Attached files
file | filename |
---|---|
EX-32.1 - EX-32.1 - DIAMOND OFFSHORE DRILLING, INC. | h70194exv32w1.htm |
EX-31.2 - EX-31.2 - DIAMOND OFFSHORE DRILLING, INC. | h70194exv31w2.htm |
EX-31.1 - EX-31.1 - DIAMOND OFFSHORE DRILLING, INC. | h70194exv31w1.htm |
EXCEL - IDEA: XBRL DOCUMENT - DIAMOND OFFSHORE DRILLING, INC. | Financial_Report.xls |
Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
þ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended March 31, 2010
OR
o | 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 | (I.R.S. Employer | |
or organization) | Identification No.) |
15415 Katy Freeway
Houston, Texas
77094
(Address of principal executive offices)
(Zip Code)
(281) 492-5300
(Registrants telephone number, including area code)
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 þ No o
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 þ No o
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 þ | Accelerated filer o | Non-accelerated filer o | Smaller reporting company o | |||
(Do not check if a 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 o No þ
Indicate the number of shares outstanding of each of the issuers classes of common stock, as
of the latest practicable date.
As of April 22, 2010 Common stock, $0.01 par value per share 139,026,178 shares
DIAMOND OFFSHORE DRILLING, INC.
TABLE OF CONTENTS FOR FORM 10-Q
QUARTER ENDED MARCH 31, 2010
PAGE NO. | ||||||||
COVER PAGE |
1 | |||||||
TABLE OF CONTENTS |
2 | |||||||
3 | ||||||||
3 | ||||||||
4 | ||||||||
5 | ||||||||
6 | ||||||||
18 | ||||||||
33 | ||||||||
35 | ||||||||
35 | ||||||||
35 | ||||||||
36 | ||||||||
37 | ||||||||
EX-31.1 | ||||||||
EX-31.2 | ||||||||
EX-32.1 | ||||||||
EX-101 INSTANCE DOCUMENT | ||||||||
EX-101 SCHEMA DOCUMENT | ||||||||
EX-101 CALCULATION LINKBASE DOCUMENT | ||||||||
EX-101 LABELS LINKBASE DOCUMENT | ||||||||
EX-101 PRESENTATION LINKBASE DOCUMENT |
Table of Contents
PART I. FINANCIAL INFORMATION
ITEM 1. Financial Statements.
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In thousands, except per share data)
(Unaudited)
(In thousands, except per share data)
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
ASSETS |
||||||||
Current assets: |
||||||||
Cash and cash equivalents |
$ | 306,054 | $ | 376,417 | ||||
Marketable securities |
650,756 | 400,853 | ||||||
Accounts receivable, net of provision for bad debts |
797,932 | 791,023 | ||||||
Prepaid expenses and other current assets |
146,913 | 155,077 | ||||||
Total current assets |
1,901,655 | 1,723,370 | ||||||
Drilling and other property and equipment, net of
accumulated depreciation |
4,414,387 | 4,432,052 | ||||||
Other assets |
408,761 | 108,839 | ||||||
Total assets |
$ | 6,724,803 | $ | 6,264,261 | ||||
LIABILITIES AND STOCKHOLDERS EQUITY |
||||||||
Current liabilities: |
||||||||
Accounts payable |
$ | 67,250 | $ | 75,015 | ||||
Payable for purchase of marketable securities |
99,989 | | ||||||
Accrued liabilities |
292,644 | 301,871 | ||||||
Taxes payable |
360,628 | 32,410 | ||||||
Current portion of long-term debt |
4,215 | 4,179 | ||||||
Total current liabilities |
824,726 | 413,475 | ||||||
Long-term debt |
1,495,428 | 1,495,375 | ||||||
Deferred tax liability |
540,669 | 546,024 | ||||||
Other liabilities |
220,837 | 178,745 | ||||||
Total liabilities |
3,081,660 | 2,633,619 | ||||||
Commitments and contingencies (Note 10) |
| | ||||||
Stockholders equity: |
||||||||
Common stock (par value $0.01, 500,000,000 shares authorized,
143,942,978 shares issued and 139,026,178 shares outstanding
at March 31, 2010 and December 31, 2009) |
1,439 | 1,439 | ||||||
Additional paid-in capital |
1,967,451 | 1,965,513 | ||||||
Retained earnings |
1,788,013 | 1,776,498 | ||||||
Accumulated other comprehensive gain |
653 | 1,605 | ||||||
Treasury stock, at cost (4,916,800 shares at March 31, 2010
and December 31, 2009) |
(114,413 | ) | (114,413 | ) | ||||
Total stockholders equity |
3,643,143 | 3,630,642 | ||||||
Total liabilities and stockholders equity |
$ | 6,724,803 | $ | 6,264,261 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
3
Table of Contents
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(Unaudited)
(In thousands, except per share data)
