |
|
|
|
|
|
|
||
Cost |
|
|
|
|
|
|
||
Less: accumulated depreciation |
|
|
( |
) |
|
|
( |
) |
Drilling and other property and equipment, net |
|
$ |
|
|
$ |
|
6. Long-Term Debt
At June 30, 2024 and December 31, 2023, the carrying value of our long-term debt, net of unamortized debt issuance costs, was comprised as follows (in thousands):
|
|
June 30, |
|
|
December 31, |
|
||
|
|
2024 |
|
|
2023 |
|
||
$ |
|
$ |
|
|
$ |
|
Second Lien Notes
17
On September 21, 2023, Diamond Foreign Asset Company and Diamond Finance, LLC (collectively referred to as the Issuers) issued $
The Second Lien Notes obligate DODI and its specified subsidiaries to comply with an indenture dated as of September 21, 2023 (or the Indenture) entered into by the Issuers, DODI and certain of its subsidiaries named therein and HSBC Bank USA, National Association. The Indenture contains covenants that, among other things, restrict DODI’s ability and the ability of certain of its subsidiaries to: (i) incur additional debt and issue certain preferred stock; (ii) incur or create liens; (iii) make certain dividends, distributions, investments and other restricted payments; (iv) sell or otherwise dispose of certain assets; (v) engage in certain transactions with affiliates; and (vi) merge, consolidate, amalgamate or sell, transfer, lease or otherwise dispose of all or substantially all of DODI’s assets. These covenants are subject to important exceptions and qualifications.
The Second Lien Notes were valued at par at issuance and were presented net of unamortized debt issuance costs of $
Revolving Credit Agreement
Our revolving credit agreement provides for a $
At June 30, 2024 and August 5, 2024, we had
There is
At June 30, 2024, we were in compliance with all covenants under the Second Lien Notes and the RCF.
7. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims by offshore workers alleging personal injuries. With respect to each claim or exposure, we have made an assessment, in accordance with GAAP, of the probability that the resolution of the matter would ultimately result in a loss. When we determine that an unfavorable resolution of a matter is probable and such amount of loss can be determined, we record a liability for the amount of the estimated loss at the time that both of these criteria are met. Our management believes that we have recorded adequate accruals for any liabilities that may reasonably be expected to result from these claims.
Non-Income Tax and Related Claims. We have received assessments related to, or otherwise have exposure to, non-income tax items such as sales-and-use tax, value-added tax, ad valorem tax, custom duties, and other similar taxes in various taxing jurisdictions. We have determined that we have a probable loss for certain of these taxes and the related penalties and interest and, accordingly, have recorded a $
18
Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business. 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 such pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
Personal Injury Claims. Under our current insurance policies, which renewed effective May 1, 2024, we generally self-insure $
The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to “Accrued liabilities” based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as “Other liabilities.” At June 30, 2024, our estimated liability for personal injury claims was $
Purchase Obligations. At June 30, 2024, we had
Services Agreement. In February 2016, we entered into a
In addition, we lease Well Control Equipment for our drillships under ten-year finance leases that commenced in 2016 that also include an option to purchase the leased equipment at the end of the respective lease term.
Letters of Credit and Other. As of June 30, 2024, an aggregate of $
8. Ocean GreatWhite Insurance Claim
19
On February 1, 2024, the Ocean GreatWhite reported an equipment incident while located in the North Sea west of the Shetland Islands. The rig’s lower marine riser package (or LMRP) and deployed riser string unintentionally separated from the rig at the slip joint tensioner ring, and the LMRP and riser dropped to the seabed. We have recovered the LMRP from the seabed and the Ocean GreatWhite resumed operations under the rig’s drilling contract in early July 2024.
As of the date of this report, we have incurred $
9. Earnings Per Share
We compute basic earnings per share by dividing net income available to holders of our common stock by the weighted-average number of shares of our common stock outstanding during the period. Diluted earnings per share reflects the potential dilution that could occur if securities or other contracts to issue our common stock (common stock equivalents) were exercised or converted into common stock. Basic and diluted earnings per share (or EPS) was calculated in accordance with the treasury stock method, and includes all potentially dilutive stock equivalents, including warrants, restricted stock unit awards and performance stock unit awards.
A reconciliation of the numerators and denominators of our basic and diluted EPS computations is summarized as follows (in thousands).
|
|
Three Months Ended |
|
|||||
|
|
2024 |
|
|
2023 |
|
||
Net income – basic and diluted (numerator) |
|
$ |
|
|
$ |
|
||
Weighted average shares – basic (denominator): |
|
|
|
|
|
|
||
Dilutive effect of stock-based awards |
|
|
|
|
|
|
||
Weighted average shares including conversions – diluted (denominator) |
|
|
|
|
|
|
|
|
Six Months Ended |
|
|
|||||
|
|
2024 |
|
|
2023 |
|
|
||
Net income – basic and diluted numerator |
|
$ |
|
|
$ |
|
|
||
Weighted average shares – basic (denominator): |
|
|
|
|
|
|
|
||
Dilutive effect of stock-based awards |
|
|
|
|
|
|
|
||
Weighted average shares including conversions – diluted (denominator) |
|
|
|
|
|
|
|
The computation of EPS for the three-month and six-month periods ended June 30, 2024 excluded non-vested stock-based awards of
As of June 30, 2024, we had
20
10. Segments and Geographic Area Analysis
We provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations. However, we have aggregated these operations into
Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At June 30, 2024, our active drilling rigs were located offshore
The following tables provide information about disaggregated revenue by country (in thousands):
|
|
Three Months Ended June 30, 2024 |
|
|||||||||
|
|
Total |
|
|
Revenues |
|
|
Total |
|
|||
United States |
|
$ |
|
|
$ |
|
|
$ |
|
|||
United Kingdom |
|
|
|
|
|
|
|
|
|
|||
Brazil |
|
|
|
|
|
|
|
|
|
|||
Senegal |
|
|
|
|
|
|
|
|
|
|||
Australia |
|
|
|
|
|
|
|
|
|
|||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
|
|
Six Months Ended June 30, 2024 |
|
|||||||||
|
|
Total |
|
|
Revenues |
|
|
Total |
|
|||
United States |
|
$ |
|
|
$ |
|
|
$ |
|
|||
United Kingdom |
|
|
|
|
|
|
|
|
|
|||
Brazil |
|
|
|
|
|
|
|
|
|
|||
Senegal |
|
|
|
|
|
|
|
|
|
|||
Australia |
|
|
|
|
|
|
|
|
|
|||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
|
|
Three Months Ended June 30, 2023 |
|
|||||||||
|
|
Total |
|
|
Revenues |
|
|
Total |
|
|||
United States |
|
$ |
|
|
$ |
|
|
$ |
|
|||
United Kingdom |
|
|
|
|
|
|
|
|
|
|||
Brazil |
|
|
|
|
|
|
|
|
|
|||
Senegal |
|
|
|
|
|
|
|
|
|
|||
Australia |
|
|
|
|
|
|
|
|
|
|||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
21
|
|
Six Months Ended June 30, 2023 |
|
|||||||||
|
|
Total |
|
|
Revenues |
|
|
Total |
|
|||
United States |
|
$ |
|
|
$ |
|
|
$ |
|
|||
United Kingdom |
|
|
|
|
|
|
|
|
|
|||
Brazil |
|
|
|
|
|
|
|
|
|
|||
Senegal |
|
|
|
|
|
|
|
|
|
|||
Australia |
|
|
|
|
|
|
|
|
|
|||
Total |
|
$ |
|
|
$ |
|
|
$ |
|
22
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”[1] included in our Annual Report on Form 10-K for the year ended December 31, 2023 and Part II, Item 1A, “Risk Factors” in this report. References to “Diamond Offshore,” “Company,” “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 12 floater rigs (four owned drillships, seven owned semisubmersibles, including one semisubmersible that is held for sale, and one managed rig). See “– Market Overview.”
