UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2015
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE |
SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission file number 1-13926
DIAMOND OFFSHORE DRILLING, INC.
(Exact name of registrant as specified in its charter)
Delaware | 76-0321760 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
15415 Katy Freeway
Houston, Texas
77094
(Address of principal executive offices)
(Zip Code)
(281) 492-5300
(Registrants telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of large accelerated filer, accelerated filer, and smaller reporting company in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ (Do not check if a smaller reporting company) | Smaller reporting company | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Indicate the number of shares outstanding of each of the issuers classes of common stock, as of the latest practicable date.
As of October 26, 2015 Common stock, $0.01 par value per share 137,158,706 shares
DIAMOND OFFSHORE DRILLING, INC.
TABLE OF CONTENTS FOR FORM 10-Q
QUARTER ENDED SEPTEMBER 30, 2015
PAGE NO. | ||||||||
COVER PAGE |
1 | |||||||
TABLE OF CONTENTS |
2 | |||||||
3 |
42 |
ITEM 6. | Exhibits | 42 | ||||||
42 | ||||||||
43 |
2
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
(Unaudited)
(In thousands, except share and per share data)
September 30, 2015 |
December 31, 2014 |
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ASSETS |
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Current assets: |
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Cash and cash equivalents |
$ | 141,131 | $ | 233,623 | ||||
Marketable securities |
13,621 | 16,033 | ||||||
Accounts receivable, net of allowance for bad debts |
515,754 | 463,862 | ||||||
Prepaid expenses and other current assets |
163,871 | 185,541 | ||||||
Assets held for sale |
6,700 | | ||||||
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Total current assets |
841,077 | 899,059 | ||||||
Drilling and other property and equipment, net of accumulated depreciation |
6,888,248 | 6,945,953 | ||||||
Other assets |
121,171 | 176,277 | ||||||
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Total assets |
$ | 7,850,496 | $ | 8,021,289 | ||||
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
$ | 78,571 | $ | 138,444 | ||||
Accrued liabilities |
285,304 | 426,592 | ||||||
Taxes payable |
33,546 | 41,648 | ||||||
Short-term borrowings |
492,996 | | ||||||
Current portion of long-term debt |
| 249,962 | ||||||
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Total current liabilities |
890,417 | 856,646 | ||||||
Long-term debt |
1,994,710 | 1,994,526 | ||||||
Deferred tax liability |
417,621 | 530,394 | ||||||
Other liabilities |
171,595 | 188,160 | ||||||
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Total liabilities |
3,474,343 | 3,569,726 | ||||||
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Commitments and contingencies (Note 11) |
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Stockholders equity: |
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Preferred stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding) |
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Common stock (par value $0.01, 500,000,000 shares authorized; 143,978,877 shares issued and 137,158,706 shares outstanding at September 30, 2015; 143,960,260 shares issued and 137,147,899 shares outstanding at December 31, 2014) |
1,440 | 1,440 | ||||||
Additional paid-in capital |
1,998,281 | 1,993,898 | ||||||
Retained earnings |
2,581,664 | 2,661,999 | ||||||
Accumulated other comprehensive gain (loss) |
(2,827 | ) | (3,605 | ) | ||||
Treasury stock, at cost (6,820,171 and 6,812,361 shares of common stock at September 30, 2015 and December 31, 2014, respectively) |
(202,405 | ) | (202,169 | ) | ||||
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Total stockholders equity |
4,376,153 | 4,451,563 | ||||||
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Total liabilities and stockholders equity |
$ | 7,850,496 | $ | 8,021,289 | ||||
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The accompanying notes are an integral part of the consolidated financial statements.
3
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share data)
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
Revenues: |
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Contract drilling |
$ | 599,036 | $ | 727,888 | $ | 1,816,055 | $ | 2,062,750 | ||||||||
Revenues related to reimbursable expenses |
10,706 | 9,794 | 47,775 | 76,600 | ||||||||||||
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Total revenues |
609,742 | 737,682 | 1,863,830 | 2,139,350 | ||||||||||||
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Operating expenses: |
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Contract drilling, excluding depreciation |
277,944 | 399,802 | 971,471 | 1,164,968 | ||||||||||||
Reimbursable expenses |
10,476 | 9,437 | 46,904 | 75,393 | ||||||||||||
Depreciation |
118,086 | 108,854 | 378,714 | 324,771 | ||||||||||||
General and administrative |
16,888 | 18,604 | 50,888 | 61,909 | ||||||||||||
Impairment of assets |
2,546 | 109,462 | 361,074 | 109,462 | ||||||||||||
Restructuring and separation costs |
1,574 | | 8,735 | | ||||||||||||
Loss (gain) on disposition of assets |
794 | 1,107 | 19 | (7,612 | ) | |||||||||||
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Total operating expenses |
428,308 | 647,266 | 1,817,805 | 1,728,891 | ||||||||||||
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Operating income |
181,434 | 90,416 | 46,025 | 410,459 | ||||||||||||
Other income (expense): |
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Interest income |
629 | 86 | 1,796 | 644 | ||||||||||||
Interest expense, net of amounts capitalized |
(21,350 | ) | (9,378 | ) | (70,800 | ) | (46,056 | ) | ||||||||
Foreign currency transaction gain (loss) |
(1,163 | ) | 425 | 954 | (3,724 | ) | ||||||||||
Other, net |
217 | 90 | 702 | 598 | ||||||||||||
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Income (loss) before income tax (expense) benefit |
159,767 | 81,639 | (21,323 | ) | 361,921 | |||||||||||
Income tax expense |
(23,345 | ) | (28,994 | ) | (7,578 | ) | (73,753 | ) | ||||||||
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Net income (loss) |
$ | 136,422 | $ | 52,645 | $ | (28,901 | ) | $ | 288,168 | |||||||
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Earnings (loss) per share, Basic and Diluted |
$ | 0.99 | $ | 0.38 | $ | (0.21 | ) | $ | 2.09 | |||||||
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Weighted-average shares outstanding: |
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Shares of common stock |
137,159 | 137,146 | 137,156 | 137,582 | ||||||||||||
Dilutive potential shares of common stock |
44 | 1 | | 3 | ||||||||||||
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Total weighted-average shares outstanding |
137,203 | 137,147 | 137,156 | 137,585 | ||||||||||||
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Cash dividends declared per share of common stock |
$ | 0.125 | $ | 0.875 | $ | 0.375 | $ | 2.625 | ||||||||
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The accompanying notes are an integral part of the consolidated financial statements.
4
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(Unaudited)
(In thousands)
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
Net income (loss) |
$ | 136,422 | $ | 52,645 | $ | (28,901 | ) | $ | 288,168 | |||||||
Other comprehensive (losses) gains, net of tax: |
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Derivative financial instruments: |
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Unrealized holding (loss) gain |
(40 | ) | (4,229 | ) | (1,574 | ) | 1,492 | |||||||||
Reclassification adjustment for loss (gain) included in net income |
268 | (1,518 | ) | 5,085 | (4,055 | ) | ||||||||||
Investments in marketable securities: |
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Unrealized holding (loss) gain |
(2,440 | ) | (3 | ) | (2,733 | ) | 36 | |||||||||
Reclassification adjustment for gain included in net income |
| (1 | ) | | (27 | ) | ||||||||||
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Total other comprehensive (loss) gain |
(2,212 | ) | (5,751 | ) | 778 | (2,554 | ) | |||||||||
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Comprehensive income (loss) |
$ | 134,210 | $ | 46,894 | $ | (28,123 | ) | $ | 285,614 | |||||||
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The accompanying notes are an integral part of the consolidated financial statements.
5
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
Nine Months Ended September 30, |
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2015 | 2014 | |||||||
Operating activities: |
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Net (loss) income |
$ | (28,901 | ) | $ | 288,168 | |||
Adjustments to reconcile net income to net cash provided by operating activities: |
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Depreciation |
378,714 | 324,771 | ||||||
Loss on impairment of assets |
361,074 | 109,462 | ||||||
Loss (gain) on disposition of assets |
19 | (7,612 | ) | |||||
Loss (gain) on foreign currency forward exchange contracts |
8,364 | (6,736 | ) | |||||
Deferred tax provision |
(114,662 | ) | (10,290 | ) | ||||
Stock-based compensation expense |
3,503 | 2,559 | ||||||
Deferred income, net |
(24,735 | ) | 49,013 | |||||
Deferred expenses, net |
(42,261 | ) | (79,907 | ) | ||||
Long-term employee remuneration programs |
(1,265 | ) | (4,799 | ) | ||||
Other assets, noncurrent |
774 | 197 | ||||||
Other liabilities, noncurrent |
(3,844 | ) | 672 | |||||
(Payments for) proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges |
(8,364 | ) | 6,736 | |||||
Bank deposits denominated in nonconvertible currencies |
992 | 6,009 | ||||||
Other |
1,271 | 1,379 | ||||||
Changes in operating assets and liabilities: |
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Accounts receivable |
(33,360 | ) | (48,258 | ) | ||||
Prepaid expenses and other current assets |
10,979 | (10,686 | ) | |||||
Accounts payable and accrued liabilities |
(112,206 | ) | 40,326 | |||||
Taxes payable |
70,585 | 21,832 | ||||||
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Net cash provided by operating activities |
466,677 | 682,836 | ||||||
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Investing activities: |
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Capital expenditures (including rig construction) |
(758,342 | ) | (1,024,325 | ) | ||||
Proceeds from disposition of assets, net of disposal costs |
8,442 | 16,756 | ||||||
Proceeds from sale and maturities of marketable securities |
34 | 7,125,045 | ||||||
Purchases of marketable securities |
| (5,974,861 | ) | |||||
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Net cash provided by (used in) investing activities |
(749,866 | ) | 142,615 | |||||
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Financing activities: |
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Repayment of long-term debt |
(250,000 | ) | (250,000 | ) | ||||
Payment of dividends |
(52,287 | ) | (365,290 | ) | ||||
Net proceeds from short-term borrowings |
492,996 | | ||||||
Purchase of treasury stock |
| (87,756 | ) | |||||
Other |
(12 | ) | (593 | ) | ||||
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Net cash provided by (used in) financing activities |
190,697 | (703,639 | ) | |||||
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Net change in cash and cash equivalents |
(92,492 | ) | 121,812 | |||||
Cash and cash equivalents, beginning of period |
233,623 | 347,011 | ||||||
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Cash and cash equivalents, end of period |
$ | 141,131 | $ | 468,823 | ||||
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The accompanying notes are an integral part of the consolidated financial statements.
6
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS
1. General Information
The unaudited consolidated financial statements of Diamond Offshore Drilling, Inc. and subsidiaries, which we refer to as Diamond Offshore, we, us or our, should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2014 (File No. 1-13926).
As of October 26, 2015, Loews Corporation owned 53.3 % of the outstanding shares of our common stock.
Interim Financial Information
The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the U.S., or GAAP, for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X of the Securities and Exchange Commission. Accordingly, pursuant to such rules and regulations, they do not include all disclosures required by GAAP for complete financial statements. The consolidated financial information has not been audited but, in the opinion of management, includes all adjustments (consisting only of normal recurring accruals) necessary for a fair presentation of the consolidated balance sheets, statements of operations, statements of comprehensive income and statements of cash flows at the dates and for the periods indicated. Results of operations for interim periods are not necessarily indicative of results of operations for the respective full years.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from those estimated.
Cash and Cash Equivalents
We consider short-term, highly liquid investments that have an original maturity of three months or less and deposits in money market mutual funds that are readily convertible into cash to be cash equivalents.
The effect of exchange rate changes on cash balances held in foreign currencies was not material for each of the three-month and nine-month periods ended September 30, 2015 and 2014.
Marketable Securities
We classify our investments in marketable securities as available for sale and they are stated at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses, net of taxes, are reported in our Consolidated Balance Sheets in Accumulated other comprehensive gain (loss), or AOCGL, until realized. The cost of debt securities is adjusted for amortization of premiums and accretion of discounts to maturity and such adjustments are included in our Consolidated Statements of Operations in Interest income. The sale and purchase of securities are recorded on the date of the trade. The cost of debt securities sold is based on the specific identification method. Realized gains or losses, as well as any declines in value that are judged to be other than temporary, are reported in our Consolidated Statements of Operations in Other income (expense) Other, net. See Note 6.
Derivative Financial Instruments
Our derivative financial instruments consist primarily of foreign currency forward exchange, or FOREX, contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative contract is stated in the balance sheet at its fair value with gains and losses reflected in the income statement except that, to the extent the derivative qualifies for and is designated as an accounting hedge, the gains and losses are reflected in income in the same period as offsetting gains and losses on the qualifying hedged positions. Designated hedges are expected to be highly effective, and therefore, adjustments to record the carrying value of the effective portion of our derivative financial instruments to their fair value are recorded as a component of AOCGL in our Consolidated
7
Balance Sheets. The effective portion of the cash flow hedge will remain in AOCGL until it is reclassified into earnings in the period or periods during which the hedged transaction affects earnings or it is determined that the hedged transaction will not occur. We report such realized gains and losses as a component of Contract drilling, excluding depreciation expense in our Consolidated Statements of Operations to offset the impact of foreign currency fluctuations in our expenditures in local foreign currencies in the countries in which we operate. See Note 12.
Adjustments to record the carrying value of the ineffective portion of our derivative financial instruments to fair value and realized gains or losses upon settlement of derivative contracts not designated as cash flow hedges are reported as Foreign currency transaction gain (loss) in our Consolidated Statements of Operations. See Notes 7 and 8.
Drilling and Other Property and Equipment
We carry our drilling and other property and equipment at cost. Maintenance and routine repairs are charged to income currently while replacements and betterments, which upgrade or increase the functionality of our existing equipment and that significantly extend the useful life of an existing asset, are capitalized. Significant judgments, assumptions and estimates may be required in determining whether or not such replacements and betterments meet the criteria for capitalization and in determining useful lives and salvage values of such assets. Changes in these judgments, assumptions and estimates could produce results that differ from those reported. Historically, the amount of capital additions requiring significant judgments, assumptions or estimates has not been significant. During the nine months ended September 30, 2015 and the year ended December 31, 2014, we capitalized $217.8 million and $546.0 million, respectively, in replacements and betterments of our drilling fleet, resulting from numerous projects ranging from $25,000 to $215 million per project.
Costs incurred for major rig upgrades and/or the construction of rigs are accumulated in construction work-in-progress, with no depreciation recorded on the additions, until the month the upgrade or newbuild is completed and the rig is ready for its intended use. Upon retirement or sale of a rig, the cost and related accumulated depreciation are removed from the respective accounts and any gains or losses are included in our results of operations as Loss (gain) on disposition of assets. Depreciation is recognized up to applicable salvage values by applying the straight-line method over the remaining estimated useful lives from the year the asset is placed in service. Drilling rigs and equipment are depreciated over their estimated useful lives ranging from three to 30 years.
Impairment of Long-Lived Assets
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near term, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize an undiscounted probability-weighted cash flow analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
| dayrate by rig; |
| utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates); |
| the per day operating cost for each rig if active, warm stacked or cold stacked; |
| the estimated annual cost for rig replacements and/or enhancement programs; |
| the estimated maintenance, inspection or other costs associated with a rig returning to work; |
| salvage value for each rig; and |
| estimated proceeds that may be received on disposition of each rig. |
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a projected probability- weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability.
The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rigs age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment.
8
Managements assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Managements assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and managements expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different. See Note 2.