(Unaudited)
(In thousands, except per share data)
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
Revenues: |
||||||||
Contract drilling |
$ | 844,438 | $ | 855,708 | ||||
Revenues related to reimbursable expenses |
15,243 | 30,012 | ||||||
Total revenues |
859,681 | 885,720 | ||||||
Operating expenses: |
||||||||
Contract drilling |
305,127 | 297,747 | ||||||
Reimbursable expenses |
14,705 | 29,715 | ||||||
Depreciation |
97,402 | 85,062 | ||||||
General and administrative |
16,654 | 16,315 | ||||||
Gain on disposition of assets |
(884 | ) | (55 | ) | ||||
Total operating expenses |
433,004 | 428,784 | ||||||
Operating income |
426,677 | 456,936 | ||||||
Other income (expense): |
||||||||
Interest income |
1,282 | 576 | ||||||
Interest expense |
(22,321 | ) | (1,117 | ) | ||||
Foreign currency transaction gain (loss) |
461 | (4,125 | ) | |||||
Other, net |
(87 | ) | 1,067 | |||||
Income before income tax expense |
406,012 | 453,337 | ||||||
Income tax expense |
(115,159 | ) | (104,756 | ) | ||||
Net income |
$ | 290,853 | $ | 348,581 | ||||
Income per share: |
||||||||
Basic |
$ | 2.09 | $ | 2.51 | ||||
Diluted |
$ | 2.09 | $ | 2.51 | ||||
Weighted-average shares outstanding: |
||||||||
Shares of common stock |
139,026 | 139,001 | ||||||
Dilutive potential shares of common stock |
103 | 63 | ||||||
Total weighted-average shares outstanding assuming dilution |
139,129 | 139,064 | ||||||
Cash dividends declared per share of common stock |
$ | 2.00 | $ | 2.00 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
4
Table of Contents
DIAMOND OFFSHORE DRILLING, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
(In thousands)
(Unaudited)
(In thousands)
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
Operating activities: |
||||||||
Net income |
$ | 290,853 | $ | 348,581 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||
Depreciation |
97,402 | 85,062 | ||||||
Gain on disposition of assets |
(884 | ) | (55 | ) | ||||
Loss (gain) on sale of marketable securities, net |
1 | (597 | ) | |||||
(Gain) loss on foreign currency forward exchange contracts |
(2,099 | ) | 25 | |||||
Deferred tax provision |
(4,843 | ) | 8,365 | |||||
Accretion of discounts on marketable securities |
(73 | ) | (311 | ) | ||||
Amortization/write-off of debt issuance costs |
211 | 113 | ||||||
Amortization of debt discounts |
89 | 62 | ||||||
Stock-based compensation expense |
1,938 | 1,705 | ||||||
Deferred income, net |
55,063 | 62,228 | ||||||
Deferred expenses, net |
(30,246 | ) | (9,606 | ) | ||||
Other items, net |
395 | 2,625 | ||||||
Proceeds from settlement of foreign currency forward exchange contracts designated as accounting hedges |
2,099 | | ||||||
Changes in operating assets and liabilities: |
||||||||
Accounts receivable |
(44,875 | ) | (114,007 | ) | ||||
Prepaid expenses and other current assets |
5,052 | 7,842 | ||||||
Accounts payable and accrued liabilities |
(19,762 | ) | (29,142 | ) | ||||
Taxes payable |
114,560 | 44,189 | ||||||
Net cash provided by operating activities |
464,881 | 407,079 | ||||||
Investing activities: |
||||||||
Capital expenditures |
(107,798 | ) | (130,408 | ) | ||||
Proceeds from disposition of assets, net of disposal costs |
989 | 325 | ||||||
Proceeds from sale and maturities of marketable securities |
1,200,053 | 1,348,964 | ||||||
Purchases of marketable securities |
(1,349,900 | ) | (1,149,112 | ) | ||||
Cost of proceeds from settlement of foreign currency forward exchange contracts not
designated as accounting hedges |
| (24,789 | ) | |||||
Net cash (used in) provided by investing activities |
(256,656 | ) | 44,980 | |||||
Financing activities: |
||||||||
Debt issuance costs and arrangement fees |
(98 | ) | | |||||
Payment of dividends |
(278,597 | ) | (278,257 | ) | ||||
Proceeds from stock plan exercises |
107 | | ||||||
Net cash used in financing activities |
(278,588 | ) | (278,257 | ) | ||||
Net change in cash and cash equivalents |
(70,363 | ) | 173,802 | |||||
Cash and cash equivalents, beginning of period |
376,417 | 336,052 | ||||||
Cash and cash equivalents, end of period |
$ | 306,054 | $ | 509,854 | ||||
The accompanying notes are an integral part of the consolidated financial statements.