Recent Events
On June 9, 2024, Diamond Offshore Drilling, Inc. (or DODI) entered into an Agreement and Plan of Merger (or the Merger Agreement) with Noble Corporation plc, a public limited company incorporated under the laws of England and Wales (or Noble), Dolphin Merger Sub 1, Inc., a Delaware corporation and indirect wholly owned subsidiary of Noble (or Merger Sub 1) and Dolphin Merger Sub 2, Inc., a Delaware corporation and indirect wholly owned subsidiary of Noble (or Merger Sub 2). The Merger Agreement provides that, among other things and subject to the terms and conditions of the Merger Agreement, (1) Merger Sub 1 will merge with and into DODI, with DODI surviving as a wholly-owned indirect subsidiary of Noble (or the First Merger and the effective time thereof, the
First Merger Effective Time), and subsequently DODI, as the surviving entity in the First Merger, will merge with and into Merger Sub 2, with Merger Sub 2 surviving as an indirect wholly-owned subsidiary of Noble (or the Second Merger and the effective thereof, the Effective Time; and the First Merger together with the Second Merger, the Merger) and (2) at the First Merger Effective Time, each outstanding share of common stock of DODI (other than any Cancelled Shares and any Appraisal Shares (each as defined in the Merger Agreement)) will be converted into the right to receive the following consideration (or collectively, the Merger Consideration): (i) $5.65 in cash, without interest, payable to the holders of the DODI common stock, (ii) 0.2316 (or the Exchange Ratio) ordinary shares of Noble and (iii) any cash in lieu of fractional ordinary shares of Noble. The completion of the transaction is subject to shareholder and regulatory approvals and other customary closing conditions. See Part II, Item IA, “Risk Factors” for a discussion of certain risks related to the Merger.
Market Overview
Oil commodity prices remained elevated above their 5-year average during the second quarter of 2024, primarily as a result of continued OPEC+ supply restraint, muted production growth in the United States, moderate growth in oil demand and expanding manufacturing trends in the United States and China signaling global economic improvements. Oil and natural gas benchmark prices are expected to remain volatile for the near term as geopolitical uncertainty resulting from conflicts in Russia/Ukraine and the Middle East along with the global level of economic activity may continue to affect supply and demand. Brent crude prices reached the high $80-per-barrel range in mid-July 2024, which represents an approximate 11% increase since July 2023, according to pricing data published by the U.S. Energy Information Administration. Commodity prices are expected to remain at levels that are supportive of investment in deepwater exploration and development projects. As of mid-July 2024, dated Brent crude oil prices for the remainder of 2024 and 2025 were in the high $70 to low $80-per-barrel range according to industry data.
In the second quarter of 2024, growth in offshore upstream capital expenditures continued to be supported by strong cash flows realized by oil and gas companies, continued expectations for growing demand, and breakeven development and production costs well below current oil price forecasts. According to industry reports, analysts expect offshore upstream capital expenditures to increase approximately 5% annually, on average, from 2024 to 2027, rising to more than $250 billion by 2027, with greenfield projects growing to approximately 59% of the capital expenditure total.
During the second quarter of 2024, the positive dynamics of increased offshore spending, coupled with the growing trend in long-cycle developments, production capacity expansions and exploration and appraisal activities, continued to drive growth in demand for floating drilling rigs. According to data from S&P Global, outstanding demand from floating rig tenders was approximately 68 rig years in mid-July 2024, compared to 47 rig years a year earlier, marking an increase of more than 43%. Most of this demand is concentrated in the deepwater and ultra-deepwater regions of the Gulf of Mexico, Brazil and West Africa, which are areas where we currently operate a portion
23
of our fleet. The improvement in contracting activity has pushed dayrates for ultra-deepwater drilling rigs into the high $400,000 to low $500,000 per day range for term contracts.
During the same period, offshore spending demand in the UK sector softened due to the continuation of the Energy Profits Levy affecting production in the region along with political uncertainty associated with the parliamentary elections.
The current robust deepwater dayrate market, combined with anticipated growth in upstream capital spending, continues to drive further increases in rig demand and improves the economics for rig reactivations. However, supply chain constraints and inflationary pressures could limit the pace at which these additional rigs could return to the market. Some analysts estimate that the average time for rig reactivations is approximately 12 to 18 months, with costs approaching $100 million for idle rigs and $350 million for stranded rigs. The current inventory of idle rig capacity has decreased significantly, and the owners of this remaining capacity have so far exhibited capital discipline as it relates to reactivation investments; however, the market could be adversely affected by the re-entry of this limited idle capacity.
Despite policy tightening by major central banks and a moderating pace of world economic expansion, inflationary pressures have generally remained elevated in the industry sector, though recent trends indicate possible moderation in some areas. Continued inflation may result in upward pressure on operating expenses for offshore drillers.