Capitalized Interest
We capitalize interest cost for qualifying construction and upgrade projects. See Note 9. A reconciliation of our total interest cost to Interest expense, net of amounts capitalized as reported in our Consolidated Statements of Operations is as follows:
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
Total interest cost, including amortization of debt issuance costs |
$ | 23,830 | $ | 25,707 | $ | 84,254 | $ | 93,600 | ||||||||
Capitalized interest |
(2,480 | ) | (16,329 | ) | (13,454 | ) | (47,544 | ) | ||||||||
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Total interest expense as reported |
$ | 21,350 | $ | 9,378 | $ | 70,800 | $ | 46,056 | ||||||||
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Foreign Currency
Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses are reported as Foreign currency transaction gain (loss) in our Consolidated Statements of Operations and include, when applicable, unrealized gains and losses to record the carrying value of our FOREX contracts not designated as accounting hedges, as well as realized gains and losses from the settlement of such contracts. For the three-month and nine-month periods ended September 30, 2015, we recognized net foreign currency transaction gains (losses) of $(1.2) million and $1.0 million, respectively. For the three-month and nine-month periods ended September 30, 2014, we recognized net foreign currency transaction gains (losses) of $0.4 million and $(3.7) million, respectively. See Note 7.
Revenue Recognition
We recognize revenue from dayrate drilling contracts as services are performed. In connection with such drilling contracts, we may receive fees (on either a lump-sum or dayrate basis) for the mobilization of equipment. We earn these fees as services are performed over the initial term of the related drilling contracts. We defer mobilization fees received, as well as direct and incremental mobilization costs incurred, and amortize each on a straight-line basis, over the term of the related drilling contracts (which is the period we estimate to be benefited from the mobilization activity). Straight-line amortization of mobilization revenues and related costs over the term of the related drilling contracts (which generally range from two to 60 months) is consistent with the timing of net cash flows generated from the actual drilling services performed. Absent a contract, mobilization costs are recognized currently.
Some of our drilling contracts require downtime before the start of the contract to prepare the rig to meet customer requirements. At times, we may be compensated by the customer for such work (on either a lump-sum or dayrate basis). These fees are generally earned as services are performed over the initial term of the related drilling contracts. We defer contract preparation fees received as well as direct and incremental costs associated with the contract preparation activities and amortize each, on a straight-line basis, over the term of the related drilling contracts (which we estimate to be benefited from the contract preparation activity).
9
From time to time, we may receive fees from our customers for capital improvements to our rigs (on either a lump-sum or dayrate basis). We defer such fees received in Accrued liabilities and Other liabilities in our Consolidated Balance Sheets and recognize these fees into income on a straight-line basis over the period of the related drilling contract. We capitalize the costs of such capital improvements and depreciate them over the estimated useful life of the improvement.
We record reimbursements received for the purchase of supplies, equipment, personnel services and other services provided at the request of our customers in accordance with a contract or agreement, for the gross amount billed to the customer, as Revenues related to reimbursable expenses in our Consolidated Statements of Operations.
Recent Accounting Pronouncements
In July 2015, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2015-11, Inventory (Topic 330): Simplifying the Measurement of Inventory, or ASU 2015-11, which requires an entity to measure inventory within the scope of the ASU at the lower of cost and net realizable value. The amendments in ASU 2015-11 are effective for fiscal years beginning after December 15, 2016, including interim periods within that reporting period. Earlier adoption is permitted. We are currently evaluating the provisions of ASU 2015-11 and have not yet determined its impact on our financial position, results of operations or cash flows.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), or ASU 2014-09. The new standard supersedes the industry-specific standards that currently exist under GAAP and provides a framework to address revenue recognition issues comprehensively for all contracts with customers regardless of industry-specific or transaction-specific fact patterns. Under the new guidance, companies recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. ASU 2014-09 also provides for additional disclosure requirements. In July 2015, the FASB issued ASU No. 2015-14, which deferred the effective date of ASU 2014-09. The guidance in ASU 2014-09 is now effective for annual reporting periods beginning after December 15, 2017, including interim periods within that reporting period, and may be adopted using a retrospective or modified retrospective approach. Early adoption is permitted. We are currently evaluating the provisions of ASU 2014-09 and have not yet determined its impact on our financial position, results of operations or cash flows.
2. Asset Impairments
During the first quarter of 2015, in response to pending regulatory requirements in the U.S. Gulf of Mexico, as well as the continued deterioration of the market fundamentals in the oil and gas industry, including the dramatic decline in oil prices, significant cutbacks in customer capital spending plans and contract cancelations by customers, we evaluated all drilling rigs in our fleet with indications that their carrying amounts may not be recoverable (e.g., cold stacked or expected to be cold stacked in the near term; see Note 1). Using the undiscounted projected probability-weighted cash flow analysis described in Note 1, we determined that the carrying values of seven of our mid-water semisubmersibles, as well as our older, 7,875-foot water depth rated drillship were impaired at March 31, 2015.
We determined the fair value of five of the rigs in the impairment group using a market approach, which utilized the most recent contracted sales price for another of our previously impaired mid-water semisubmersible rigs. We determined the fair value of the three remaining rigs (which were under contract with a customer at that time) using an income approach, which utilized significant unobservable inputs, including assumptions related to estimated dayrate revenue, rig utilization and anticipated costs for the remainder of the current contract, as well as estimated proceeds that may be received on disposition of each rig. We consider each of these methodologies to be Level 3 fair value measurements due to the significant level of estimation involved and the lack of transparency as to the inputs used.
During the third quarter of 2015, we evaluated 13 drilling rigs with indications that their carrying amounts may not be recoverable and that were not previously impaired, including four additional rigs that did not have prior indicators of impairment as noted above, and determined that further impairment of our fleet had not occurred. However, after receipt of offers in October 2015 to sell three drilling rigs, consisting of one semisubmersible rig and our 7,875-foot water depth rated drillship, both of which were previously impaired, and one cold-stacked jack-up rig, we recorded an aggregate impairment loss of $2.6 million during the third quarter of 2015 to write down the carrying value of
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each of these rigs to their expected selling price, which we also consider to be Level 3 fair value measurements. The sale of these rigs is currently being negotiated. As a result of our valuations, we recognized impairment losses aggregating $361.1 million for the first nine months of 2015.
Of the rigs impaired during 2015, four semisubmersible rigs have been sold for scrap and another three rigs are currently cold stacked. The two remaining rigs in the impairment group are under contract with customers and are expected to be sold for scrap at the end of their respective contracts. The aggregate fair value of the rigs in the impairment group was $8.7 million at September 30, 2015, of which $6.7 million is reported as Asset held for sale and $2.0 million is reported in Drilling and other property and equipment, net of accumulated depreciation in our Consolidated Balance Sheets. See Notes 8 and 9.
During the three-month and nine-month periods ended September 30, 2014, we recognized an impairment loss of $109.5 million related to six mid-water semisubmersible rigs, for which we had initiated a plan to retire and scrap. All of these rigs were subsequently sold for scrap.
Managements assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation. The use of different assumptions could produce results that differ from those reported. The actual amount realized upon disposition of our drilling rigs may vary if, or when, such rigs are sold.
3. Supplemental Financial Information
Consolidated Balance Sheets Information
Accounts receivable, net of allowance for bad debts, consist of the following:
September 30, | December 31, | |||||||
2015 | 2014 | |||||||
(In thousands) | ||||||||
Trade receivables |
$ | 479,408 | $ | 437,017 | ||||
Income tax receivable |
18,408 | | ||||||
Value added tax receivables |
17,604 | 24,853 | ||||||
Amounts held in escrow |
4,871 | 6,450 | ||||||
Related party receivables |
107 | 339 | ||||||
Other |
1,080 | 927 | ||||||
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521,478 | 469,586 | |||||||
Allowance for bad debts |
(5,724 | ) | (5,724 | ) | ||||
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Total |
$ | 515,754 | $ | 463,862 | ||||
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Prepaid expenses and other current assets consist of the following:
September 30, | December 31, | |||||||
2015 | 2014 | |||||||
(In thousands) | ||||||||
Rig spare parts and supplies |
$ | 49,003 | $ | 56,315 | ||||
Deferred mobilization costs |
71,242 | 53,206 | ||||||
Prepaid insurance |
6,701 | 12,163 | ||||||
Deferred tax assets |
15,612 | 15,612 | ||||||
Prepaid taxes |
16,928 | 44,085 | ||||||
Other |
4,385 | 4,160 | ||||||
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Total |
$ | 163,871 | $ | 185,541 | ||||
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Accrued liabilities consist of the following:
September 30, | December 31, | |||||||
2015 | 2014 | |||||||
(In thousands) | ||||||||
Rig operating expenses |
$ | 74,506 | $ | 85,897 | ||||
Payroll and benefits |
63,950 | 131,664 | ||||||
Deferred revenue |
47,135 | 63,209 | ||||||
Accrued capital project/upgrade costs |
42,325 | 103,123 | ||||||
Interest payable |
44,130 | 18,365 | ||||||
Personal injury and other claims |
8,565 | 8,570 | ||||||
FOREX contracts |
| 5,439 | ||||||
Other |
4,693 | 10,325 | ||||||
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Total |
$ | 285,304 | $ | 426,592 | ||||
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Consolidated Statements of Cash Flows Information
Noncash investing activities excluded from the Consolidated Statements of Cash Flows and other supplemental cash flow information is as follows:
Nine Months Ended September 30, |
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2015 | 2014 | |||||||
(In thousands) | ||||||||
Accrued but unpaid capital expenditures at period end |
$ | 42,325 | $ | 102,340 | ||||
Common stock withheld for payroll tax obligations (1) |
236 | | ||||||
Cash interest payments (2) |
57,625 | 76,092 | ||||||
Cash income taxes paid, net of (refunds): |
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U.S. federal |
(3,344 | ) | | |||||
Foreign |
53,292 | 59,299 | ||||||
State |
150 | 149 |
(1) | Represents the cost of 7,810 shares of common stock withheld to satisfy the payroll tax obligation incurred as a result of the vesting of restricted stock units in the first quarter of 2015. This cost is presented as a deduction from stockholders equity in Treasury stock in our Consolidated Balance Sheets at September 30, 2015. |
(2) | Interest payments, net of amounts capitalized, were $48.7 million and $38.9 million for the nine months ended September 30, 2015 and 2014, respectively. |
4. Stock-Based Compensation
In April 2015, we granted an aggregate of 311,145 restricted stock units, or RSUs, to employees under our Equity Incentive Compensation Plan, or Equity Plan, collectively referred to as the 2015 RSUs. RSUs are contractual rights to receive shares of our common stock in the future if the applicable vesting conditions are met. Our 2015 RSUs included both performance-vesting and time-vesting RSUs. Under the terms of the 2015 awards, the performance-vesting 2015 RSUs vest upon achievement of certain performance goals as set forth in the individual award agreements over the performance period from January 1, 2015 to December 31, 2017, and the shares of our common stock to be received upon the vesting of the performance-vesting RSUs will be delivered no later than March 15, 2018. 50% of the time-vesting 2015 RSUs will vest on April 1, 2017 and 50% will vest on April 1, 2018, conditioned upon continued employment through the applicable vesting date.
2015 RSUs awarded under the Equity Plan are summarized as follows:
Award Type |
Number of RSUs |
Weighted Average Fair Value per RSU |
||||||
Performance-vesting (dividend entitled) |
110,791 | $ | 26.69 | |||||
Performance-vesting |
56,162 | $ | 25.21 | |||||
Time-vesting |
144,192 | $ | 25.21 |
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We recognized compensation expense of $0.8 million and $1.7 million for the three-month and nine-month periods ended September 30, 2015, respectively, in connection with RSUs awarded under our Equity Plan. In connection with RSUs awarded in 2014, we recognized $0.2 million and $0.5 million in compensation expense for the three-month and nine-month periods ended September 30, 2014, respectively.
During the nine months ended September 30, 2015, we issued an aggregate of 107,750 stock appreciation rights to our board of directors and certain employees under the Equity Plan.
5. Earnings Per Share
A reconciliation of the numerators and the denominators of our basic and diluted per-share computations follows:
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands, except per share data) | ||||||||||||||||
Net income (loss) basic and diluted numerator |
$ | 136,422 | $ | 52,645 | $ | (28,901 | ) | $ | 288,168 | |||||||
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Weighted average shares basic (denominator): |
137,159 | 137,146 | 137,156 | 137,582 | ||||||||||||
Dilutive effect of stock-based awards |
44 | 1 | | 3 | ||||||||||||
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Weighted average shares including conversions diluted (denominator) |
137,203 | 137,147 | 137,156 | 137,585 | ||||||||||||
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Earnings (loss) per share: |
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Basic |
$ | 0.99 | $ | 0.38 | $ | (0.21 | ) | $ | 2.09 | |||||||
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Diluted |
$ | 0.99 | $ | 0.38 | $ | (0.21 | ) | $ | 2.09 | |||||||
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The following table sets forth the share effects of stock-based awards excluded from our computations of diluted earnings per share, or EPS, as the inclusion of such potentially dilutive shares would have been antidilutive for the periods presented:
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
Employee and director: |
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Stock options |
23 | 37 | 29 | 32 | ||||||||||||
Stock appreciation rights |
1,521 | 1,526 | 1,561 | 1,472 | ||||||||||||
Restricted stock units |
176 | | 252 | |
6. Marketable Securities
We report our investments as current assets in our Consolidated Balance Sheets in Marketable securities, representing the investment of cash available for current operations. See Note 8.
Our investments in marketable securities are classified as available for sale and are summarized as follows:
September 30, 2015 | ||||||||||||
Amortized Cost |
Unrealized Gain (Loss) |
Market Value |
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(In thousands) | ||||||||||||
Corporate bonds |
$ | 16,359 | $ | (2,836 | ) | $ | 13,523 | |||||
Mortgage-backed securities |
94 | 4 | 98 | |||||||||
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Total |
$ | 16,453 | $ | (2,832 | ) | $ | 13,621 | |||||
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December 31, 2014 | ||||||||||||
Amortized Cost |
Unrealized Gain (Loss) |
Market Value |
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(In thousands) | ||||||||||||
Corporate bonds |
$ | 16,003 | $ | (104 | ) | $ | 15,899 | |||||
Mortgage-backed securities |
130 | 4 | 134 | |||||||||
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Total |
$ | 16,133 | $ | (100 | ) | $ | 16,033 | |||||
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Proceeds from maturities and sales of marketable securities are summarized as follows:
Three Months Ended | Nine Months Ended | |||||||||||||||
September 30, | September 30, | |||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
Proceeds from maturities |
$ | | $ | 1,325,000 | $ | | $ | 7,125,000 | ||||||||
Proceeds from sales |
11 | 12 | 34 | 45 |
Gross realized gains and losses from the sale of marketable securities for the three-month and nine-month periods ended September 30, 2015 and 2014 were not significant.
7. Derivative Financial Instruments
Foreign Currency Forward Exchange Contracts
Our international operations expose us to foreign exchange risk associated with our costs payable in foreign currencies for employee compensation, foreign income tax payments and purchases from foreign suppliers. From time to time, we may utilize FOREX contracts to manage our foreign exchange risk. Our FOREX contracts generally require us to net settle the spread between the contracted foreign currency exchange rate and the spot rate on the contract settlement date, which, for most of our contracts, is the average spot rate for the contract period.
We enter into FOREX contracts when we believe market conditions are favorable to purchase contracts for future settlement with the expectation that such contracts, when settled, will reduce our exposure to foreign currency gains and losses on future foreign currency expenditures. The amount and duration of such contracts are based on our monthly forecast of expenditures in the significant currencies in which we do business and for which there is a financial market. Historically we have entered into FOREX contracts for future delivery of Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner. These forward contracts are derivatives as defined by GAAP.
During the nine months ended September 30, 2015 and 2014, we settled FOREX contracts with aggregate notional values of approximately $91.6 million and $233.9 million, respectively, of which the entire aggregate amounts were designated as a cash flow accounting hedge. There were no FOREX contracts outstanding at September 30, 2015.