5
Table of Contents
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, 2009 (File No.
1-13926).
As of April 22, 2010, Loews Corporation, or Loews, owned 50.4% 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 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, Marketable Securities
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. See Note 5.
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 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).
Derivative Financial Instruments
Our derivative financial instruments include foreign currency forward exchange, or FOREX,
contracts. See Notes 4 and 5.
Supplementary Cash Flow Information
We paid interest on long-term debt totaling $12.5 million in each of the three-month periods
ended March 31, 2010 and 2009. During the three months ended March 31, 2010, we paid $0.9 million
in interest on assessments from the Internal Revenue Service.
We paid $0.5 million in U.S. federal income taxes during the three-month periods ended March
31, 2010. We paid $37.3 million and $47.8 million in foreign income taxes, net of foreign tax
refunds, during the three months
6
Table of Contents
ended March 31, 2010 and 2009, respectively. We received a refund for state income taxes of
$0.1 million during the three months ended March 31, 2010.
Capital expenditures for the three months ended March 31, 2010 included $64.9 million that was
accrued but unpaid at December 31, 2009. Capital expenditures for the three months ended March 31,
2009 included $59.4 million that was accrued but unpaid at December 31, 2008. Capital expenditures
that were accrued but not paid as of March 31, 2010 totaled $37.0 million. We have included this
amount in Accrued liabilities in our Consolidated Balance Sheets at March 31, 2010.
We recorded income tax benefits of $0.1 million related to employee stock plan exercises
during the three months ended March 31, 2009.
Comprehensive Income
A reconciliation of net income to comprehensive income is as follows:
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Net income |
$ | 290,853 | $ | 348,581 | ||||
Other comprehensive gains (losses), net of tax: |
||||||||
FOREX contracts: |
||||||||
Unrealized holding gain |
137 | | ||||||
Reclassification adjustment for gain
included in net income |
(1,085 | ) | | |||||
Investments in marketable securities: |
||||||||
Unrealized holding (loss) gain |
(4 | ) | 27 | |||||
Reclassification adjustment for gain
included in net income |
| (493 | ) | |||||
Comprehensive income |
$ | 289,901 | $ | 348,115 | ||||
The tax related to the change in unrealized holding gain on FOREX contracts for the three
months ended March 31, 2010 was approximately $74,000. The tax related to the reclassification
adjustment for FOREX contracts included in net income for the three months ended March 31, 2010 was
approximately $584,000.
The tax related to the change in unrealized holding loss on investments was approximately
$2,000 for the three months ended March 31, 2010. The tax related to the change in unrealized
holding gain on investments for the three months ended March 31, 2009 was approximately $15,000.
The tax effect on the reclassification adjustment for net gains included in net income was
approximately $265,000 for the three months ended March 31, 2009.
Foreign Currency
Our functional currency is the U.S. dollar. Foreign currency transaction gains and losses,
including gains and losses from the settlement of FOREX contracts not designated as accounting
hedges, are reported as Foreign currency transaction gain (loss) in our Consolidated Statements
of Operations. For the three-month periods ended March 31, 2010 and 2009, we recognized net
foreign currency exchange gains of $0.5 million and net foreign currency exchange losses of $4.1
million, respectively. See Note 4.