In addition to market factors, during the second quarter of 2024, customer capital allocation decisions have continued to affect demand for our services. Customer investment mixes over time, coupled with energy demand and regulatory measures, could adversely impact demand for offshore drilling services in the long term. Notwithstanding this possibility, during the second quarter, global energy demand continued on pace and energy supply growth remained constrained. We expect increased investment in both traditional and renewable sources of energy to be required in the future, some of which we expect to be invested in finding and producing hydrocarbons in the offshore segment. Continued investment in renewable energy is resulting in this sector satisfying a growing percentage of total energy demand. Growth of renewable and other non-hydrocarbon energy sources may effect demand for our services over time. Industry experts continue to expect the world's demand for energy will increase and that hydrocarbons will continue to serve a major role in meeting the world's energy needs for the foreseeable future.
See “– Contract Drilling Backlog” for future commitments of our rigs during the remainder of 2024 through 2028.
24
Contract Drilling Backlog
We believe that our contract drilling backlog provides a useful indicator of our future revenue-earning opportunities. 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. The contract period is based on the number of stated days for fixed-term contracts or an estimated duration (in days) for contracts based on a fixed number of wells. 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 may be different than the amounts and periods shown in the tables below due to various factors. Our utilization rates, which generally have been in the range of 92-98% during contracted periods, can be adversely impacted due to various operating factors including unscheduled repairs and maintenance, weather conditions, and other factors. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. Revenue is generally not earned during periods of downtime for regulatory surveys; however, certain contracts may provide for reduced revenue during the survey period. 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 regarding 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 “Revenue from Contracts with Customers” excludes dayrate revenue and reflects expected future revenue for mobilization, demobilization and capital modifications to our rigs, which are related to non-distinct promises within our signed contracts. See “– Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows.”
The following table reflects our contract drilling backlog as of July 1, 2024 (based on information available at that time), January 1, 2024 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2023), and July 1, 2023 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended June 30, 2023) (in millions).
|
|
July 1, |
|
|
January 1, |
|
|
July 1, |
|
|||
Contract Drilling Backlog (1) |
|
$ |
2,033 |
|
|
$ |
1,424 |
|
|
$ |
1,580 |
|
25
The following table reflects the amount of revenue related to our contract drilling backlog by year as of July 1, 2024 (in millions).
|
For the Year Ending December 31, |
|
||||||||||||||||
|
Total |
|
2024 (1) |
|
2025 (3) |
|
2026 |
|
2027 |
|
2028 |
|
||||||
Contract Drilling Backlog (2) |
$ |
2,033 |
|
$ |
457 |
|
$ |
755 |
|
$ |
628 |
|
$ |
190 |
|
$ |
3 |
|
The following table reflects the percentage of rig days per year committed as of July 1, 2024. 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 and rigs held for sale, multiplied by the number of days in a particular year).
|
|
For the Year Ending December 31, |
||||||||||||||||
|
|
2024 (1) |
|
|
2025 |
|
|
2026 |
|
|
2027 |
|
|
2028 |
||||
Percentage of Rig Days Committed (2) |
|
|
90 |
% |
|
|
62 |
% |
|
|
51 |
% |
|
|
23 |
% |
|
<1% |
Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows
Regulatory Surveys and Planned Downtime. We perform certain regulatory inspections, which we refer to as a special survey, that are due every five years for most of our rigs and an intermediate survey, which is performed every two-and-one-half years, for our North Sea rigs. Our operating income is negatively impacted when we perform these required regulatory surveys due to planned downtime during the inspection period. Our operating income is also reduced 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. During the remainder of 2024, we expect to incur approximately 150 days of planned downtime, including approximately (i) 100 days for a shipyard project, as well as mobilization and demobilization activities for the Ocean BlackRhino; (ii) 25 days for the Ocean Endeavor’s blowout preventer recertification; (iii) 20 days for the Ocean BlackHornet’s special survey; and (iv) five days for the Ocean GreatWhite’s lower marine riser package (or LMRP) recovery and recertification. During 2025, we expect to incur approximately 45 days of planned downtime, including approximately (i) 20 days for the Ocean Endeavor’s blowout preventer recertification, (ii) 20 days for the Ocean BlackLion’s special survey and (iii) 5 days for the Ocean Apex’s mobilization. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, repairs, contract preparation, rig mobilizations and other shipyard projects. See “ — Contract Drilling Backlog.”
Physical Damage and Marine Liability Insurance. Under our primary insurance policies, which renewed effective May 1, 2024, we carry $50.0 million of U.S. Named Windstorm Coverage, as defined by the relevant insurance policy, for physical damage to our property and equipment with a $10.0 million deductible per accident or occurrence. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico in excess of $50.0 million. 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 results of operations, financial condition, 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 $10.0 million per occurrence. In addition, we currently carry loss-of-hire insurance on certain of our owned rigs to cover a portion of lost cash flow when a rig is damaged, which is a recoverable claim under the physical damage insurance but excludes named windstorms in the U.S. Gulf of Mexico.
26
In addition, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, collisions, and wreck removals, 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 marine liability policies, we generally self-insure $1.0 million to $2.5 million per occurrence, depending on jurisdiction, but up to $25.0 million for liabilities arising out of named windstorms in the U.S. Gulf of Mexico. Depending on the nature, severity, and frequency of claims that might arise during the policy year, if the aggregate level of claims exceeds certain thresholds, we may self-insure up to $100.0 million for each subsequent occurrence.
Critical Accounting Policies
Our significant accounting policies are discussed in Note 1 “General Information” of our notes to the audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2023.
Results of Operations
We have elected to present a comparison of our results of operations for the current quarter with that of the immediately preceding quarter, as permitted under Item 303(c)(2)(ii) of Regulation S-K. We believe this comparison is more useful in identifying business trends and provides a more meaningful analysis of our business as our results are largely driven by market changes rather than seasonal business activity. We continue to present the required comparison of current year-to-date results with the same period of the prior year.