The following table presents the aggregate amount of gain or loss recognized in our Consolidated Statements of Operations related to our FOREX contracts designated as accounting hedges for the three-month and nine-month periods ended September 30, 2015 and 2014.
Three Months Ended September 30, |
Nine Months Ended September 30, |
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Location of (Loss) Gain Recognized in Income |
2015 | 2014 | 2015 | 2014 | ||||||||||||
(In thousands) | ||||||||||||||||
Contract drilling expense |
$ | (440 | ) | $ | 1,729 | $ | (8,364 | ) | $ | 6,736 |
The following table presents the fair values of our derivative FOREX contracts designated as hedging instruments at September 30, 2015 and December 31, 2014.
Balance Sheet Location |
Fair Value | Balance Sheet Location |
Fair Value | |||||||||||||||
September 30, 2015 |
December 31, 2014 |
September 30, 2015 |
December 31, 2014 |
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(In thousands) | (In thousands) | |||||||||||||||||
Prepaid expenses and other current assets |
$ | | $ | | Accrued liabilities | $ | | $ | (5,439 | ) |
The following table presents the amounts recognized in our Consolidated Balance Sheets and Consolidated Statements of Operations related to our derivative financial instruments designated as cash flow hedges for the three-month and nine-month periods ended September 30, 2015 and 2014.
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Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
FOREX contracts: |
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Amount of (loss) gain recognized in AOCGL on derivative (effective portion) |
$ | (61 | ) | $ | (6,505 | ) | $ | (2,420 | ) | $ | 2,297 | |||||
Location of (loss) gain reclassified from AOCGL into income (effective portion) |
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Contract drilling expense |
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Contract drilling expense |
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Contract drilling expense |
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Contract drilling expense |
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Amount of (loss) gain reclassified from AOCGL into income (effective portion) |
$ | (415 | ) | $ | 2,333 | $ | (7,829 | ) | $ | 6,232 | ||||||
Location of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) |
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Foreign currency transaction gain (loss) |
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Foreign currency transaction gain (loss) |
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Foreign currency transaction gain (loss) |
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Foreign currency transaction gain (loss) |
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Amount of loss recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing) |
$ | | $ | (59 | ) | $ | (1 | ) | $ | (60 | ) | |||||
Treasury lock agreements: |
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Amount of gain recognized in AOCGL on derivative (effective portion) |
$ | | $ | | $ | | $ | | ||||||||
Location of gain reclassified from AOCGL into income (effective portion) |
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Interest Expense |
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Interest Expense |
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Interest Expense |
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Interest Expense |
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Amount of gain reclassified from AOCGL into income (effective portion) |
$ | 2 | $ | 2 | $ | 6 | $ | 6 |
As of September 30, 2015, the estimated amount of net unrealized gains associated with our treasury lock agreements that will be reclassified to interest expense during the next twelve months was $8,052. During the nine-month periods ended September 30, 2015 and 2014, we did not reclassify any amounts from AOCGL due to the probability of an underlying forecasted transaction not occurring.
8. Financial Instruments and Fair Value Disclosures
Financial instruments that potentially subject us to significant concentrations of credit or market risk consist primarily of periodic temporary investments of excess cash, trade accounts receivable and investments in debt securities, including residential mortgage-backed securities. We generally place our excess cash investments in U.S. government-backed short-term money market instruments through several financial institutions. At times, such investments may be in excess of the insurable limit. We periodically evaluate the relative credit standing of these financial institutions as part of our investment strategy.
Most of our investments in debt securities are securitized corporate bonds whereby our credit risk is mitigated by the collateral. However, we are exposed to market risk due to price volatility associated with interest rate fluctuations.
Concentrations of credit risk with respect to our trade accounts receivable are limited primarily due to the entities comprising our customer base. Since the market for our services is the offshore oil and gas industry, this customer base consists primarily of major and independent oil and gas companies and government-owned oil companies. At September 30, 2015 and December 31, 2014, Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the Brazilian government), or Petrobras, accounted for $74.1 million and $123.3 million, or 16% and 29%, respectively, of our total consolidated net trade accounts receivable balance.
In general, before working for a customer with whom we have not had a prior business relationship and/or whose financial stability may be uncertain to us, we perform a credit review on that company. Based on that analysis, we may require that the customer present a letter of credit, prepay or provide other credit enhancements. We record a provision for bad debts on a case-by-case basis when facts and circumstances indicate that a customer receivable may not be collectible and, historically, losses on our trade receivables have been infrequent occurrences.
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Fair Values
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. There are three levels of inputs that may be used to measure fair value:
Level 1 |
Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds, U.S. Treasury Bills and Treasury notes. Our Level 1 assets at September 30, 2015 consisted of cash held in money market funds of $110.3 million and time deposits of $20.3 million. Our Level 1 assets at December 31, 2014 consisted of cash held in money market funds of $197.5 million and time deposits of $20.3 million. | |
Level 2 |
Quoted market prices for similar instruments in active markets; quoted prices for identical or similar instruments in markets that are not active; and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets. Level 2 assets and liabilities include residential mortgage-backed securities, corporate bonds purchased in a private placement offering and over-the-counter FOREX contracts. Our residential mortgage-backed securities and corporate bonds were valued using a model-derived valuation technique based on the quoted closing market prices received from a financial institution. Our FOREX contracts are valued based on quoted market prices, which are derived from observable inputs including current spot and forward rates, less the contract rate multiplied by the notional amount. The inputs used in our valuation are obtained from a Bloomberg curve analysis which uses par coupon swap rates to calculate implied forward rates so that projected floating rate cash flows can be calculated. The valuation techniques underlying the models are widely accepted in the financial services industry and do not involve significant judgment. | |
Level 3 |
Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable. Level 3 assets and liabilities generally include financial instruments whose value is determined using pricing models, discounted cash flow methodologies, or similar techniques, as well as instruments for which the determination of fair value requires significant management judgment or estimation or for which there is a lack of transparency as to the inputs used. Our Level 3 assets at September 30, 2015 consisted of nonrecurring measurements of certain of our drilling rigs for which we recorded an impairment loss during the first nine months of 2015. See Notes 1 and 2. |
Market conditions could cause an instrument to be reclassified among Levels 1, 2 and 3. Our policy regarding fair value measurements of financial instruments transferred into and out of levels is to reflect the transfers as having occurred at the beginning of the reporting period. There were no transfers between fair value levels during the three-month and nine-month periods ended September 30, 2015 and 2014.
Certain of our assets and liabilities are required to be measured at fair value on a recurring basis in accordance with GAAP. In addition, certain assets and liabilities may be recorded at fair value on a nonrecurring basis. Generally, we record assets at fair value on a nonrecurring basis as a result of impairment charges. We recorded impairment charges related to assets measured at fair value on a nonrecurring basis during the three-month and nine-month periods ended September 30, 2015 of $2.6 million and $361.1 million, respectively. We recorded impairment charges related to assets measured at fair value on a nonrecurring basis of $109.5 million during the three-month and nine-month periods ended September 30, 2014.
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Assets and liabilities measured at fair value are summarized below:
September 30, 2015 | ||||||||||||||||||||||||
Fair Value Measurements Using | Total Losses for Period Ended |
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Level 1 | Level 2 | Level 3 | Assets at Fair Value |
Three Months |
Nine Months |
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(In thousands) | ||||||||||||||||||||||||
Recurring fair value measurements: |
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Assets: |
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Short-term investments |
$ | 130,625 | $ | | $ | | $ | 130,625 | ||||||||||||||||
Corporate bonds |
| 13,523 | | 13,523 | ||||||||||||||||||||
Mortgage-backed securities |
| 98 | | 98 | ||||||||||||||||||||
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Total assets |
$ | 130,625 | $ | 13,621 | $ | | $ | 144,246 | ||||||||||||||||
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Nonrecurring fair value measurements: |
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Assets: |
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Impaired assets (1)(2) |
$ | | $ | | $ | 8,650 | $ | 8,650 | $ | 2,546 | $ | 361,074 | ||||||||||||
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(1) | Represents the carrying value as of September 30, 2015 of three mid-water semisubmersible rigs, one jack-up rig and one drillship, which were written down to their estimated recoverable amounts in 2015. See Note 2. |
(2) | Excludes the fair values of the Ocean Saratoga, Ocean Yorktown, Ocean Worker, and Ocean Lexington which were impaired in March 2015, but were subsequently sold for scrap in the second and third quarters of 2015. |
December 31, 2014 | ||||||||||||||||
Fair Value Measurements Using | ||||||||||||||||
Level 1 | Level 2 | Level 3 | Assets at Fair Value |
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(In thousands) | ||||||||||||||||
Recurring fair value measurements: |
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Assets: |
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Short-term investments |
$ | 217,789 | $ | | $ | | $ | 217,789 | ||||||||
Corporate bonds |
| 15,899 | | 15,899 | ||||||||||||
Mortgage-backed securities |
| 134 | | 134 | ||||||||||||
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Total assets |
$ | 217,789 | $ | 16,033 | $ | | $ | 233,822 | ||||||||
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Liabilities: |
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FOREX contracts |
$ | | $ | (5,439 | ) | $ | | $ | (5,439 | ) | ||||||
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Nonrecurring fair value measurements: |
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Assets: |
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Impaired assets (1) |
$ | | $ | | $ | 9,421 | $ | 9,421 | ||||||||
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(1) | Represents the book value as of December 31, 2014 of four of our mid-water semisubmersible rigs, which were written down to their estimated recoverable amounts in 2014. All four rigs were sold for scrap during the nine months ended September 30, 2015. |
We believe that the carrying amounts of our other financial assets and liabilities (excluding long-term debt), which are not measured at fair value in our Consolidated Balance Sheets, approximate fair value based on the following assumptions:
| Cash and cash equivalents The carrying amounts approximate fair value because of the short maturity of these instruments. |
| Accounts receivable and accounts payable The carrying amounts approximate fair value based on the nature of the instruments. |
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| Commercial paper The carrying amounts approximate fair value because of the short maturity of these instruments. |
We consider our senior notes, including current maturities, to be Level 2 liabilities under the GAAP fair value hierarchy and, accordingly, the fair value of our senior notes was derived using a third-party pricing service at September 30, 2015 and December 31, 2014. We perform control procedures over information we obtain from pricing services and brokers to test whether prices received represent a reasonable estimate of fair value. These procedures include the review of pricing service or broker pricing methodologies and comparing fair value estimates to actual trade activity executed in the market for these instruments occurring generally within a 10-day period of the report date. Fair values and related carrying values of our senior notes are shown below.
September 30, 2015 | December 31, 2014 | |||||||||||||||
Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||
(In millions) | ||||||||||||||||
4.875% Senior Notes due 2015 |
$ | | $ | | $ | 255.0 | $ | 250.0 | ||||||||
5.875% Senior Notes due 2019 |
520.0 | 499.7 | 544.9 | 499.6 | ||||||||||||
3.45% Senior Notes due 2023 |
230.0 | 249.1 | 232.0 | 249.1 | ||||||||||||
5.70% Senior Notes due 2039 |
383.0 | 497.0 | 478.5 | 497.0 | ||||||||||||
4.875% Senior Notes due 2043 |
490.5 | 748.9 | 638.9 | 748.8 |
We have estimated the fair value amounts by using appropriate valuation methodologies and information available to management. Considerable judgment is required in developing these estimates, and accordingly, no assurance can be given that the estimated values are indicative of the amounts that would be realized in a free market exchange.
9. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized as follows:
September 30, 2015 |
December 31, 2014 |
|||||||
(In thousands) | ||||||||
Drilling rigs and equipment |
$ | 10,113,847 | $ | 10,555,314 | ||||
Construction work-in-progress |
250,930 | 439,206 | ||||||
Land and buildings |
65,785 | 66,989 | ||||||
Office equipment and other |
71,255 | 70,591 | ||||||
|
|
|
|
|||||
Cost |
10,501,817 | 11,132,100 | ||||||
Less: accumulated depreciation |
(3,613,569 | ) | (4,186,147 | ) | ||||
|
|
|
|
|||||
Drilling and other property and equipment, net |
$ | 6,888,248 | $ | 6,945,953 | ||||
|
|
|
|
During the nine months ended September 30, 2015, we sold eight rigs with an aggregate net book value of $4.4 million for scrap and recognized an aggregate gain on disposition of $0.2 million and $1.0 million for the three-month and nine-month periods ended September 30, 2015, respectively. In addition, during the nine-month period ended September 30, 2015, we recognized an impairment loss of $361.1 million. See Note 2.
Construction work-in-progress, including capitalized interest, at September 30, 2015 and December 31, 2014 is summarized as follows:
September 30, 2015 |
December 31, 2014 |
|||||||
(In thousands) | ||||||||
Ultra-deepwater semisubmersible Ocean GreatWhite |
$ | 250,930 | $ | 213,801 | ||||
Ultra-deepwater drillship Ocean BlackLion |
| 225,405 | ||||||
|
|
|
|
|||||
Total construction work-in-progress |
$ | 250,930 | $ | 439,206 | ||||
|
|
|
|
The Ocean BlackLion was placed in service in June 2015 and is no longer reported as construction work-in-progress at September 30, 2015.
18
10. Revolving Credit Facility, Commercial Paper and Senior Notes
Revolving Credit Facility. We have a syndicated revolving credit agreement with Wells Fargo Bank, National Association, as administrative agent and swingline lender, which provides for a $1.5 billion senior unsecured revolving credit facility for general corporate purposes, or the Revolving Credit Facility. Effective October 22, 2015, we entered into an extension agreement and fourth amendment to our Revolving Credit Facility, which, among other things, provides for a one-year extension of the maturity date for most of the lenders. As so extended, our Revolving Credit Facility matures on October 22, 2020, except for $40 million of commitments that mature on March 17, 2019 and $60 million of commitments that mature on October 22, 2019. In addition, we also have the option to increase the revolving commitments under the Revolving Credit Facility by up to an additional $500 million from time to time, upon receipt of additional commitments from new or existing lenders, and to request one additional one-year extension of the maturity date. The entire amount of the facility is available, subject to its terms, for revolving loans. Up to $250 million of the facility may be used for the issuance of performance or other standby letters of credit and up to $100 million may be used for swingline loans.
Commercial Paper. In 2015, we established a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion. Proceeds from issuances under the commercial paper program may be used for general corporate purposes. The maturities of the notes may vary, but may not exceed 397 days from the date of issuance. The notes will be issued, at our option, either at a discounted price to their principal face value or will bear interest, which may be at a fixed or floating rate, at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The notes are not redeemable or subject to voluntary prepayment by us prior to maturity. Liquidity for our payment obligations in respect of the notes issued under the commercial paper program is provided under our Revolving Credit Facility, and the aggregate amount of notes outstanding at any time will not exceed the amount available under the Revolving Credit Facility.
As of September 30, 2015, we had $493.0 million in commercial paper notes outstanding with a weighted average interest rate of 0.44% and a weighted average remaining term of two days. As of October 29, 2015, we had an additional $1.1 billion available under our Revolving Credit Facility to provide liquidity for our payment obligations with respect to the issuance of commercial paper.
4.875% Senior Notes due 2015. On July 1, 2015, we repaid $250.0 million in aggregate principal amount of our 4.875% Senior Notes due July 1, 2015, primarily with funds obtained through the issuance of additional commercial paper. These notes were presented as Current portion of long-term debt in our Consolidated Balance Sheet at December 31, 2014.
11. 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.