Our operating results for contract drilling services are dependent on three primary metrics or key performance indicators: revenue-earning (or R-E) days, rig utilization and average daily revenue. We believe that R-E days provide a comparative measurement of the activity level of our fleet, rig utilization is an indicator of our ability to secure work for and the operational efficiency of our fleet and average daily revenue provides a comparative measure for our revenue-earning performance. We utilize these performance indicators in the review of our business and operating results and believe these are useful metrics for investors to utilize in evaluating our performance. The tables presented below include these three key performance indicators and other comparative data relating to our revenues and operating expenses for the respective periods (in thousands, except days, daily amounts and percentages) for the three-month periods ended June 30, 2024 and March 31, 2024 and the six-month periods ended June 30, 2024 and June 30, 2023.
27
Results for the Three-Month Periods Ended June 30, 2024 and March 31, 2024
|
|
Three Months Ended |
|
|||||
|
|
June 30, |
|
|
March 31, |
|
||
|
|
2024 |
|
|
2024 |
|
||
Revenue-Earning Days (1) |
|
|
756 |
|
|
|
849 |
|
Utilization (2) |
|
|
69 |
% |
|
|
68 |
% |
Average daily revenue (3) |
|
$ |
317,800 |
|
|
$ |
305,000 |
|
|
|
|
|
|
|
|
||
Revenues: |
|
|
|
|
|
|
||
Contract drilling |
|
$ |
240,229 |
|
|
$ |
258,770 |
|
Revenues related to reimbursable expenses |
|
|
12,657 |
|
|
|
15,840 |
|
Total revenues |
|
|
252,886 |
|
|
|
274,610 |
|
Operating expenses: |
|
|
|
|
|
|
||
Contract drilling, excluding depreciation |
|
|
164,461 |
|
|
|
184,205 |
|
Reimbursable expenses |
|
|
12,333 |
|
|
|
15,266 |
|
Depreciation |
|
|
31,698 |
|
|
|
31,354 |
|
General and administrative |
|
|
23,219 |
|
|
|
18,576 |
|
(Gain) loss on disposition of assets |
|
|
(7,106 |
) |
|
|
3,396 |
|
Total operating expenses |
|
|
224,605 |
|
|
|
252,797 |
|
Operating income |
|
|
28,281 |
|
|
|
21,813 |
|
Other income (expense): |
|
|
|
|
|
|
||
Interest income |
|
|
1,966 |
|
|
|
1,774 |
|
Interest expense |
|
|
(15,061 |
) |
|
|
(15,346 |
) |
Foreign currency transaction (loss) gain |
|
|
(13 |
) |
|
|
231 |
|
Other, net |
|
|
1,605 |
|
|
|
(71 |
) |
Income before income tax (expense) benefit |
|
|
16,778 |
|
|
|
8,401 |
|
Income tax (expense) benefit |
|
|
(7,451 |
) |
|
|
3,211 |
|
Net income |
|
$ |
9,327 |
|
|
$ |
11,612 |
|
|
|
|
|
|
|
|
Three Months Ended June 30, 2024 Compared to Three Months Ended March 31, 2024
Contract Drilling Revenue. Contract drilling revenue decreased $18.5 million during the three months ended June 30, 2024 compared to the three months ended March 31, 2024, primarily due to a 93-day decrease in R-E days ($27.4 million), partially offset by higher average daily revenue earned ($8.9 million).
R-E days decreased during the second quarter of 2024, primarily due to termination of the managed services agreement and charter of the West Auriga (60 fewer R-E days) and downtime for repairs to the Ocean GreatWhite related to an equipment incident (30 fewer R-E days), both of which occurred in the first quarter of 2024, and additional warm stacked days between contracts for the Ocean Patriot (17 fewer R-E days). The decrease in R-E days was partially offset by an aggregate net increase in R-E days for the other rigs in our fleet (14 incremental R-E days).
The increase in average daily revenue during the second quarter of 2024, compared to the first quarter of 2024 was primarily due to performance bonuses earned by our operations in Senegal.
Contract drilling expense, excluding depreciation. Contract drilling expense, excluding depreciation, decreased $19.7 million during the second quarter of 2024, compared to the first quarter of 2024. The decrease was primarily due to the absence of costs for the West Auriga as a result of the termination of its charter in the first quarter of 2024 ($19.7 million) and non-recoverable expense (or a portion of an insurance deductible) in the first quarter of 2024 and the recovery of prior period expense, both of which related to the equipment incident on the Ocean GreatWhite ($18.7 million). The decrease in contract drilling expense, excluding depreciation, was partially offset by an aggregate net
28
increase in expense for the other rigs in our fleet ($18.7 million), which included higher costs for repairs and maintenance, equipment rentals and integrated services provided to our customers.
General and administrative. General and administrative expense for the second quarter of 2024 increased $4.6 million compared to the first quarter of 2024, primarily due to professional fees incurred in connection with the proposed Merger.
(Gain) Loss on disposition of assets. We recorded a net gain on disposition of assets that was $10.5 million higher for the second quarter of 2024, compared to the first quarter of 2024. In April 2024, we disposed of the Ocean Monarch and recognized a net gain on the sale ($6.4 million). Additionally, the increased net gain was due to the absence in the second quarter of 2024 of a loss on disposition of assets associated with the equipment incident on the Ocean GreatWhite recognized during the first quarter of 2024 ($3.4 million).
Income Tax Benefit. We estimate our annual effective tax rate (or AETR) for continuing operations in recording our interim quarterly income tax provision, considering the various jurisdictions in which we operate. We exclude discrete tax adjustments from the computation of the AETR and record such adjustments in the quarter in which they occur.
We recorded a net income tax expense of $7.5 million for the three months ended June 30, 2024. For the three months ended March 31, 2024, we recorded a net income tax benefit of $3.2 million, inclusive of a $12.2 million tax benefit resulting from the revaluation of unrecognized tax benefits denominated in the Egyptian pound. The higher effective tax rate for the three months ended June 30, 2024 reflects the mix of pre-tax income and loss across jurisdictions and increased profitability in the jurisdictions in which our rigs are currently operating. Additionally, the higher effective tax rate for the quarter ended June 30, 2024 reflects stabilization of the Egyptian pound.
Results for the Six-Month Periods Ended June 30, 2024 and June 30, 2023
|
|
Six Months Ended |
|
|
|||||
|
|
June 30, |
|
|
June 30, |
|
|
||
|
|
2024 |
|
|
2023 |
|
|
||
Revenue-Earning Days |
|
|
1,602 |
|
|
|
1,676 |
|
|
Utilization |
|
|
69 |
% |
|
|
66 |
% |
|
Average daily revenue |
|
$ |
311,400 |
|
|
$ |
286,000 |
|
|
|
|
|
|
|
|
|
|
||
Revenues: |
|
|
|
|
|
|
|
||
Contract drilling |
|
$ |
498,999 |
|
|
$ |
479,373 |
|
|
Revenues related to reimbursable expenses |
|
|
28,497 |
|
|
|
34,211 |
|
|
Total revenues |
|
|
527,496 |
|
|
|
513,584 |
|
|
Operating expenses: |
|
|
|
|
|
|
|
||
Contract drilling, excluding depreciation |
|
|
348,665 |
|
|
|
386,436 |
|
|
Reimbursable expenses |
|
|
27,599 |
|
|
|
32,792 |
|
|
Depreciation |
|
|
63,052 |
|
|
|
55,812 |
|
|
General and administrative |
|
|
41,796 |
|
|
|
36,409 |
|
|
Gain on disposition of assets |
|
|
(3,710 |
) |
|
|
(3,146 |
) |
|
Total operating expenses |
|
|
477,402 |
|
|
|
508,303 |
|
|
Operating income |
|
|
50,094 |
|
|
|
5,281 |
|
|
Other income (expense): |
|
|
|
|
|
|
|
||
Interest income |
|
|
3,740 |
|
|
|
12 |
|
|
Interest expense |
|
|
(30,407 |
) |
|
|
(24,795 |
) |
|
Foreign currency transaction gain (loss) |
|
|
218 |
|
|
|
(3,239 |
) |
|
Other, net |
|
|
1,534 |
|
|
|
(17 |
) |
|
Income (loss) before income tax (expense) benefit |
|
|
25,179 |
|
|
|
(22,758 |
) |
|
Income tax (expense) benefit |
|
|
(4,240 |
) |
|
|
268,770 |
|
|
Net income |
|
$ |
20,939 |
|
|
$ |
246,012 |
|
|
29
Six Months Ended June 30, 2024 Compared to Six Months Ended June 30, 2023
Contract Drilling Revenue. Contract drilling revenue increased $19.6 million during the six months ended June 30, 2024 compared to the six months ended June 30, 2023, primarily due to higher average daily revenue earned ($40.8 million). The increase in revenue was partially offset by a 74-day decrease in R-E days ($21.2 million).
Average daily revenue for the six months ended June 30, 2024 increased, compared to the prior year period, primarily due to higher dayrates earned under new contracts that commenced in the fourth quarter of 2023 for several rigs. Additionally, the average daily revenue was favorably impacted by performance bonuses for our operations in Senegal earned during the six months ended June 30, 2024.
R-E days during the six months ended June 30, 2024 decreased, compared to the prior year period, primarily due to the termination of the management and charter agreement of the West Auriga in February 2024 (114 fewer R-E days), downtime for repairs to the Ocean GreatWhite (60 fewer R-E days), the stacking of rigs between contracts (34 fewer R-E days) and incremental unpaid nonproductive days across our fleet (37 fewer R-E days). The decrease in R-E days was partially offset by incremental operating days for the Ocean Apex and Ocean Endeavor (171 incremental R-E days), both of which completed shipyard projects in 2023.
Contract drilling expense, excluding depreciation. Contract drilling expense, excluding depreciation, decreased $37.8 million during the six months ended June 30, 2024, compared to the prior year period, primarily due to a reduction in contract drilling expense, including charter costs for the West Auriga ($36.5 million), as a result of the termination of the managed services agreement and rig charter, lower contract drilling expense across our fleet ($18.8 million), which reflected the absence of costs associated with the Ocean Apex’s shipyard in 2023 and lower costs for mobilization of rigs, and reduced costs associated with cold-stacked rigs ($4.1 million). The decrease in contract drilling expense during the six months ended June 30, 2024 was partially offset by the higher charter and operating expense for the West Vela ($14.0 million) and non-recoverable expense (or a portion of the insurance deductible) associated with the LMRP equipment incident on the Ocean GreatWhite ($7.6 million).
Depreciation expense. Depreciation expense increased $7.2 million during the six months ended June 30, 2024, compared to the prior year period, primarily due to a higher depreciable asset base in the first six months of 2024, compared to the prior year period.
General and administrative. General and administrative expense increased $5.4 million during the six months ended June 30, 2024, compared to the prior year period, primarily due to professional fees associated with the proposed Merger.
Interest Expense. Interest expense increased $5.6 million during the six months ended June 30, 2024, compared to the prior year period, primarily due to higher average debt outstanding compared to the prior year period. Interest expense for the first half of 2024 included $24.3 million in expense related to our $550.0 million aggregate principal amount of senior secured second lien notes (or the Second Lien Notes), which were issued in September 2023 and bear interest at 8.5%, and the amortization of associated debt issuance costs. Additionally, interest expense for the first half of 2024 included $4.2 million in interest related to finance leases. During the first half of 2023, we incurred interest expense of $19.9 million on weighted average debt outstanding of approximately $363.3 million at an average interest rate of 9.5%, in addition to amortization of associated debt issuance costs and debt premium. Additionally, interest expense for the first half of 2023 included $4.7 million related to finance leases.
Income Tax (Expense) Benefit. We recorded a net income tax expense of $4.2 million for the six months ended June 30, 2024, inclusive of a $12.5 million tax benefit on the revaluation of unrecognized tax benefits in Egypt due to the significant weakening of the Egyptian pound. For the six months ended June 30, 2023, we recorded a net income tax benefit of $268.8 million. The variation in the effective tax rate for the six months ended June 30, 2024 was the result of the mix of pre-tax income and loss across jurisdictions and increased profitability in jurisdictions in which rigs were operating.
Liquidity and Capital Resources
We have available a revolving credit agreement, which provides for a $300.0 million senior secured revolving credit facility (or the RCF). The RCF is scheduled to mature on April 22, 2026. See Note 6 “Long-Term Debt” to our
30
unaudited condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of our RCF.
At August 5, 2024, we had no borrowings outstanding under the RCF and the entire $300.0 million was available for borrowings under the RCF subject to its terms and conditions. However, the availability of borrowings under the RCF is subject to the satisfaction of certain conditions as specified in our revolving credit agreement, including restrictions on borrowings.