Asbestos Litigation. We are one of several unrelated defendants in lawsuits filed in Mississippi, Louisiana and Missouri state courts alleging that defendants manufactured, distributed or utilized drilling mud containing asbestos and, in our case, allowed such drilling mud to have been utilized aboard our offshore drilling rigs. The plaintiffs seek, among other things, an award of unspecified compensatory and punitive damages. The manufacture and use of asbestos-containing drilling mud had already ceased before we acquired any of the drilling rigs addressed in these lawsuits. We believe that we are not liable for the damages asserted and we expect to receive complete defense and indemnity from Murphy Exploration & Production Company with respect to many of the lawsuits pursuant to the terms of our 1992 asset purchase agreement with them. We also believe that we are not liable for the damages asserted in the remaining lawsuits pursuant to the terms of our 1989 asset purchase agreement with Diamond M Corporation, and we filed a declaratory judgment action in Texas state court against NuStar Energy LP, or NuStar, and Kaneb Management Co., L.L.C., or Kaneb, the successors to Diamond M Corporation, seeking a judicial determination that we did not assume liability for these claims. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but do not believe that our ultimate liability, if any, resulting from this litigation will have a material effect on our consolidated financial condition, results of operations or cash flows.
19
Other Litigation. We have been named in various other claims, lawsuits or threatened actions that are incidental to the ordinary course of our business, including a claim by Petrobras that it will seek to recover from its contractors, including us, any taxes, penalties, interest and fees that it must pay to the Brazilian tax authorities for our applicable portion of withholding taxes related to Petrobras charter agreements with its contractors. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of these claims, lawsuits and actions cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of these matters. Any claims against us, whether meritorious or not, could cause us to incur costs and expenses, require significant amounts of management time and result in the diversion of significant operational resources. In the opinion of our management, no pending or known threatened claims, actions or proceedings against us are expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows.
NPI Arrangement. We received customer payments measured by a percentage net profits interest (primarily of 27%) under an overriding royalty interest in certain developmental oil-and-gas producing properties, or NPI, which we believe is a real property interest. Our drilling program related to the NPI was completed in 2011, and the balance of the amounts due to us under the NPI was received in 2013. However, the customer that conveyed the NPI to us filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in August 2012. Certain parties (including the debtor) in the bankruptcy proceedings questioned whether our NPI, and certain amounts we received under it since the filing of the bankruptcy, should be included in the debtors estate under the bankruptcy proceeding. In 2013, we filed a declaratory judgment action in the bankruptcy court seeking a declaration that our NPI, and payments that we received from it since the filing of the bankruptcy, are not part of the bankruptcy estate. We agreed to a settlement with the company that purchased most of the debtors assets (including the debtors claims against our NPI) whereby the nature of our NPI will not be challenged by that party and our declaratory judgment action was dismissed. Following the settlement, the bankruptcy was converted to a Chapter 7 liquidation proceeding. Several lienholders who had previously intervened in the declaratory judgment action filed motions in the bankruptcy contending that their liens have priority and seeking disgorgement of $3.25 million of payments made to us after the bankruptcy was filed. We believe that our rights to the payments at issue are superior to these liens, and we have filed appropriate motions to dismiss these claims. In addition, the bankruptcy trustee filed counterclaims seeking disgorgement of a total of $30.0 million of pre- and post-bankruptcy payments made to us under the original NPI. We have filed motions to dismiss these counterclaims and still expect the bankruptcy proceedings to be concluded with no further material impact to us.
Personal Injury Claims. Under our current insurance policies that expire on May 1, 2016, our deductibles for marine liability insurance coverage, including personal injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are $25.0 million for the first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.
The Jones Act is a federal law that permits seamen to seek compensation for certain injuries during the course of their employment on a vessel and governs the liability of vessel operators and marine employers for the work-related injury or death of an employee. We engage outside consultants to assist us in estimating our aggregate liability for personal injury claims based on our historical losses and utilizing various actuarial models. We allocate a portion of the aggregate liability to Accrued liabilities based on an estimate of claims expected to be paid within the next twelve months with the residual recorded as Other liabilities. At September 30, 2015 our estimated liability for personal injury claims was $43.4 million, of which $8.2 million and $35.2 million were recorded in Accrued liabilities and Other liabilities, respectively, in our Consolidated Balance Sheets. At December 31, 2014, our estimated liability for personal injury claims was $39.4 million, of which $8.2 million and $31.2 million were recorded in Accrued liabilities and Other liabilities, respectively, in our Consolidated Balance Sheets. The eventual settlement or adjudication of these claims could differ materially from our estimated amounts due to uncertainties such as:
| the severity of personal injuries claimed; |
| significant changes in the volume of personal injury claims; |
| the unpredictability of legal jurisdictions where the claims will ultimately be litigated; |
| inconsistent court decisions; and |
| the risks and lack of predictability inherent in personal injury litigation. |
Purchase Obligations. The Ocean GreatWhite, a 10,000 foot dynamically positioned, harsh environment semisubmersible drilling rig, is under construction in South Korea at an estimated cost of $764 million, including shipyard costs, capital spares, commissioning, project management and shipyard supervision. The contracted price
20
to Hyundai Heavy Industries Co., Ltd. totaling $628.5 million is payable in two installments, of which the first installment of $188.6 million has been paid. The final installment of $439.9 million is due upon delivery of the rig, which is expected to occur in the second quarter of 2016.
At September 30, 2015, we had no other purchase obligations for major rig upgrades or any other significant obligations, except for those related to our direct rig operations, which arise during the normal course of business.
Letters of Credit and Other. We were contingently liable as of September 30, 2015 in the amount of $71.3 million under certain performance, security, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $63.7 million of performance, security, supersedeas and customs bonds can require collateral at any time. As of September 30, 2015, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. On our behalf, banks have issued letters of credit securing certain of these bonds.
12. Accumulated Other Comprehensive Gain (Loss)
The components of our AOCGL and related changes thereto are as follows:
Unrealized (Loss) Gain on | ||||||||||||
Derivative Financial Instruments |
Marketable Securities |
Total AOCGL |
||||||||||
(In thousands) | ||||||||||||
Balance at January 1, 2015 |
$ | (3,504 | ) | $ | (101 | ) | $ | (3,605 | ) | |||
Change in other comprehensive (loss) gain before reclassifications, after tax of $846 and $(1) |
(1,574 | ) | (2,733 | ) | (4,307 | ) | ||||||
Reclassification adjustments for items included in Net Income, after tax of $(2,738) and $0 |
5,085 | | 5,085 | |||||||||
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|
|
|
|
|
|||||||
Balance at September 30, 2015 |
$ | 7 | $ | (2,834 | ) | $ | (2,827 | ) | ||||
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The following table presents the line items in our Consolidated Statements of Operations affected by reclassification adjustments out of AOCGL.
Three Months Ended September 30, |
Nine Months Ended September 30, |
Consolidated Statements of | ||||||||||||||||
Major Category of AOCGL | 2015 | 2014 | 2015 | 2014 | ||||||||||||||
(In thousands) | ||||||||||||||||||
Derivative Financial Instruments: |
||||||||||||||||||
Unrealized loss (gain) on FOREX contracts |
$ | 415 | $ | (2,333 | ) | $ | 7,829 | $ | (6,232 | ) | Contract drilling, excluding depreciation | |||||||
Unrealized (gain) loss on treasury lock agreements |
(2 | ) | (2 | ) | (6 | ) | (6 | ) | Interest expense | |||||||||
(145 | ) | 817 | (2,738 | ) | 2,183 | Income tax expense | ||||||||||||
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$ | 268 | $ | (1,518 | ) | $ | 5,085 | $ | (4,055 | ) | Net of tax | ||||||||
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Marketable Securities: |
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Unrealized (gain) loss on marketable securities |
$ | | $ | (1 | ) | $ | | $ | (34 | ) | Other, net | |||||||
| | | 7 | Income tax expense | ||||||||||||||
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$ | | $ | (1 | ) | $ | | $ | (27 | ) | Net of tax | ||||||||
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13. Restructuring and Separation Costs
In response to the continuing decline in the offshore drilling market, we reviewed our cost and organization structure, and, as a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities, also referred to as the Corporate Reduction Plan, during the first nine months of 2015. As of September 30, 2015, appropriate communications have been made to substantially all impacted personnel, and we paid $1.6 million and $8.7 million in restructuring and employee separation related costs during the three-month and nine-month periods ended September 30, 2015, respectively. There were no accrued costs associated with the Corporate Reduction Plan as of September 30, 2015.
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14. Income Taxes
Our income tax expense is a function of the mix between our domestic and international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in which we operate. Certain of our international rigs are owned and operated, directly or indirectly, by one of our wholly owned foreign subsidiaries. It is our intention to indefinitely reinvest future earnings of this subsidiary to finance foreign activities. Accordingly, we have not made a provision for U.S. income taxes on such earnings except to the extent that such earnings were immediately subject to U.S. income taxes.
Tax Returns and Examinations. We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and various foreign jurisdictions. In several of these jurisdictions, tax years remain subject to examination and/or we are currently under audit or we have assessments that we are disputing.
U.S. Tax Jurisdiction. During 2015, the Internal Revenue Service began an audit of our corporate income tax return for the 2013 tax year.
Australia Tax Jurisdiction. During 2015, the Australian Taxation Office began an audit of our income tax returns for the 2010 through 2013 tax years.
Mexico Tax Jurisdiction. Due to the 2015 expiration of the statute of limitations in Mexico for the 2009 tax year for one of our subsidiaries operating in Mexico, we reversed our $10.7 million accrual for an uncertain tax position, of which $3.6 million is interest and $1.4 million is penalty.
During 2015, one of our subsidiaries operating in Mexico received a tax assessment of $5.3 million from the Mexican tax authorities for the 2008 tax year, which we are appealing.
15. Segments and Geographic Area Analysis
Although we provide contract drilling services with different types of offshore drilling rigs and also provide such services in many geographic locations, we have aggregated these operations into one reportable segment based on the similarity of economic characteristics due to the nature of the revenue earning process as it relates to the offshore drilling industry over the operating lives of our drilling rigs.
Revenues from contract drilling services by equipment type are listed below:
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
Floaters: |
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Ultra-Deepwater |
$ | 376,195 | $ | 313,124 | $ | 943,261 | $ | 701,574 | ||||||||
Deepwater |
136,668 | 111,372 | 456,542 | 378,470 | ||||||||||||
Mid-Water |
69,500 | 258,028 | 342,783 | 844,909 | ||||||||||||
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Total Floaters |
582,363 | 682,524 | 1,742,586 | 1,924,953 | ||||||||||||
Jack-ups |
16,673 | 45,364 | 73,469 | 137,797 | ||||||||||||
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Total contract drilling revenues |
599,036 | 727,888 | 1,816,055 | 2,062,750 | ||||||||||||
Revenues related to reimbursable expenses |
10,706 | 9,794 | 47,775 | 76,600 | ||||||||||||
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Total revenues |
$ | 609,742 | $ | 737,682 | $ | 1,863,830 | $ | 2,139,350 | ||||||||
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Geographic Areas
Our drilling rigs are highly mobile and may be moved to other markets throughout the world in response to market conditions or customer needs. At September 30, 2015, our actively-marketed drilling rigs were en route to or located offshore seven countries in addition to the United States. Revenues by geographic area are presented by attributing revenues to the individual country or areas where the services were performed.
Three Months Ended September 30, |
Nine Months Ended September 30, |
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2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
United States |
$ | 140,898 | $ | 83,300 | $ | 330,765 | $ | 326,808 | ||||||||
International: |
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South America |
222,717 | 294,246 | 654,432 | 844,242 | ||||||||||||
Europe/Africa/Mediterranean |
132,345 | 135,286 | 420,147 | 395,602 | ||||||||||||
Australia/Asia |
86,608 | 162,929 | 333,628 | 393,248 | ||||||||||||
Mexico |
27,174 | 61,921 | 124,858 | 179,450 | ||||||||||||
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Total revenues |
$ | 609,742 | $ | 737,682 | $ | 1,863,830 | $ | 2,139,350 | ||||||||
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23
ITEM 2. Managements Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion should be read in conjunction with our unaudited consolidated financial statements (including the notes thereto) included elsewhere in this report and our audited consolidated financial statements and the notes thereto, Item 7, Managements Discussion and Analysis of Financial Condition and Results of Operations and Item 1A, Risk Factors included in our Annual Report on Form 10-K for the year ended December 31, 2014. References to Diamond Offshore, we, us or our mean Diamond Offshore Drilling, Inc., a Delaware corporation, and its subsidiaries.
We are a leader in offshore drilling, providing contract drilling services to the energy industry around the globe with a fleet of 33 offshore drilling rigs. Our current fleet consists of eight ultra-deepwater, seven deepwater and eight mid-water semisubmersibles, four dynamically-positioned ultra-deepwater drillships and six jack-ups. Construction of our fourth newbuild ultra-deepwater drillship, the Ocean BlackLion, was completed in the second quarter of 2015, and the rig is currently in the U.S. Gulf of Mexico, or GOM, and is expected to begin contract drilling operations by the end of this year. One of our eight ultra-deepwater semisubmersibles, the Ocean GreatWhite is currently under construction and is expected to be delivered in the second quarter of 2016. The Ocean GreatWhite is expected to commence a three-year drilling contract offshore Australia in late 2016.
Of our current fleet, eleven rigs are cold stacked, including one ultra-deepwater, one deepwater and four mid-water semisubmersible rigs and five jack-up rigs. Since the beginning of 2015, eight of our older mid-water semisubmersible rigs have been sold for scrap. We intend to sell one of our idled jack-up rigs and, after completion of their respective contracts, we also intend to sell one mid-water semisubmersible and our older 7,875-foot water depth rated drillship for scrap.
Market Overview
Crude oil prices have declined significantly since the summer of 2014, and oil markets remain volatile and unpredictable due to a number of geopolitical and economic factors, including the Iranian Joint Comprehensive Plan of Action which, if implemented, would result in the lifting of certain international sanctions. In reaction to the depressed fundamentals in the oil and gas industry, independent and national oil companies and exploration and production companies have announced significant reductions to their 2016 capital spending plans, in addition to their already-reduced 2015 capital spending plans, and are projecting reductions to their 2017 spending budgets. Thus far in 2015, rig tenders have been infrequent and have generally been limited to short-term or well-to-well work or long-range work not commencing until 2017 or later. Competition for the limited number of drilling jobs continues to be intense, with numerous offshore drillers vying for the same opportunities, including some contractors bidding multiple rigs on the same bid, and in some cases bidding rigs of both high and lower specifications on the same bid. Operators are continuing to attempt to sublet previously contracted rigs for which capital spending programs have been delayed or canceled. In addition, newbuild floaters continue to enter the market, many of which are not contracted, adding to the oversupply of rigs. With the shortage of work and an oversupply of rigs available for work, price competition remains intense, and some industry analysts are predicting further weakening in already lower dayrates across the floater markets.
In addition, as a result of the depressed market conditions and continued pessimistic outlook for the near term, certain of our customers, as well as those of our competitors, have attempted to renegotiate or terminate existing drilling contracts. Such renegotiations could include requests to lower the contract dayrate, lowering of a dayrate in exchange for additional contract term, shortening the term on one contracted rig in exchange for additional term on another rig, early termination of a contract in exchange for a lump sum margin payout and many other possibilities. In addition to the potential for renegotiations, some of our drilling contracts permit the customer to terminate the contract early after specified notice periods, sometimes resulting in no payment to us or sometimes resulting in a contractually specified termination amount, which often does not fully compensate us for the loss of the contract. During depressed market conditions, certain customers have utilized such contract clauses to seek to renegotiate or terminate a drilling contract or claim that we have breached provisions of our drilling contracts in order to avoid their obligations to us under circumstances where we believe we are in compliance with the contracts. The early termination of a contract may result in a rig being idle for an extended period of time, which could adversely affect our financial condition, results of operations and cash flows. When a customer terminates our contract prior to the contracts scheduled expiration, our contract backlog is also adversely impacted. See Contract Drilling Backlog below.