There is no capacity for the issuance of letters of credit under the RCF, but the RCF permits us to obtain up to $50.0 million in letters of credit outside the RCF. We have obtained a separate $25.0 million letter of credit facility; however, letters of credit under the facility must be cash collateralized. As of August 5, 2024, we utilized $1.9 million of this facility for the issuance of a letter of credit, which is scheduled to expire in May 2025.
Historically, we have relied on our cash flows from operations and cash reserves to meet our liquidity needs, which primarily include funding of our working capital requirements and capital expenditures, as well as the servicing of our debt repayments and interest payments. As of August 5, 2024, all of our rigs, excluding our managed rig, are owned and operated, directly or indirectly, by Diamond Foreign Asset Company (or DFAC). Our management has determined that we will permanently reinvest foreign earnings, which restricts the ability to utilize cash flows of DFAC on a company-wide basis. To the extent possible, we expect to utilize the operating cash flows and cash reserves of DFAC and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each respective entity's working capital requirements and capital commitments.
From time to time, based on market conditions and other factors, we may seek to repay, refinance or restructure all or a portion of our outstanding indebtedness or otherwise enter into transactions regarding our capital structure to obtain more favorable terms, enhance flexibility in conducting our business, increase liquidity or otherwise. We regularly evaluate capital markets to consider future opportunities for enhancements of our capital structure and may opportunistically pursue financing transactions to optimize our capital structure. Our ability to access the capital markets by issuing debt or equity securities will be dependent on the contractual restriction under the Noble Merger Agreement, our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control, and there can be no assurance that we would be able to complete any such offering of securities.
As of July 1, 2024, our contractual backlog was approximately $2.0 billion. At June 30, 2024, we had cash of $178.0 million, including $12.4 million that is subject to restrictions.
Sources and Uses of Cash
Cash Flows and Cash Expenditures
For the six-month period ended June 30, 2024, our operating activities generated cash of $89.9 million. Cash receipts from contract drilling services ($569.1 million) were partially offset by cash expenditures for contract drilling, shorebase support, and general and administrative costs ($479.2 million).
Cash outlays for capital expenditures during the first half of 2024 aggregated $51.3 million, primarily related to long-lead items related to the Ocean BlackRhino’s managed pressure drilling upgrade planned for the fourth quarter of 2024 and our ongoing capital maintenance and improvement program. We also paid $8.9 million in connection with our finance lease obligations for well control equipment on our four owned drillships.
For the six-month period ended June 30, 2023, our operating activities generated cash of $10.7 million. Cash receipts from contract drilling services ($486.9 million) were partially offset by cash expenditures for contract drilling, shorebase support, and general and administrative costs ($476.2 million).
Cash outlays for capital expenditures during the first half of 2023 aggregated $59.0 million, primarily related to shipyard projects for the Ocean Endeavor, Ocean GreatWhite, Ocean Apex and Ocean BlackHawk. During the first six months of 2023, we borrowed a net $5.0 million under the RCF and made payments in connection with finance lease obligations aggregating $10.5 million related to well control equipment on our owned drillships.
31
Ocean GreatWhite Equipment Incident
On February 1, 2024, the Ocean GreatWhite, reported an equipment incident while located in the North Sea west of the Shetland Islands. The rig’s LMRP and deployed riser string unintentionally separated from the rig at the slip joint tensioner ring and the LMRP and riser dropped to the seabed. We have recovered the LMRP from the seabed and the Ocean GreatWhite resumed operations under the rig’s drilling contract in early July 2024.
We anticipate that the repairs and equipment replacement associated with the equipment incident will be covered by our hull & machinery insurance policy and that all incremental costs, less our $10.0 million deductible, will be reimbursable under that policy. In addition, we carry loss-of-hire insurance on the Ocean GreatWhite to cover a portion of lost cash flow under certain circumstances. After a 60-day waiting period, our loss-of-hire insurance provides $150,000 per day, for up to 180 days, for each day of lost revenue as a result of a covered property loss claim. As of the date of this report, we estimate that we will be entitled to approximately 90 days of loss-of-hire insurance recovery, none of which has been included in our financial results to date. Additionally, we estimate the cash flow impact of direct and incremental recovery, repairs and maintenance costs, and replacement capital expenditures, offset by loss-of-hire insurance, to be approximately $25.0 million to $30.0 million as of the date of this report. However, we cannot fully predict the extent of such insurance coverage or the timing of such claims.
Capital Expenditures and Other Projects
We have historically invested a significant portion of our cash flows in the enhancement of our drilling fleet and our ongoing rig equipment replacement and capital maintenance programs. 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 rig equipment enhancement, maintenance and replacement programs. We make periodic assessments of our capital spending programs based on current and expected industry conditions and our cash flow forecast. As of the date of this report, we expect total capital expenditures for 2024 to be approximately $135.0 million to $145.0 million.
Other Obligations
As of June 30, 2024, the amount of total net unrecognized tax benefits related to uncertain tax positions that could result in a future cash payment was $38.1 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.
Other Commercial Commitments - Letters of Credit
See Note 7 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report for a discussion of certain of our other commercial commitments.
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (or the Securities Act) and Section 21E of the Securities Exchange Act of 1934, as amended (or the Exchange Act). All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “would,” “may,” “might,” “will,” “will be,” “will continue,” “will likely result,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, the proposed business combination between the Company and Noble pursuant to the Merger Agreement, 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:
32
33
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 in Item 1A, “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2023 and Part II, Item 1A, “Risk Factors” in 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,
34
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.
The information included in this Item 3 constitutes “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Forward-Looking Statements” in Item 2 of Part I of this report.
Interest Rate Risk. From time to time, we may have exposure to interest rate risk on our debt instruments that may arise from changes in the level or volatility of interest rates. As of June 30, 2024, we had no variable rate debt outstanding. Our Second Lien Notes have been issued at fixed rates, and as such, interest expense would not be impacted by interest rate shifts.
There were no other material changes in our market risk components for the six months ended June 30, 2024. 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, 2023 for further information.
ITEM 4. Controls and Procedures.
We maintain a system of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.
Our Chief Executive Officer (or CEO) and Chief Financial Officer (or CFO) participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of June 30, 2024. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of June 30, 2024.
There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our second fiscal quarter of 2024 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
35
PART II. OTHER INFORMATION
ITEM 1. Legal Proceedings.
Information related to certain legal proceedings is included in Note 7 “Commitments and Contingencies” to our unaudited condensed consolidated financial statements included in Item 1 of Part I of this report, which is incorporated herein by reference.