In October 2015, we reached agreement with Petróleo Brasileiro S.A., or Petrobras, to terminate the drilling contracts on the Ocean Clipper and Ocean Alliance early, to be effective on October 30, 2015, and to add 875 days
24
to the end of the current term of the drilling contract on the Ocean Courage at the rate of $380,000 per day. Petrobras has approved the agreement and we are in the process of completing the amendments to the drilling contracts. When the amendment has been completed, the revised term of the Ocean Courage contract will expire on July 20, 2020. Prior to the amendment, the terms of the Ocean Clipper and Ocean Alliance contracts were scheduled to expire on December 9, 2015 and June 17, 2016, respectively.
As previously disclosed, on February 20, 2015, a representative of PEMEX Exploración y Producción, or PEMEX, verbally informed us of PEMEXs intention to exercise its contractual right to terminate its drilling contract on the Ocean Ambassador and to cancel its drilling contract on the Ocean Lexington, which contract was scheduled to commence in September 2015. During the second quarter of 2015, we and PEMEX renegotiated the contract for the Ocean Ambassador, which is expected to be completed in the first quarter of 2016, at a lower dayrate. In July 2015, PEMEX delivered to us a notice to initiate the rescission of the Ocean Lexington contract, which process is currently underway.
Current depressed market conditions in the offshore drilling industry have materially impacted our results of operations and cash flows during the first nine months of 2015. We currently expect that these adverse market conditions will continue for the foreseeable future. The continuation of these conditions could result in more of our rigs being without contracts and/or cold stacked or scrapped and could further materially and adversely affect our financial condition, results of operations and cash flows. When we cold stack or elect to scrap a rig, we evaluate the rig for impairment. During the first nine months of 2015, we recognized a $361.1 million impairment charge related to nine rigs, for which we determined the carrying values to be impaired. See Results of Operations Overview Nine Months Ended September 30, 2015 and 2014 Impairment of Assets.
As of October 19, 2015, 15 of our rigs were not subject to a drilling contract with a customer, including 11 rigs that have been cold stacked or are in the process of being cold stacked. See Contract Drilling Backlog for future commitments of our rigs during the last quarter of 2015 through 2020.
Although these general market conditions impact all segments of the offshore drilling market, the following discussion addresses market conditions within segments of the floater market.
Floater Markets
Ultra-Deepwater and Deepwater Floaters. Globally, the ultra-deepwater and deepwater floater markets continue to be depressed. The continuing oversupply of rigs and diminished demand has resulted in further decline in dayrates and the stacking, and in some cases scrapping, of rigs in all asset classes. Industry analysts expect offshore drillers to continue to scrap older, lower specification rigs and predict that the number of uncontracted floaters may more than double by the end of 2016.
Newbuild rig deliveries and established rigs coming off contract continue to fuel an oversupply of floaters in both the ultra-deepwater and deepwater markets. In an effort to manage the oversupply of rigs and potentially avoid the cost of cold stacking newly-built rigs, which, in the case of dynamically-positioned rigs, can be significant, several drilling contractors have exercised options to delay the delivery of rigs by the shipyard or have exercised their right to cancel orders due to the late delivery of rigs. As of the date of this report, based on industry data, there are approximately 52 competitive, or non-owner-operated, newbuild floaters on order, 37 of which are not yet contracted for future work. There are currently 22 newbuild floaters scheduled for delivery in 2016, of which only six rigs have been contracted for future work, and another 30 rigs scheduled for delivery in 2017 and beyond. The influx of newbuilds into the market, combined with established rigs coming off contract during 2015 and in 2016, is expected to exacerbate the continuing weakened condition of the ultra-deepwater and deepwater floater markets.
Mid-Water Floaters. While conditions in the mid-water market vary slightly by region, mid-water rigs have generally been adversely impacted by (i) lower demand, (ii) declining dayrates, (iii) increased regulatory requirements, including more stringent design requirements for well control equipment, which could significantly increase the capital needed to comply with design requirements that would permit such rigs to work in U.S. waters, (iv) the challenges experienced by lower specification units in this segment as a result of more complex customer specifications, and (v) the intensified competition resulting from the migration of some deepwater and ultra-deepwater units to compete against mid-water units. To date, the mid-water market has seen the highest number of cold-stacked and scrapped rigs. Additionally, as market conditions remain challenging, higher specification rigs may continue to take the place of lower specification units, leading to additional lower specification rigs being cold stacked or ultimately scrapped.
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Contract Drilling Backlog
The following table reflects our contract drilling backlog as of October 1, 2015 (based on contract information known as of November 2, 2015), February 9, 2015 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2014), and October 21, 2014 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30, 2014). Contract drilling backlog as presented below includes only firm commitments (typically represented by signed contracts, except as indicated in the footnotes to the tables below), and is calculated by multiplying the contracted operating dayrate by the firm contract period and adding one-half of any potential rig performance bonuses. Our calculation also assumes full utilization of our drilling equipment for the contract period (excluding scheduled shipyard and survey days); however, the amount of actual revenue earned and the actual periods during which revenues are earned will be different than the amounts and periods shown in the tables below due to various factors. Utilization rates, which generally approach 92-98% during contracted periods, can be adversely impacted by downtime due to various operating factors including, but not limited to, weather conditions and unscheduled repairs and maintenance. Contract drilling backlog excludes revenues for mobilization, demobilization, contract preparation and customer reimbursables. No revenue is generally earned during periods of downtime for regulatory surveys. Changes in our contract drilling backlog between periods are generally a function of the performance of work on term contracts, as well as the extension or modification of existing term contracts and the execution of additional contracts.
October 1, 2015 |
February 9, 2015 |
October 21, 2014 |
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(In thousands) | ||||||||||||
Contract Drilling Backlog |
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Floaters: |
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Ultra-Deepwater (1)(2) |
$ | 4,851,000 | $ | 5,390,000 | $ | 6,090,000 | ||||||
Deepwater (2) |
439,000 | 748,000 | 773,000 | |||||||||
Mid-Water |
401,000 | 611,000 | 1,149,000 | |||||||||
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|
|||||||
Total Floaters |
5,691,000 | 6,749,000 | 8,012,000 | |||||||||
Jack-ups |
18,000 | 91,000 | 180,000 | |||||||||
|
|
|
|
|
|
|||||||
Total |
$ | 5,709,000 | $ | 6,840,000 | $ | 8,192,000 | ||||||
|
|
|
|
|
|
(1) | Contract drilling backlog as of October 1, 2015 for our ultra-deepwater floaters includes (i) $1.3 billion attributable to our contracted operations offshore Brazil for the years 2015 to 2020 and (ii) $641.0 million for the years 2016 to 2019 attributable to future work for the semisubmersible Ocean GreatWhite, which is under construction. |
(2) | Contract drilling backlog as of October 1, 2015 (i) includes $322.0 million of additional backlog attributable to the ultra-deepwater Ocean Courage and (ii) excludes $12.0 million and $79.0 million attributable to the ultra-deepwater Ocean Clipper and deepwater Ocean Alliance, respectively, pursuant to an agreement that Petrobras has approved, but for which we are in the process of completing the amendments to the drilling contracts. See discussion under Market Overview above. |
The following table reflects the amount of our contract drilling backlog by year as of October 1, 2015.
For the Years Ending December 31, | ||||||||||||||||||||
Total | 2015 (1) | 2016 | 2017 | 2018 - 2020 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Contract Drilling Backlog |
||||||||||||||||||||
Floaters: |
||||||||||||||||||||
Ultra-Deepwater (2)(3) |
$ | 4,851,000 | $ | 357,000 | $ | 1,227,000 | $ | 1,202,000 | $ | 2,065,000 | ||||||||||
Deepwater (4) |
439,000 | 88,000 | 215,000 | 136,000 | | |||||||||||||||
Mid-Water |
401,000 | 47,000 | 221,000 | 133,000 | | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total Floaters |
5,691,000 | 492,000 | 1,663,000 | 1,471,000 | 2,065,000 | |||||||||||||||
Jack-ups |
18,000 | 11,000 | 7,000 | | | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|||||||||||
Total |
$ | 5,709,000 | $ | 503,000 | $ | 1,670,000 | $ | 1,471,000 | $ | 2,065,000 | ||||||||||
|
|
|
|
|
|
|
|
|
|
(1) | Represents the three-month period beginning October 1, 2015. |
26
(2) | Contract drilling backlog as of October 1, 2015 for our ultra-deepwater floaters includes (i) $94.0 million, $333.0 million, $332.0 million for the years 2015, 2016 and 2017, respectively, and $491.0 million in the aggregate for the years 2018 to 2020 attributable to our contracted operations offshore Brazil and (ii) $90.0 million and $214.0 million for the years 2016 and 2017, respectively, and $337.0 million in the aggregate for the years 2018 to 2019 attributable to future work for the Ocean GreatWhite, which is under construction. |
(3) | Contract drilling backlog as of October 1, 2015 for our ultra-deepwater floaters includes (i) $322.0 million of additional backlog in the aggregate for the years 2018 to 2020 attributable to the Ocean Courage and (ii) excludes $12.0 million in previously reported backlog for the last quarter of 2015 attributable to the Ocean Clipper pursuant to an agreement that Petrobras has approved, but for which we are in the process of completing the amendments to the drilling contracts. See discussion under Market Overview above. |
(4) | Contract drilling backlog as of October 1, 2015 for our deepwater floaters excludes $21.0 million for the last quarter of 2015 and $58.0 million for the year 2016 in previously reported backlog attributable to the Ocean Alliance pursuant to an agreement that Petrobras has approved, but for which we are in the process of completing the amendments to the drilling contracts. See discussion under Market Overview above. |
The following table reflects the percentage of rig days committed by year as of October 1, 2015. The percentage of rig days committed is calculated as the ratio of total days committed under contracts, as well as scheduled shipyard, survey and mobilization days for all rigs in our fleet, to total available days (number of rigs, including cold-stacked rigs, multiplied by the number of days in a particular year). Total available days have been calculated based on the expected final commissioning date for the Ocean GreatWhite, which is under construction.
For the Years Ending December 31, | ||||||||||||||||
2015 (1) | 2016 | 2017 | 2018 - 2020 | |||||||||||||
Rig Days Committed (2)(3) |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
78 | % | 64 | % | 54 | % | 32 | % | ||||||||
Deepwater |
45 | % | 25 | % | 17 | % | | |||||||||
Mid-Water |
46 | % | 27 | % | 12 | % | | |||||||||
All Floaters |
60 | % | 43 | % | 33 | % | 15 | % | ||||||||
Jack-ups |
17 | % | 3 | % | | |
(1) | Represents a three-month period beginning October 1, 2015. |
(2) | As of October 1, 2015, includes approximately 260 and 330 currently known, scheduled shipyard days for rig commissioning, contract preparation, surveys and extended maintenance projects, as well as rig mobilization days, for the remainder of 2015 and for the year 2016, respectively. |
(3) | Excludes previously reported rig days attributable to the Ocean Clipper and Ocean Alliance, but includes 875 additional rig days attributable to the Ocean Courage pursuant to an agreement that Petrobras has approved, but for which we are in the process of completing the amendments to the drilling contracts. See discussion under Market Overview above. |
Important Factors That May Impact Our Operating Results, Financial Condition or Cash Flows
Regulatory Surveys and Planned Downtime. Our operating income is negatively impacted when we perform certain regulatory inspections, which we refer to as a 5-year survey, or special survey, that are due every five years for each of our rigs. Operating revenue decreases because these special surveys are generally performed during scheduled downtime in a shipyard. Operating expenses increase as a result of these special surveys due to the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs. Repair and maintenance activities may result from the special survey or may have been previously planned to take place during this mandatory downtime. The number of rigs undergoing a 5-year survey will vary from year to year, as well as from quarter to quarter.
In addition, operating income may be negatively impacted by intermediate surveys, which are performed at interim periods between 5-year surveys. Intermediate surveys are generally less extensive in duration and scope than a 5-year survey. Although an intermediate survey may require some downtime for the drilling rig, it normally does not require shipyard time, except for rigs older than 15 years that are located in the United Kingdom, or U.K., sector of the North Sea.
27
During the remainder of 2015, we expect to spend an additional approximately 260 days for the mobilization of rigs, contract modifications, acceptance testing and extended maintenance projects, including days associated with a helideck upgrade for the Ocean Quest (approximately 60 days) and mobilization of and acceptance testing for the recently delivered Ocean BlackLion (approximately 67 days), which is not expected to commence drilling operations until December 2015. We can provide no assurance as to the exact timing and/or duration of downtime associated with regulatory inspections, planned rig mobilizations and other shipyard projects. See Contract Drilling Backlog.
In April 2015, the Bureau of Safety and Environmental Enforcement (an agency established by the U.S. Department of the Interior that governs the offshore drilling industry on the Outer Continental Shelf) announced proposed rules that, when enacted, will include more stringent design requirements for well control equipment used in offshore drilling operations. Based on our assessment of the proposed rules, we believe that we will need to incur significant capital cost to comply with the additional design requirements to enable our cold stacked mid-water semisubmersibles to return to work in U. S. waters.
Physical Damage and Marine Liability Insurance. We are self-insured for physical damage to rigs and equipment caused by named windstorms in the GOM. If a named windstorm in the GOM causes significant damage to our rigs or equipment, it could have a material adverse effect on our financial position, results of operations and cash flows. Under our current insurance policies that expire on May 1, 2016, we carry physical damage insurance for certain losses, other than those caused by named windstorms in the GOM, for which our deductible for physical damage is $25.0 million per occurrence. There is no assurance, however, that we will be able to retain or obtain, as the case may be, adequate levels of such coverage for such events at rates and with deductibles that we consider to be reasonable, or that we will continue to retain such coverage in the future or obtain such coverage in any particular jurisdiction. We do not typically retain loss-of-hire insurance policies to cover our rigs.
In addition, under our current insurance policies that expire on May 1, 2016, we carry marine liability insurance covering certain legal liabilities, including coverage for certain personal injury claims, with no exclusions for pollution and/or environmental risk. We believe that the policy limit for our marine liability insurance is within the range that is customary for companies of our size in the offshore drilling industry and is appropriate for our business. Our deductibles for marine liability coverage, including for personal injury claims, are $25.0 million for the first occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity and frequency of claims that might arise during the policy year.
Construction and Capital Upgrade Projects. We capitalize interest cost for the construction and upgrade of qualifying assets in accordance with accounting principles generally accepted in the U.S., or GAAP. The period of interest capitalization covers the duration of the activities required to make the asset ready for its intended use, and the capitalization period ends when the asset is substantially complete and ready for its intended use. We ceased capitalization of interest on five qualifying projects as a result of their completion in 2014 and on the Ocean BlackLion upon its delivery in the second quarter of 2015. We continue to capitalize interest for our ultra-deepwater semisubmersible Ocean GreatWhite. Consequently, interest expense reported in our Consolidated Statements of Operations will increase for the final quarter of 2015, compared to the prior year, due to the completion of projects.
Impact of Changes in Tax Laws or Their Interpretation. We operate through our various subsidiaries in a number of countries throughout the world. As a result, we are subject to highly complex tax laws, treaties and regulations in the jurisdictions in which we operate, which may change and are subject to interpretation. Changes in laws, treaties and regulations and the interpretation of such laws, treaties and regulations may put us at risk for future tax assessments and liabilities which could be substantial and could have a material adverse effect on our financial condition, results of operations and cash flows.
Critical Accounting Estimates
Impairment of Long-Lived Assets
We evaluate our property and equipment for impairment whenever changes in circumstances indicate that the carrying amount of an asset may not be recoverable (such as, but not limited to, cold stacking a rig, the expectation of cold stacking a rig in the near term, a decision to retire or scrap a rig, or excess spending over budget on a newbuild, construction project or major rig upgrade). We utilize an undiscounted probability-weighted cash flow
28
analysis in testing an asset for potential impairment. Our assumptions and estimates underlying this analysis include the following:
| dayrate by rig; |
| utilization rate by rig if active, warm stacked or cold stacked (expressed as the actual percentage of time per year that the rig would be used at certain dayrates); |
| the per day operating cost for each rig if active, warm stacked or cold stacked; |
| the estimated annual cost for rig replacements and/or enhancement programs; |
| the estimated maintenance, inspection or other costs associated with a rig returning to work; |
| salvage value for each rig; and |
| estimated proceeds that may be received on disposition of each rig. |
Based on these assumptions, we develop a matrix for each rig under evaluation using multiple utilization/dayrate scenarios, to each of which we have assigned a probability of occurrence. We arrive at a projected probability- weighted cash flow for each rig based on the respective matrix and compare such amount to the carrying value of the asset to assess recoverability.
The underlying assumptions and assigned probabilities of occurrence for utilization and dayrate scenarios are developed using a methodology that examines historical data for each rig, which considers the rigs age, rated water depth and other attributes and then assesses its future marketability in light of the current and projected market environment at the time of assessment. Other assumptions, such as operating, maintenance and inspection costs, are estimated using historical data adjusted for known developments and future events that are anticipated by management at the time of the assessment.
Managements assumptions are necessarily subjective and are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported. Our methodology generally involves the use of significant unobservable inputs, representative of a Level 3 fair value measurement, which may include assumptions related to future dayrate revenue, costs and rig utilization, quotes from rig brokers, the long-term future performance of our rigs and future market conditions. Managements assumptions involve uncertainties about future demand for our services, dayrates, expenses and other future events, and managements expectations may not be indicative of future outcomes. Significant unanticipated changes to these assumptions could materially alter our analysis in testing an asset for potential impairment. For example, changes in market conditions that exist at the measurement date or that are projected by management could affect our key assumptions. Other events or circumstances that could affect our assumptions may include, but are not limited to, a further sustained decline in oil and gas prices, cancelations of our drilling contracts or contracts of our competitors, contract modifications, costs to comply with new governmental regulations, growth in the global oversupply of oil and geopolitical events, such as lifting sanctions on oil-producing nations. Should actual market conditions in the future vary significantly from market conditions used in our projections, our assessment of impairment would likely be different.
Our other significant accounting policies are discussed in Note 1 of our notes to unaudited consolidated financial statements included in Item 1 of Part I of this report and in Note 1 of our notes to audited consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2014. There were no material changes to these policies during the three months ended September 30, 2015.
29
Results of Operations
Although we perform contract drilling services with different types of drilling rigs and in many geographic locations, there is a similarity of economic characteristics among all our divisions and locations, including the nature of services provided and the type of customers for our services. We believe that the combination of our drilling rigs into one reportable segment is the appropriate aggregation in accordance with applicable accounting standards on segment reporting. However, for purposes of this discussion and analysis of our results of operations, we provide greater detail with respect to the types of rigs in our fleet to enhance the readers understanding of our financial condition, changes in financial condition and results of operations.
Key performance indicators by equipment type are listed below.
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
REVENUE EARNING DAYS (1) |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
786 | 638 | 1,945 | 1,570 | ||||||||||||
Deepwater |
379 | 313 | 1,066 | 937 | ||||||||||||
Mid-Water |
241 | 974 | 1,253 | 3,110 | ||||||||||||
Jack-ups |
172 | 457 | 817 | 1,422 | ||||||||||||
UTILIZATION (2) |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
71 | % | 77 | % | 62 | % | 65 | % | ||||||||
Deepwater |
59 | % | 57 | % | 56 | % | 58 | % | ||||||||
Mid-Water |
31 | % | 59 | % | 39 | % | 63 | % | ||||||||
Jack-ups |
31 | % | 83 | % | 50 | % | 79 | % | ||||||||
AVERAGE DAILY REVENUE (3) |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
$ | 478,800 | $ | 491,000 | $ | 484,900 | $ | 446,700 | ||||||||
Deepwater |
360,700 | 355,500 | 428,400 | 403,700 | ||||||||||||
Mid-Water |
288,500 | 265,000 | 273,600 | 271,700 | ||||||||||||
Jack-ups |
96,700 | 99,300 | 89,900 | 96,900 |
(1) | A revenue earning day is defined as a 24-hour period during which a rig earns a dayrate after commencement of operations and excludes mobilization, demobilization and contract preparation days. |
(2) | Utilization is calculated as the ratio of total revenue-earning days divided by the total calendar days in the period for all specified rigs in our fleet (including cold-stacked rigs, but excluding rigs under construction). As of September 30, 2015, our cold-stacked rigs included one ultra-deepwater semisubmersible, one deepwater semisubmersible, four mid-water semisubmersibles and five jack-up rigs. |
(3) | Average daily revenue is defined as total contract drilling revenue for all of the specified rigs in our fleet per revenue earning day. |
30
Comparative data relating to our revenues and operating expenses by equipment type are listed below.
Three Months Ended September 30, |
Nine Months Ended September 30, |
|||||||||||||||
2015 | 2014 | 2015 | 2014 | |||||||||||||
(In thousands) | ||||||||||||||||
CONTRACT DRILLING REVENUE |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
$ | 376,195 | $ | 313,124 | $ | 943,261 | $ | 701,574 | ||||||||
Deepwater |
136,668 | 111,372 | 456,542 | 378,470 | ||||||||||||
Mid-Water |
69,500 | 258,028 | 342,783 | 844,909 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Floaters |
582,363 | 682,524 | 1,742,586 | 1,924,953 | ||||||||||||
Jack-ups |
16,673 | 45,364 | 73,469 | 137,797 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Contract Drilling Revenue |
$ | 599,036 | $ | 727,888 | $ | 1,816,055 | $ | 2,062,750 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
REVENUES RELATED TO REIMBURSABLE EXPENSES |
$ | 10,706 | $ | 9,794 | $ | 47,775 | $ | 76,600 | ||||||||
CONTRACT DRILLING EXPENSE |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
$ | 156,107 | $ | 157,655 | $ | 472,131 | $ | 403,512 | ||||||||
Deepwater |
67,630 | 72,367 | 217,769 | 225,957 | ||||||||||||
Mid-Water |
35,784 | 132,340 | 201,839 | 415,317 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Floaters |
259,521 | 362,362 | 891,739 | 1,044,786 | ||||||||||||
Jack-ups |
12,507 | 28,056 | 54,950 | 85,936 | ||||||||||||
Other |
5,916 | 9,384 | 24,782 | 34,246 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Contract Drilling Expense |
$ | 277,944 | $ | 399,802 | $ | 971,471 | $ | 1,164,968 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
REIMBURSABLE EXPENSES |
$ | 10,476 | $ | 9,437 | $ | 46,904 | $ | 75,393 | ||||||||
OPERATING INCOME (LOSS) |
||||||||||||||||
Floaters: |
||||||||||||||||
Ultra-Deepwater |
$ | 220,088 | $ | 155,469 | $ | 471,130 | $ | 298,062 | ||||||||
Deepwater |
69,038 | 39,005 | 238,773 | 152,513 | ||||||||||||
Mid-Water |
33,716 | 125,688 | 140,944 | 429,592 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Floaters |
322,842 | 320,162 | 850,847 | 880,167 | ||||||||||||
Jack-ups |
4,166 | 17,308 | 18,519 | 51,861 | ||||||||||||
Other |
(5,916 | ) | (9,384 | ) | (24,782 | ) | (34,246 | ) | ||||||||
Reimbursable expenses, net |
230 | 357 | 871 | 1,207 | ||||||||||||
Depreciation |
(118,086 | ) | (108,854 | ) | (378,714 | ) | (324,771 | ) | ||||||||
General and administrative expense |
(16,888 | ) | (18,604 | ) | (50,888 | ) | (61,909 | ) | ||||||||
Gain (loss) on disposition of assets |
(794 | ) | (1,107 | ) | (19 | ) | 7,612 | |||||||||
Impairment of assets |
(2,546 | ) | (109,462 | ) | (361,074 | ) | (109,462 | ) | ||||||||
Restructuring and separation costs |
(1,574 | ) | | (8,735 | ) | | ||||||||||
|
|
|
|
|
|
|
|
|||||||||
Total Operating Income |
$ | 181,434 | $ | 90,416 | $ | 46,025 | $ | 410,459 | ||||||||
|
|
|
|
|
|
|
|
|||||||||
Other income (expense): |
||||||||||||||||
Interest income |
629 | 86 | 1,796 | 644 | ||||||||||||
Interest expense, net of amounts capitalized |
(21,350 | ) | (9,378 | ) | (70,800 | ) | (46,056 | ) | ||||||||
Foreign currency transaction gain (loss) |
(1,163 | ) | 425 | 954 | (3,724 | ) | ||||||||||
Other, net |
217 | 90 | 702 | 598 | ||||||||||||
|
|
|
|
|
|
|
|
|||||||||
Income (loss) before income tax expense |
159,767 | 81,639 | (21,323 | ) | 361,921 | |||||||||||
Income tax expense |
(23,345 | ) | (28,994 | ) | (7,578 | ) | (73,753 | ) | ||||||||
|
|
|
|
|
|
|
|
|||||||||
NET INCOME (LOSS) |
$ | 136,422 | $ | 52,645 | $ | (28,901 | ) | $ | 288,168 | |||||||
|
|
|
|
|
|
|
|
31
The following is a summary as of the date of this report of the most significant transfers of our rigs during 2015 and 2014 between the geographic areas in which we operate:
Rig |
Rig Type |
Relocation Details |
Date | |||
Floaters (1): |
||||||
Ocean Confidence |
Ultra-Deepwater | Angola to Cameroon | February 2014 | |||
Ocean BlackHawk |
Ultra-Deepwater | South Korea to GOM (initial mobilization) | February 2014 | |||
Ocean Confidence |
Ultra-Deepwater | Cameroon to Canary Islands (life-extension project) | April 2014 | |||
Ocean Clipper |
Ultra-Deepwater | Brazil to Colombia | June 2014 | |||
Ocean Monarch |
Ultra-Deepwater | Indonesia to Malaysia (shipyard project) | September 2014 | |||
Ocean Clipper |
Ultra-Deepwater | Colombia to Brazil | December 2014 | |||
Ocean BlackHornet |
Ultra-Deepwater | South Korea to GOM (initial mobilization) | December 2014 | |||
Ocean BlackRhino |
Ultra-Deepwater | South Korea to GOM (initial mobilization) | December 2014 | |||
Ocean BlackLion |
Ultra-Deepwater | South Korea to Canary Islands (contract preparation) | May 2015 | |||
Ocean Monarch |
Ultra-Deepwater | Malaysia to Australia | June 2015 | |||
Ocean Baroness |
Ultra-Deepwater | Brazil to GOM (cold stacked August 2015) | June 2015 | |||
Ocean BlackLion |
Ultra-Deepwater | Canary Islands to GOM (acceptance testing) | September 2015 | |||
Ocean Onyx |
Deepwater | Placed in service (GOM) | January 2014 | |||
Ocean Star |
Deepwater | Brazil to GOM (cold stacked April 2015) | September 2014 | |||
Ocean Apex |
Deepwater | Singapore to Vietnam | December 2014 | |||
Ocean Onyx |
Deepwater | GOM to Trinidad | March 2015 | |||
Ocean Victory |
Deepwater | GOM to Trinidad | March 2015 | |||
Ocean Apex |
Deepwater | Vietnam to Malaysia | April 2015 | |||
Ocean America |
Deepwater | Australia to Malaysia | August 2015 | |||
Ocean General |
Mid-Water | Vietnam to Indonesia | March 2014 | |||
Ocean Quest |
Mid-Water | Malaysia to Vietnam | May 2014 | |||
Ocean Patriot |
Mid-Water | Singapore to U.K. | June 2014 | |||
Ocean Vanguard |
Mid-Water | Norway to U.K. (cold stacked July 2014) | June 2014 | |||
Ocean General |
Mid-Water | Indonesia to Malaysia (cold stacked October 2014) | September 2014 | |||
Ocean Quest |
Mid-Water | Vietnam to Malaysia | April 2015 | |||
Jack-ups: | ||||||
Ocean Titan |
Jack-up | Mexico to GOM (cold stacked January 2015) | June 2014 | |||
Ocean Spur |
Jack-up | Ecuador to Singapore (cold stacked June 2015) | April 2015 | |||
Ocean Nugget |
Jack-up | Mexico to GOM (cold stacked June 2015) | June 2015 |
(1) | The Ocean Concord, Ocean Yatzy and Ocean Epoch were sold for scrap in the first quarter of 2015. The Ocean Winner, Ocean Saratoga, Ocean Worker and Ocean Yorktown were sold for scrap in the second quarter of 2015 and the Ocean Lexington was sold for scrap in the third quarter of 2015. |
Overview
Three Months Ended September 30, 2015 and 2014
Operating Income. Operating income for the third quarter of 2015 increased $91.0 million compared to the same period of 2014, primarily due to the absence of a $109.5 million impairment loss recognized in the third quarter of 2014, partially offset by higher depreciation expense ($9.2 million) in the 2015 period.
Contract drilling revenue for our mid-water and jack-up fleets decreased $188.5 million and $28.7 million, respectively, during the third quarter of 2015 compared to the prior year period, primarily as a result of 733 and 285 fewer revenue earning days, respectively, representing the deterioration in two of the rig markets most negatively impacted by the continued downturn in demand for contract drilling services. In contrast, contract drilling revenue earned by our ultra-deepwater and deepwater floaters increased $63.1 million and $25.3 million, respectively, during the current year quarter, compared to the third quarter of 2014, primarily due to an aggregate 214-day increase in revenue earning days, including the operation of two of our newbuild drillships that commenced drilling operations in 2015, partially offset by lower average daily revenue earned by our ultra-deepwater fleet.
32
Total contract drilling expense decreased $121.9 million during the third quarter of 2015, compared to the same quarter of 2014, reflecting lower overall operating costs, primarily for labor and personnel ($54.4 million), repairs and maintenance ($30.6 million) and inspections ($7.7 million) as a result of cost control measures and reduced costs associated with idled and cold-stacked or retired rigs.
Impairment of Assets. During the third quarter of 2014, our management adopted a plan to scrap six of our mid-water semisubmersible rigs, all of which have been sold. As a result of this decision, we recognized an impairment loss of $109.5 million during the prior year quarter to write down the aggregate net book value of these rigs to their estimated recoverable amounts. During the third quarter of 2015, we recognized an aggregate impairment loss of $2.6 million based on our decision to sell an additional three rigs in the near term. See Critical Accounting Estimates Impairment of Long-Lived Assets and Notes 1 and 2 to our unaudited consolidated financial statements included in Item 1 of Part I of this report.
Interest Expense, Net of Amounts Capitalized. Interest expense increased $12.0 million during the third quarter of 2015, compared to the same period in 2014, primarily as a result of a reduction in interest capitalized in the current year quarter ($13.8 million) due to the completion of qualifying construction projects in 2014 and in the second quarter of 2015, combined with higher interest expense associated with uncertain tax positions ($2.7 million). These unfavorable factors were partially offset by a $4.5 million reduction in interest expense in the current year quarter due to the repayment of two tranches of our senior notes in September 2014 and July 2015.
Income Tax Expense. Our effective tax rate for the three months ended September 30, 2015 was 14.6%, compared to a 35.5% effective tax rate for the three months ended September 30, 2014. The effective tax rate in the 2015 period was lower than in the same period of 2014 primarily as a result of our $109.5 million asset impairment in the 2014 period (the majority of which related to rigs owned by our foreign subsidiary for which no tax benefit was recognized) and higher U.K. income taxes associated with the July 2014 enactment of the U.K. Finance Act of 2014, which was partially offset by the reversal of $31.2 million of reserves in 2014 for uncertain tax positions in various foreign jurisdictions. In the 2015 period we reversed $7.0 million of reserves for uncertain tax positions associated with the expiration of the statute of limitations.