ITEM 1A. Risk Factors.
Due to the announced Merger with Noble, there have been material changes to the risk factors included in Item 1A, “Risk Factors” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023. For a complete discussion of the Company’s risk factors, refer to Item 1A, “Risk Factors” of the Company’s Annual Report on Form 10-K for the year ended December 31, 2023 and the following additional risk factors relating to the Merger with Noble, the Merger Agreement, the transactions contemplated by the Merger Agreement and the Company’s related special meeting of stockholders (or, collectively, the transactions):
Failure to complete the transactions in a timely manner or at all could have adverse effects on the market value, trading price and/or the future business results and financial condition of the Company.
If the transactions are not completed, the ongoing business, financial condition, financial results and stock price of the Company may be adversely affected. Without realizing any of the benefits of having completed the transactions, we may be subject to a number of risks, including the following:
The materialization of any of these risks could adversely impact our ongoing business, financial condition, financial results and the price of our common stock. Similarly, delays in the completion of the transactions could, among other things, result in additional transaction costs, loss of revenue or other negative effects associated with uncertainty about completion of the transactions.
We are subject to business uncertainties and contractual restrictions while the proposed transactions are pending, which could adversely affect our business and operations.
36
In connection with the pendency of the transactions, it is possible that some customers, suppliers and other persons with whom we or Noble have a business relationship may delay or defer certain business decisions or might decide to seek to terminate, change or renegotiate their relationships with us or Noble as a result of the pendency of the transactions. In addition, the Merger Agreement restricts us and Noble, without the other’s consent, from making certain acquisitions and taking other specified actions until the transactions close or the Merger Agreement terminates. These restrictions may prevent us or Noble from pursuing otherwise attractive business opportunities and making other changes to our and their businesses before completion of the transactions or termination of the Merger Agreement.
Uncertainties associated with the transactions may cause a loss of management personnel and other key employees, and the Company and Noble may be unable to attract or retain management personnel and other key employees during the pendency of the transactions.
The Company and Noble are dependent on the experience and industry knowledge of their respective management personnel and other key employees to execute their business plans. The success of Noble after the completion of the transactions will depend in part upon the ability of Noble and the Company to attract, motivate and retain key management personnel and other key employees. In connection with the pending transactions, our and Noble’s current and prospective employees may experience uncertainty about their future roles with Noble following completion of the transactions, which may materially adversely affect our and Noble’s ability to attract, motivate and retain management personnel and other key employees during the pendency of the transactions. Furthermore, we and Noble may incur costs in our respective efforts to retain management personnel and other key employees prior to and after the completion of the transactions. Key employees may depart because of issues relating to the uncertainty and difficulty of integration or a desire not to remain with Noble following completion of the transactions. Accordingly, no assurance can be given that we and Noble will be able to retain management personnel and other key employees to the same extent that we and Noble have been able to in the past.
The combined company may not achieve the intended benefits and the transactions may disrupt Noble’s current plans or operations.
There can be no assurance that Noble will be able to successfully integrate our assets or otherwise realize the expected benefits of the transactions (including annual pre-tax cost synergies). Difficulties in integrating the Company into Noble may result in Noble performing differently than expected, in operational challenges or in the failure to realize anticipated synergies and efficiencies in the expected time frame or at all, including annual pre-tax cost synergies of approximately $100 million, in which case the transactions may not be accretive to earnings per share, may not improve Noble’s balance sheet position, may not enhance Noble’s ability to deliver and may not generate additional free cash flow. The integration of the two companies may result in material challenges, including the diversion of management’s attention from ongoing business concerns; retaining key management and other employees; retaining or attracting business and operational relationships; the possibility of faulty assumptions underlying expectations regarding the integration process and associated expenses; consolidating corporate and administrative infrastructures and eliminating duplicative operations; coordinating geographically separate organizations; unanticipated issues in integrating information technology, communications and other systems; as well as potential unknown liabilities, unforeseen expenses relating to integration, or delays associated with the acquisition.
Potential litigation against Noble and the Company could result in substantial costs, an injunction preventing the completion of the transactions and/or a judgment resulting in the payment of damages.
Securities class action lawsuits and derivative lawsuits are often brought against public companies that have entered into merger agreements. Even if such a lawsuit is unsuccessful, defending against these claims can result in substantial costs. An adverse judgment could result in monetary damages, which could have a negative impact on our liquidity and financial condition.
Stockholders of Diamond Offshore may file lawsuits against Diamond Offshore and/or the directors and officers of the Company in connection with the transactions. These lawsuits could prevent or delay the completion of the transactions and result in significant costs to us, including any costs associated with the indemnification of our directors and officers. There can be no assurance that any of the defendants will be successful in the outcome of any potential lawsuits.
Additionally, if a plaintiff is successful in obtaining an injunction prohibiting completion of the transactions, then that injunction may delay or prevent the transactions from being completed, or from being completed within the expected time frame, which may adversely affect our business, financial position and results of operations.
37
The Merger Agreement contains provisions that limit our ability to pursue alternatives to the transactions, which could discourage a potential competing acquirer from making a favorable alternative proposal.
The Merger Agreement contains certain provisions that restrict our ability to initiate, solicit, knowingly encourage or knowingly facilitate or, subject to certain exceptions, engage in, discussions or negotiations with respect to, or, subject to certain exceptions, approve or recommend, any alternative proposal. Further, even if the Diamond Offshore board withdraws or qualifies its recommendation with respect to the adoption of the Merger Agreement, unless the Merger Agreement has been terminated in accordance with its terms, we will still be required to hold the special meeting for the purpose of obtaining the Diamond Offshore stockholder approval.
The transactions are subject to conditions, some or all of which may not be satisfied or completed on a timely basis, or at all. The Merger Agreement may be terminated in accordance with its terms if such conditions are not completed.
The completion of the transactions is subject to a number of conditions, including, among others, (i) the receipt of the Diamond Offshore stockholder approval, (ii) the receipt of any regulatory approvals required to consummate the First Merger, (iii) the absence of any order or law prohibiting consummation of the transactions, (iv) the absence of any material adverse effect on Diamond Offshore or Noble since the date of the Merger Agreement, (v) the effectiveness of the registration statement of which the proxy statement for the Company’s special meeting of stockholders forms a part and (vi) the authorization for listing on the New York Stock Exchange of the Noble ordinary shares to be issued in connection with the First Merger. These conditions make the completion and timing of the transactions uncertain.