Nine Months Ended September 30, 2015 and 2014
Operating Income. Our operating income decreased $364.4 million during the first nine months of 2015, compared to the same period of 2014, reflective of lower operating results for our combined floater fleet and jack-up rigs, additional impairment losses recognized in 2015 ($251.6 million), higher depreciation expense ($53.9 million) and $8.7 million in restructuring and severance costs recognized in 2015. Depreciation expense increased during the first nine months of 2015, compared to the same period in 2014, primarily due to a higher depreciable asset base in 2015, including the Ocean Apex and three newbuild drillships, which were placed in service after the third quarter of 2014, partially offset by the absence of depreciation for our rigs that were impaired or sold during late 2014 and in 2015.
Total contract drilling revenue declined $246.7 million, or 12%, during the first nine months of 2015 compared to the same period in 2014, primarily due to a $566.5 million decrease in revenue earned by our combined mid-water and jack-up fleets, partially offset by an aggregate $319.8 million increase in revenue earned by our ultra-deepwater and deepwater floaters. Our results for the first nine months of 2015 reflected an aggregate 1,958 fewer revenue earning days, compared to the first nine months of 2014, primarily, due to the cold stacking and sale of rigs and incremental downtime between contracts for several of our rigs, partially offset by incremental revenue generating days for our newly constructed and upgraded or enhanced rigs.
Total contract drilling expense for the first nine months of 2015 decreased $193.5 million, or 17%, compared to the prior year period, primarily as a result of lower rig utilization, including the impact of cold stacked and retired rigs, as well as cost control efforts. Lower contract drilling expense during the first nine months of 2015, compared to the first nine months of 2014, reflects lower costs for labor and personnel ($105.5 million), repairs and maintenance ($60.3 million), inspections ($13.7 million), freight ($8.8 million) and rig insurance ($7.1 million) and a net decrease in other rig operating, shorebase support and overhead costs ($34.0 million), partially offset by higher rig mobilization costs ($35.9 million).
Impairment of Assets. During the third quarter of 2014, our management adopted a plan to scrap six of our mid-water semisubmersibles and, as a result, we recognized an impairment loss of $109.5 million in September 2014. In 2015, due to the continued deterioration of the market fundamentals in the oil and gas industry, among other factors, we determined that the carrying values of our 7,875-foot water depth rated drillship, the Ocean Clipper, seven of our mid-water floaters and one jack-up rig were impaired and recorded an aggregate impairment loss of $361.1 million during the first nine months of 2015. See Critical Accounting Estimates Impairment of Long-Lived Assets and Note 2 to our unaudited consolidated financial statements included in Item 1 of Part I of this report.
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Restructuring and Separation Costs. In response to the continued decline in the offshore drilling market, we have reviewed our cost and organization structure. As a result, our management approved and initiated a reduction in workforce at our onshore bases and corporate facilities. During the nine months ended September 30, 2015, we recognized $8.7 million in restructuring and employee separation related costs on behalf of separated employees.
Interest Expense, Net of Amounts Capitalized. Interest expense increased $24.7 million during the nine-month period ended September 30, 2015, compared to the same period in 2014, primarily as a result of a reduction in interest capitalized during the first nine months of 2015 ($34.1 million) due to the completion of five qualifying projects in 2014 and 2015. These unfavorable factors were partially offset by an $11.6 million reduction in interest expense for the first nine months of 2015 due to the repayment of two tranches of our senior notes in September 2014 and July 2015.
Income Tax Expense. Our effective tax rate for the nine months ended September 30, 2015 was (35.5)%, compared to a 20.4% effective tax rate for the nine months ended September 30, 2014. The effective tax rate in the 2015 period was lower than in the same period of 2014 primarily due to the mix of our domestic and international pre-tax earnings and losses, including asset impairments taken during both 2015 and 2014 in various jurisdictions with differing tax consequences.
Contract Drilling Revenue and Expense by Equipment Type
Three Months Ended September 30, 2015 and 2014
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $63.1 million during the third quarter of 2015, compared to the same quarter of 2014, primarily as a result of 148 incremental revenue earning days ($72.7 million), partially offset by the effect of lower average daily revenue earned ($9.6 million). The increase in revenue earning days in the third quarter of 2015 was primarily attributable to incremental revenue earning days for our two newbuild drillships placed in service in the fourth quarter of 2014, partially offset by a decrease in revenue earning days for the cold-stacked Ocean Baroness, whose contract was canceled in the second quarter of 2015.
Contract drilling expense for our ultra-deepwater floaters remained relatively unchanged, decreasing $1.5 million during the third quarter of 2015, compared to the same period of 2014. Incremental contract drilling expense for our two newbuild drillships ($38.2 million) was partially offset by lower operating costs for our other ultra-deepwater floaters, including labor and personnel ($16.2 million) and maintenance and inspections ($17.8 million) due to our cost control efforts in 2015.
Deepwater Floaters. Revenue generated by our deepwater floaters increased $25.3 million in the third quarter of 2015, compared to the same quarter in 2014, primarily due to 66 incremental revenue earning days ($23.3 million) combined with the effect of higher average daily revenue earned ($2.0 million). Revenue earning days for the third quarter of 2015 increased primarily due to less unplanned downtime between contracts (139 incremental operating days), partially offset by fewer operating days for the cold-stacked Ocean Star (52 fewer days) and incremental unplanned downtime for repairs (21 fewer days).
Contract drilling expense incurred by our deepwater floaters decreased $4.7 million during the third quarter of 2015, compared to the same period of 2014, primarily due to a reduction in contract drilling expense for the Ocean Star ($12.0 million). The cost reductions in the third quarter of 2015 were partially offset by higher contract drilling expense for our other actively marketed deepwater rigs, primarily for labor and personnel costs ($4.5 million) and rig mobilization ($5.5 million) and included incremental expense for rigs that were idle during the prior year quarter.
Mid-Water Floaters. Revenue generated by our mid-water floaters during the third quarter of 2015 decreased $188.5 million compared to the same quarter in 2014, primarily due to 733 fewer revenue earning days ($194.2 million). Comparing the periods, revenue earning days declined as a result of fewer revenue earning days for cold-stacked and retired rigs (713 fewer days) and incremental downtime between contracts (123 fewer days) during the third quarter of 2015, partially offset by incremental revenue earning days for the recently upgraded Ocean Patriot, which resumed operations in the fourth quarter of 2014 (91 incremental days).
Contract drilling expense for our mid-water floaters decreased $96.6 million in the third quarter of 2015, compared to the prior year quarter, primarily due to reduced operating costs for our non-operating rigs, including our cold-stacked and retired mid-water rigs ($105.0 million), partially offset by incremental contract drilling expense for the Ocean Patriot ($10.8 million).
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Jack-ups. Contract drilling revenue for our jack-up fleet decreased $28.7 million during the third quarter of 2015, compared to the prior year quarter, primarily due to the cold stacking of rigs ($23.1 million) combined with the negative impact of negotiated dayrate reductions for our two rigs that operated during the period. Contract drilling expense for the third quarter of 2015 declined $15.5 million, primarily due to reduced costs for our cold-stacked rigs.
Nine Months Ended September 30, 2015 and 2014
Ultra-Deepwater Floaters. Revenue generated by our ultra-deepwater floaters increased $241.7 million during the first nine months of 2015, compared to the same period of 2014, primarily as a result of 375 incremental revenue earning days ($167.4 million), combined with higher average daily revenue earned ($74.2 million). Total revenue earning days increased during the first nine months of 2015, primarily due to incremental revenue earning days for our three newbuild drillships, which were placed in service during 2014 (431 additional days), and the Ocean Endeavor operating offshore Romania (150 additional days), partially offset by fewer revenue earning days for the Ocean Confidence due to its service-life extension project (90 fewer days) and the Ocean Baroness as a result of operational issues and the subsequent cold stacking of the rig (154 fewer days). Average daily revenue increased during the first nine months of 2015, compared to the prior year period, primarily due to revenue associated with incremental operations for the Ocean Endeavor in Romania, a contract extension for the Ocean Rover at a higher dayrate than previously earned and a dayrate adjustment for the Ocean Courage, combined with the operation of two additional drillships in the 2015 period.
Contract drilling expense for our ultra-deepwater floaters increased $68.6 million during the first nine months of 2015, compared to the same period of 2014, reflecting incremental contract drilling expense for our newbuild drillships ($100.7 million) and the Ocean Endeavor ($13.2 million), partially offset by lower costs for labor and personnel ($34.7 million), rig mobilization and inspections ($7.7 million) and other rig operating costs ($2.9 million) for our other ultra-deepwater floaters.
Deepwater Floaters. Revenue generated by our deepwater floaters increased $78.1 million in the first nine months of 2015, compared to the same period in 2014, primarily due to 129 incremental revenue earning days ($51.8 million) in the current year period combined with higher average daily revenue earned ($26.2 million). The increase in revenue earning days during the first nine months of 2015 resulted from the return to service of several rigs in this market after prolonged periods in shipyards for upgrades and surveys and warm-stacking between contracts (416 incremental days), partially offset by fewer revenue earning days due to the cold stacking of the Ocean Star (233 days) and additional non-revenue earning days for rig mobilization and repairs (54 additional days). Average daily revenue earned for the first nine months of 2015 increased compared to the prior year period, primarily due to incremental amortization of $19.2 million in mobilization and contract preparation fees and inclusion of revenue earned by the Ocean Apex.
Contract drilling expense for our deepwater floaters decreased an aggregate $8.2 million during the first nine months of 2015, compared to the same period of 2014, primarily due to reduced operating costs for the Ocean Star ($23.8 million) and the absence of costs associated with a 2014 five-year survey and shipyard project for the Ocean Alliance ($22.7 million). These cost reductions were partially offset by incremental operating costs for the Ocean Apex ($22.0 million) and higher rig mobilization costs ($21.3 million) in the 2015 period.
Mid-Water Floaters. Revenue generated by our mid-water floaters decreased $502.1 million in the first nine months of 2015, compared to the same period in 2014, primarily due to 1,857 fewer revenue earning days ($504.5 million), partially offset by higher average daily revenue earned ($2.4 million). The reduction in revenue earning days during the first nine months of 2015 was the result of the cold stacking or retirement of twelve of our mid-water rigs (2,140 fewer days), partially offset by incremental revenue earning days for the Ocean Patriot (272 additional days).
Contract drilling expense for our mid-water floaters decreased $213.5 million in the first nine months of 2015, compared to the prior year period, primarily due to reduced operating costs for our cold-stacked or retired mid-water rigs ($246.5 million), partially offset by incremental costs for the Ocean Patriot ($35.5 million).
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Jack-ups. Contract drilling revenue and expense for our jack-up fleet decreased $64.3 million and $31.0 million, respectively, during the first nine months of 2015, compared to the prior year period, primarily due to the cold stacking of four rigs that were operating under contract in 2014. Contract drilling revenue for the first nine months of 2015 was also negatively impacted by negotiated dayrate reductions in 2015 for two or our rigs.
Liquidity and Capital Resources
We currently have available a syndicated revolving credit agreement, or Revolving Credit Facility, to meet our short-term and long-term liquidity needs. See Revolving Credit Facility, Senior Notes and Commercial Paper Program.
At September 30, 2015 and December 31, 2014, we had cash available for current operations as follows:
September 30, | December 31, | |||||||
2015 | 2014 | |||||||
(In thousands) | ||||||||
Cash and equivalents |
$ | 141,131 | $ | 233,623 | ||||
Marketable securities |
13,621 | 16,033 | ||||||
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Total cash available for current operations |
$ | 154,752 | $ | 249,656 | ||||
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As of October 1, 2015, our contract drilling backlog was approximately $5.7 billion, of which approximately $0.5 billion is expected to be realized by the end of 2015.
Historically, a substantial portion of our cash flows has been invested in the enhancement of our drilling fleet. We determine the amount of cash required to meet our capital commitments by evaluating our rig construction obligations, the need to upgrade rigs to meet specific customer requirements and our ongoing rig equipment enhancement/replacement programs.
Certain of our international rigs are owned and operated, directly or indirectly, by our wholly-owned subsidiary Diamond Offshore International Limited, or DOIL, and, as a result of our intention to indefinitely reinvest the earnings of DOIL to finance our foreign activities, we do not expect such earnings to be available for distribution to our stockholders or to finance our domestic activities. To the extent available, we expect to utilize the operating cash flows generated by and cash reserves of DOIL and the operating cash flows available to and cash reserves of Diamond Offshore Drilling, Inc. to meet each entitys respective working capital requirements and capital commitments. We expect to continue to make use of our Revolving Credit Facility or commercial paper program to finance our capital expenditures and working capital requirements in the near term. In addition, we will make periodic assessments of our capital spending programs based on industry conditions and make adjustments thereto if we determine that they are required. See Cash Flow, Capital Expenditures and Contractual Obligations Contractual Cash Obligations Rig Construction and Revolving Credit Facility, Senior Notes and Commercial Paper Program.
We pay dividends at the discretion of our Board of Directors, or Board. During the nine-month period ended September 30, 2015, we paid cash dividends totaling $51.4 million. During the nine-month period ended September 30, 2014, we paid regular and special cash dividends totaling $51.7 million and $313.6 million, respectively. Our Board has adopted a policy of considering paying regular and special cash dividends, in amounts to be determined, on a quarterly basis. Any determination to declare a dividend, as well as the amount of any dividend that may be declared, will be based on the Boards consideration of our financial position, earnings, earnings outlook, capital spending plans, outlook on current and future market conditions and business needs and other factors that our Board considers relevant at that time. Our dividend policy may change from time to time, and there can be no assurance that we will continue to declare any cash dividends at all or in any particular amounts.
On October 30, 2015, we declared a regular cash dividend of $0.125 per share of our common stock, which is payable on December 1, 2015 to stockholders of record on November 13, 2015.
Depending on market and other conditions, we may, from time to time, purchase shares of our common stock in the open market or otherwise. We did not purchase any shares of our outstanding common stock during the nine-month period ended September 30, 2015. However, during the nine-month period ended September 30, 2015, in connection with the vesting of restricted stock units held by our chief executive officer, we withheld 7,810 shares of common stock, with a cost of $0.2 million, to satisfy the associated payroll tax obligation. During the nine-month period ended September 30, 2014, we purchased 1,895,561 shares of our common stock at an aggregate cost of $87.8 million.
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In addition, Loews Corporation, or Loews, has informed us that, depending on market and other conditions, it may, from time to time, purchase shares of our common stock in the open market or otherwise. During the nine-month period ended September 30, 2015, Loews purchased 1,134,827 shares of our common stock in the open market. Loews did not purchase any shares of our outstanding common stock during the nine-month period ended September 30, 2014.
Our primary source of cash during the nine-month period ended September 30, 2015, was an aggregate $466.7 million generated from operating activities, $493.0 million from short-term borrowings under our commercial paper program and $8.4 million from the disposition of assets, including $5.4 million in proceeds from the sale of eight mid-water floaters for scrap during the period. Our primary uses of cash during the same period were $758.3 million towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program, including payment of the final construction installment for the Ocean BlackLion, $250.0 million for the repayment of debt and $52.3 million for the payment of dividends and anti-dilution adjustments to stock plan participants. See Revolving Credit Facility, Senior Notes and Commercial Paper Program Commercial Paper Program.
For the nine-month period ended September 30, 2014, our primary source of cash was an aggregate $682.8 million generated from operating activities, $1.2 billion in proceeds, primarily from the maturity of marketable securities, net of purchases, and $16.8 million from the disposition of assets, primarily from the sale of the Ocean Spartan in June 2014. Our primary uses of cash during the same period were $1.0 billion towards the construction of new rigs and our ongoing rig equipment enhancement/replacement program, $365.3 million for the payment of dividends, $250.0 million for the repayment of debt and $87.8 million for the repurchase of shares.