In addition, if the transactions are not completed by June 9, 2025, or, in certain instances, on or before June 9, 2026, either Noble or Diamond Offshore may choose not to proceed with the transactions by terminating the Merger Agreement, and the parties can mutually decide to terminate the Merger Agreement at any time. Further, either Noble or Diamond Offshore may elect to terminate the Merger Agreement in certain other circumstances.
The Exchange Ratio is fixed and will not be adjusted in the event of fluctuations in the market price of Noble ordinary shares or shares of Diamond Offshore common stock.
Upon completion of the First Merger, each share of Diamond Offshore common stock will be converted into the right to receive $5.65 in cash without interest, and 0.2316 of validly issued, fully paid and non-assessable Noble ordinary shares. This Exchange Ratio is fixed in the Merger Agreement and will not be adjusted for changes in the market price of either Noble ordinary shares or Diamond Offshore common stock between the date of the Merger Agreement and the First Merger Effective Time. Due to the fixed Exchange Ratio, fluctuations in the price of Noble ordinary shares will drive corresponding changes in the value of the Merger Consideration payable to each Diamond Offshore stockholder. As a result, changes in the price of Noble ordinary shares prior to the completion of the First Merger will affect the market value that Diamond Offshore stockholders will become entitled to receive at the First Merger Effective Time. Changes in the price of Noble ordinary shares or Diamond Offshore common stock could result from changes in the business, operations or prospects of Noble or Diamond Offshore prior to or following the completion of the First Merger, regulatory considerations, general market and economic conditions and other factors both within and beyond the control of Noble or Diamond Offshore, including, among other things, a decline in the price of oil or gas, a reduction in demand for oil and gas products, increased regulation of drilling and production and a number of other factors beyond the companies’ control.
The transactions are subject to regulatory approvals, and regulatory authorities may impose conditions that could delay, prevent or increase the costs associated with completion of the transactions.
The completion of the transactions is subject to a number of conditions, including, among others, (i) the receipt of Diamond Offshore stockholder approval, (ii) the receipt of any regulatory approvals required to consummate the First Merger, (iii) the absence of any order or law prohibiting consummation of the transactions, (iv) the absence of any material adverse effect on the Company or Noble since the date of the Merger Agreement, (v) the effectiveness of the registration statement of which this proxy statement/prospectus forms a part and (vi) the authorization for listing on the NYSE of the Noble ordinary shares to be issued in connection with the First Merger. These conditions make the completion and timing of the transactions uncertain.
In addition, if the transactions are not completed by June 9, 2025, or, in certain instances, on or before June 9, 2026, either Noble or the Company may choose not to proceed with the transactions by terminating the Merger Agreement, and the parties can mutually decide to terminate the Merger Agreement at any time. Further, either Noble or the Company may elect to terminate the Merger Agreement in certain other circumstances.
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The Noble ordinary shares to be received by Diamond Offshore stockholders upon completion of the First Merger will have different rights from shares of Diamond Offshore common stock due to the difference between Delaware law and English law.
Upon completion of the First Merger, Diamond Offshore stockholders will no longer be stockholders of Diamond Offshore but will instead become shareholders of Noble, and their rights as Noble shareholders will be governed by English law, including the Companies Act 2006 of the United Kingdom and, the terms of Noble’s amended and restated memorandum and articles of association (“or Noble’s articles”). The terms of Noble’s articles are in some respects materially different than the terms of the Fourth Amended and Restated Certificate of Incorporation of Diamond Offshore and the Third Amended and Restated Bylaws of Diamond Offshore, which currently govern the rights of Diamond Offshore stockholders.
It may be difficult for shareholders of Noble (including former Diamond Offshore stockholders that become shareholders of Noble upon completion of the First Merger) to effect service of process on Noble or its directors or officers in the United States or to enforce in the United States judgments obtained in U.S. courts against Noble or its officers or directors based on the civil liability provisions of the U.S. securities laws or otherwise. Even if a shareholder of Noble is successful in bringing an action of this kind, English law (or any other applicable law) may render such shareholder of Noble unable to enforce a judgment against Noble’s assets or the assets of its directors and executive officers. In addition, it is doubtful whether English courts would enforce certain civil liabilities under U.S. securities laws in original actions or judgments of U.S. courts based upon these civil liability provisions. In addition, awards of punitive damages in actions brought in the United States or elsewhere may be unenforceable in the United Kingdom. An award for monetary damages under the U.S. securities laws would likely be considered punitive if it does not seek to compensate the claimant for loss or damage suffered and is intended to punish the defendant. The enforceability of any judgment in the United Kingdom will depend on the particular facts of the case as well as the laws and treaties in effect at the time. The United States and the United Kingdom do not currently have a treaty providing for recognition and enforcement of judgments (other than arbitration awards) in civil and commercial matters. As a result of the above, holders of Noble ordinary shares may have more difficulty in protecting their interest through actions against Noble’s management, directors or major shareholders than they would as stockholders of Diamond Offshore common stock.
ITEM 5. Other Information.
Items 5(a) and 5(b) are not applicable.
(c) During the quarter ended June 30, 2024, no director or officer
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ITEM 6. Exhibits.
Exhibit No. |
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Description of Exhibit |
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2.1* |
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3.1 |
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3.2 |
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31.1** |
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Rule 13a-14(a) Certification of the Chief Executive Officer. |
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31.2** |
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Rule 13a-14(a) Certification of the Chief Financial Officer. |
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32.1** |
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Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer. |
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101.INS** |
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Inline 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. |
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101.SCH** |
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Inline XBRL Taxonomy Extension Schema With Embedded Linkbase Document. |
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104** |
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The cover page of our Quarterly Report on Form 10-Q for the quarter ended June 30, 2024, formatted in Inline XBRL (included with the Exhibit 101 attachments). |
* Schedules have been omitted pursuant to Item 601(a)(5) of Regulation S-K.
**Filed or furnished herewith.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
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DIAMOND OFFSHORE DRILLING, INC. |
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(Registrant) |
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Date August 7, 2024 |
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By: |
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/s/ Dominic A. Savarino |
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Dominic A. Savarino |
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Senior Vice President and Chief Financial Officer |
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