We may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control.
Cash Flow, Capital Expenditures and Contractual Obligations
Our cash flow from operations and capital expenditures for the nine-month periods ended September 30, 2015 and 2014 were as follows:
Nine Months Ended September 30, |
||||||||
2015 | 2014 | |||||||
(In thousands) | ||||||||
Cash flow from operations |
$ | 466,677 | $ | 682,836 | ||||
Cash capital expenditures: |
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Drillship construction |
$ | 416,095 | $ | 520,385 | ||||
Construction of deepwater floaters |
34,632 | 118,006 | ||||||
Construction of ultra-deepwater floater |
37,129 | 11,767 | ||||||
Ocean Patriot enhancement project |
1,349 | 91,360 | ||||||
Ocean Confidence service-life extension project |
74,956 | 87,895 | ||||||
Rig equipment and replacement programs |
194,181 | 194,912 | ||||||
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Total capital expenditures |
$ | 758,342 | $ | 1,024,325 | ||||
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Cash Flow
Cash flow from operations decreased approximately $216.2 million during the first nine months of 2015, compared to the first nine months of 2014, primarily due to lower cash receipts from contract drilling services ($333.3 million), partially offset by a $107.8 million net decrease in cash payments for contract drilling and general and administrative expenses, including personnel-related, maintenance, mobilization and other rig operating costs.
Capital Expenditures
As of the date of this report, we expect our capital spending for 2015 to aggregate approximately $920.0 million, of which we expect to spend approximately $630.0 million on our current rig construction projects, including the Ocean Confidence service-life-extension project. During the first nine months of 2015, we incurred $528.3 million in project-related expenditures, including accrued expenditures. See Contractual Cash
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Obligations Rig Construction. Our 2015 capital spending program also includes an estimated $280.0 million for our ongoing capital maintenance and replacement programs, of which $167.9 million had been incurred as of September 30, 2015.
Contractual Cash Obligations Rig Construction
As of the date of this report, we have one rig, the Ocean GreatWhite, under construction in Ulsan, South Korea, for which we are obligated under a construction agreement with Hyundai Heavy Industries Co., Ltd. Construction of the Ocean GreatWhite continues with delivery expected in the second quarter of 2016. The estimated total project cost, including shipyard costs, capital spares, commissioning, project management and shipyard supervision, is $764.0 million, of which $225.7 million has been incurred as of September 30, 2015. See Note 11 Commitments and Contingencies to our unaudited consolidated financial statements included in Item 1 of Part I of this report for more information about this project.
We had no other purchase obligations for major rig upgrades or any other significant obligations at September 30, 2015, except for those related to our direct rig operations, which arise during the normal course of business.
Other Obligations
As of September 30, 2015, the total unrecognized tax benefits related to uncertain tax positions was $49.5 million. In addition, we have recorded a liability, as of September 30, 2015, for potential penalties and interest of $39.4 million and $3.9 million, respectively. 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.
Revolving Credit Facility, Senior Notes and Commercial Paper Program
Revolving Credit Facility
Effective October 22, 2015, we entered into an extension agreement and fourth amendment to our Revolving Credit Facility which, among other things, provides for a one-year extension of the maturity date for most of the lenders. As so extended, our Revolving Credit Facility provides for a $1.5 billion senior unsecured revolving credit facility for general corporate purposes, maturing on October 22, 2020, except for $40 million of commitments that mature on March 17, 2019 and $60 million of commitments that mature on October 22, 2019. We also have the option to increase the revolving commitments under the Revolving Credit Facility by up to an additional $500 million from time to time, upon receipt of additional commitments from new or existing lenders, and to request one additional one-year extension of the maturity date. The entire amount of the facility is available, subject to its terms, for revolving loans. Up to $250 million of the facility may be used for the issuance of performance or other standby letters of credit and up to $100 million may be used for swingline loans. As of September 30, 2015, there were no loans or letters of credit outstanding under the Revolving Credit Facility, and we were in compliance with all covenant requirements under the Revolving Credit Facility. See Commercial Paper Program.
Senior Notes
On July 1, 2015, we repaid $250.0 million in aggregate principal amount of our 4.875% Senior Notes due July 1, 2015, primarily with funds obtained through the issuance of additional commercial paper.
Commercial Paper Program
In 2015, we established a commercial paper program with four commercial paper dealers pursuant to which we may issue, on a private placement basis, unsecured commercial paper notes up to a maximum aggregate amount outstanding at any time of $1.5 billion. Proceeds from issuances under the commercial paper program may be used for general corporate purposes. The maturities of the notes may vary, but may not exceed 397 days from the date of issuance. The notes will be issued, at our option, either at a discounted price to their principal face value or will bear interest, which may be at a fixed or floating rate, at rates that will vary based on market conditions and the ratings assigned by credit rating agencies at the time of issuance. The notes are not redeemable or subject to voluntary prepayment by us prior to maturity. Our Revolving Credit Facility provides liquidity for our payment obligations in respect of the notes issued under the commercial paper program, and the aggregate amount of notes outstanding at any time will not exceed the amount available under the Revolving Credit Facility. As of September 30, 2015, we had $493.0 million in commercial paper notes outstanding with a weighted average interest rate of 0.44% and a weighted average remaining term of two days.
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We continually assess our working capital availability and requirements and reevaluate our aggregate commercial paper position based on daily net working capital activity and short and long-term cash requirements, including the repayment of debt and our capital spending program. We expect to issue additional commercial paper, as necessary, to meet short-term liquidity needs, and to reduce our aggregate commercial paper position, as excess operating cash flow allows, maintaining our financial flexibility. However, we expect our short-term borrowings to increase over the next 12 months.
As of October 29, 2015, we had an additional $1.1 billion available under the Revolving Credit Facility to provide liquidity for our payment obligations with respect to the issuance of commercial paper.
Credit Ratings
In October 2015, Moodys Investors Services, or Moodys lowered our corporate credit and unsecured debt rating from A3 to Baa2 and revised its outlook on us to negative. Our current credit rating is BBB+ for Standard & Poors Ratings Services, or S&P. In February 2015, Moodys and S&P assigned short-term credit ratings of Prime-2 and A2, respectively, to our commercial paper program. In October 2015, Moodys affirmed our short-term credit rating of Prime-2. Market conditions and other factors, many of which are outside of our control, could cause our credit ratings to be lowered. A downgrade in our credit ratings could adversely impact our cost of issuing additional debt and the amount of additional debt that we could issue. A series of downgrades or a substantial downgrade could restrict our access to our commercial paper program and capital markets and our ability to raise additional debt or rollover existing maturities. As a consequence, we may not be able to issue additional debt in amounts and/or with terms that we consider to be reasonable. One or more of these occurrences could limit our ability to pursue other business opportunities.
Other Commercial Commitments Letters of Credit
We were contingently liable as of September 30, 2015 in the amount of $71.3 million under certain performance, bid, security, tax, supersedeas and customs bonds and letters of credit. Agreements relating to approximately $63.7 million of performance, security, tax, supersedeas and customs bonds can require collateral at any time. As of September 30, 2015, we had not been required to make any collateral deposits with respect to these agreements. The remaining agreements cannot require collateral except in events of default. Banks have issued letters of credit on our behalf securing certain of these bonds. The table below provides a list of these obligations in U.S. dollar equivalents and their time to expiration.
For the Years Ending December 31, | ||||||||||||||||||||
Total | 2015 | 2016 | 2017 | 2018 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Other Commercial Commitments |
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Performance bonds |
$ | 51,357 | $ | | $ | 6,122 | $ | 26,110 | $ | 19,125 | ||||||||||
Supersedeas bond |
9,189 | 9,189 | | | | |||||||||||||||
Bid bonds |
2,470 | | 2,470 | | | |||||||||||||||
Tax bond |
5,952 | | 5,952 | | | |||||||||||||||
Other |
2,348 | 1,339 | 1,009 | | | |||||||||||||||
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Total obligations |
$ | 71,316 | $ | 10,528 | $ | 15,553 | $ | 26,110 | $ | 19,125 | ||||||||||
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Off-Balance Sheet Arrangements
At September 30, 2015 and December 31, 2014, we had no off-balance sheet debt or other off-balance sheet arrangements.
Recent Accounting Pronouncements
See Note 1 General Information to our unaudited consolidated financial statements included in Item 1 of Part I of this report for a discussion of recently issued accounting pronouncements.
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press releases or otherwise, make or incorporate by reference certain written or oral statements that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of
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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, may, might, will, will be, will continue, will likely result, project, forecast, budget and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:
| market conditions and the effect of such conditions on our future results of operations; |
| sources and uses of and requirements for financial resources; |
| availability under our Revolving Credit Facility and issuance of notes under our commercial paper program; |
| interest rate and foreign exchange risk; |
| contractual obligations; |
| operations outside the United States; |
| business strategy; |
| growth opportunities; |
| competitive position; |
| expected financial position; |
| cash flows and contract backlog; |
| declaration or payment of regular or special dividends; |
| financing plans; |
| market outlook; |
| tax planning, examinations, assessments and audits; |
| debt levels, credit ratings, the impact of changes in the credit markets and credit ratings for our debt and our ability to access capital markets; |
| budgets for capital and other expenditures; |
| timing and duration of required regulatory inspections for our drilling rigs; |
| timing and cost of completion of rig upgrades, construction projects and other capital projects; |
| delivery dates and drilling contracts related to rig conversion or upgrade projects, construction projects, other capital projects or rig acquisitions; |
| plans and objectives of management; |
| idling drilling rigs or reactivating stacked rigs; |
| scrapping retired rigs; |
| assets held for sale; |
| asset impairments and impairment evaluations and any future use or disposition of impaired assets; |
| competitive newbuild drilling rigs on order; |
| effective date and performance of contracts; |
| outcomes of legal proceedings; |
| compliance with applicable laws; and |
| availability, limits and adequacy of insurance or indemnification. |
These types of statements are based on current expectations about future events and inherently are subject to a variety of assumptions, risks and uncertainties, many of which are beyond our control, that could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. These risks and uncertainties include, among others, the following:
| those described under Risk Factors in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2014; |
| general economic and business conditions; |
| worldwide demand for oil and natural gas; |
| changes in foreign and domestic oil and gas exploration, development and production activity; |
| oil and natural gas price fluctuations and related market expectations; |
| the ability of the Organization of Petroleum Exporting Countries, commonly called OPEC, to set and maintain production levels and pricing, and the level of production in non-OPEC countries; |
| policies of various governments regarding exploration and development of oil and gas reserves; |
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| our inability to obtain contracts for our rigs that do not have contracts; |
| the cancellation or renegotiation of contracts included in our reported contract backlog; |
| advances in exploration and development technology; |
| the worldwide political and military environment, including, for example, in oil-producing regions and locations where our rigs are operating or where we have rigs under construction, in shipyards or stacked; |
| casualty losses; |
| operating hazards inherent in drilling for oil and gas offshore; |
| the risk that future regular or special dividends may not be declared or paid; |
| the risk of physical damage to rigs and equipment caused by named windstorms in the GOM; |
| industry fleet capacity, including, without limitation, construction of new drilling rig capacity in Brazil; |
| market conditions in the offshore contract drilling industry, including, without limitation, dayrates and utilization levels; |
| competition; |
| changes in foreign, political, social and economic conditions; |
| risks of international operations, compliance with foreign laws and taxation policies and seizure, expropriation, nationalization, deprivation, malicious damage or other loss of possession or use of equipment and assets; |
| risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time; |
| customer or supplier bankruptcy or liquidation; |
| the ability of customers and suppliers to meet their obligations to us and our subsidiaries; |
| collection of receivables; |
| the risk that a letter of intent may not result in a definitive agreement; |
| foreign exchange and currency fluctuations and regulations, and the inability to repatriate income or capital; |
| risks of war, military operations, other armed hostilities, terrorist acts and embargoes; |
| changes in offshore drilling technology, which could require significant capital expenditures in order to maintain competitiveness; |
| regulatory initiatives and compliance with governmental regulations including, without limitation, regulations pertaining to climate change, greenhouse gases, carbon emissions or energy use; |
| compliance with and liability under environmental laws and regulations; |
| potential changes in accounting policies by the Financial Accounting Standards Board, the Securities and Exchange Commission, or SEC, or regulatory agencies for our industry which may cause us to revise our financial accounting and/or disclosures in the future, and which may change the way analysts measure our business or financial performance; |
| development and exploitation of alternative fuels; |
| customer preferences; |
| effects of litigation, tax audits and contingencies and the impact of compliance with judicial rulings and jury verdicts; |
| cost, availability, limits and adequacy of insurance; |
| invalidity of assumptions used in the design of our controls and procedures; |
| the results of financing efforts; |
| adequacy and availability of our sources of liquidity; |
| risks resulting from our indebtedness; |
| public health threats; |
| negative publicity; |
| impairments of assets; |
| the availability of qualified personnel to operate and service our drilling rigs; and |
| various other matters, many of which are beyond our control. |
The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the SEC include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based.
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ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
There were no material changes in our market risk components for the nine months ended September 30, 2015. See Quantitative and Qualitative Disclosures About Market Risk included in Item 7A of our Annual Report on Form 10-K filed with the Securities and Exchange Commission for the year ended December 31, 2014 for further information.
ITEM 4. Controls and Procedures.
We maintain a system of disclosure controls and procedures which are designed to ensure that information required to be disclosed by us in reports that we file or submit under the federal securities laws, including this report, is recorded, processed, summarized and reported on a timely basis. These disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by us under the federal securities laws is accumulated and communicated to our management on a timely basis to allow decisions regarding required disclosure.
Our Chief Executive Officer, or CEO, and Chief Financial Officer, or CFO, participated in an evaluation by our management of the effectiveness of our disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) as of September 30, 2015. Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure controls and procedures were effective as of September 30, 2015.
There were no changes in our internal control over financial reporting identified in connection with the foregoing evaluation that occurred during our third fiscal quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
See the Exhibit Index for a list of those exhibits filed or furnished herewith.
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DIAMOND OFFSHORE DRILLING, INC. (Registrant) | ||||
Date November 2, 2015 | By: | \s\ Gary T. Krenek | ||
Gary T. Krenek | ||||
Senior Vice President and Chief Financial Officer | ||||
Date November 2, 2015 | \s\ Beth G. Gordon | |||
Beth G. Gordon | ||||
Controller (Chief Accounting Officer) |
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Exhibit No. |
Description | |
3.1 | Amended and Restated Certificate of Incorporation of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2003) (SEC File No. 1-13926). | |
3.2 | Amended and Restated By-laws (as amended through October 4, 2013) of Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current Report on Form 8-K filed October 8, 2013). | |
10.1* | Extension Agreement and Amendment No. 4 to Credit Agreement, dated as of October 22, 2015, among Diamond Offshore Drilling, Inc., Wells Fargo Bank, National Association, as administrative agent and swingline lender, the issuing banks named therein and the lenders named therein. | |
31.1* | Rule 13a-14(a) Certification of the Chief Executive Officer. | |
31.2* | Rule 13a-14(a) Certification of the Chief Financial Officer. | |
32.1* | Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer. | |
101.INS* | XBRL Instance Document. | |
101.SCH* | XBRL Taxonomy Extension Schema Document. | |
101.CAL* | XBRL Taxonomy Calculation Linkbase Document. | |
101.LAB* | XBRL Taxonomy Label Linkbase Document. | |
101.PRE* | XBRL Presentation Linkbase Document. | |
101.DEF* | XBRL Definition Linkbase Document. |
* | Filed or furnished herewith. |
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