Revenue Recognition
Revenue from our dayrate drilling contracts is recognized as services are performed. In
connection with such drilling contracts, we may receive fees (either lump-sum or dayrate) for the
mobilization of equipment. These fees are earned 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 initial term of the related drilling contracts (which generally range from two to 60 months) is
consistent with the timing of net cash
7
Table of Contents
flows generated from the actual drilling services performed.
Absent a contract, mobilization costs are recognized as incurred.
From time to time, we may receive fees from our customers for capital improvements to our rigs
(either lump-sum or dayrate). 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 asset.
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.
2. Earnings Per Share
A reconciliation of the numerators and the denominators of our basic and diluted per-share
computations follows:
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
(In thousands, except per share data) | ||||||||
Net income basic (numerator): |
$ | 290,853 | $ | 348,581 | ||||
Effect of dilutive potential shares |
||||||||
Zero Coupon Debentures |
24 | 23 | ||||||
Net income including conversions diluted
(numerator) |
$ | 290,877 | $ | 348,604 | ||||
Weighted average shares basic (denominator): |
139,026 | 139,001 | ||||||
Effect of dilutive potential shares |
||||||||
Zero Coupon Debentures |
52 | 52 | ||||||
Stock options and SARs |
51 | 11 | ||||||
Weighted average shares including conversions
diluted (denominator) |
139,129 | 139,064 | ||||||
Earnings per share: |
||||||||
Basic |
$ | 2.09 | $ | 2.51 | ||||
Diluted |
$ | 2.09 | $ | 2.51 | ||||
Our computation of diluted earnings per share, or EPS, for the three months ended March
31, 2010 excludes 441,037 stock appreciation rights, or SARs. The inclusion of such potentially
dilutive shares in the computation of diluted EPS would have been antidilutive for the period
presented.
Our computation of EPS for the three months ended March 31, 2009 excludes stock options
representing 23,493 shares of common stock and 482,588 SARs. The inclusion of such potentially
dilutive shares in the computation of diluted EPS would have been antidilutive for the period
presented.
3. 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.
8
Table of Contents
Our investments in marketable securities are classified as available for sale and are summarized as
follows:
March 31, 2010 | ||||||||||||
Amortized | Unrealized | Market | ||||||||||
Cost | (Loss) Gain | Value | ||||||||||
(In thousands) | ||||||||||||
Due within one year |
$ | 649,960 | $ | (2 | ) | $ | 649,958 | |||||
Mortgage-backed securities |
738 | 60 | 798 | |||||||||
Total |
$ | 650,698 | $ | 58 | $ | 650,756 | ||||||
December 31, 2009 | ||||||||||||
Amortized | Unrealized | Market | ||||||||||
Cost | (Loss) Gain | Value | ||||||||||
(In thousands) | ||||||||||||
Due within one year |
$ | 399,997 | $ | (1 | ) | $ | 399,996 | |||||
Mortgage-backed securities |
792 | 65 | 857 | |||||||||
Total |
$ | 400,789 | $ | 64 | $ | 400,853 | ||||||
Marketable securities at March 31, 2010 include $100.0 million in U.S. Treasury Bills
purchased on March 31, 2010 that did not settle until April 2010. The offsetting amount for this
transaction has been reported as a $100.0 million Payable for purchase of marketable securities
in our Consolidated Balance Sheets at March 31, 2010.
Proceeds from sales and maturities of marketable securities and gross realized gains and
losses are summarized as follows:
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Proceeds from sales |
$ | 53 | $ | 1,448,943 | ||||
Proceeds from maturities |
1,200,000 | | ||||||
Gross realized gains |
| 732 | ||||||
Gross realized losses |
(1 | ) | (135 | ) |
Proceeds from sales of marketable securities for the three months ended March 31, 2009 include
$100.0 million in securities sold on March 31, 2009 that did not settle until April 2009.
4. 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. We may utilize FOREX contracts to reduce our foreign exchange risk. Our
FOREX contracts may obligate us to exchange predetermined amounts of foreign currencies on
specified dates or 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/losses on foreign currency expenditures in the future. The
amount and duration of such contracts is based on our monthly forecast of expenditures in the
significant currencies in which we do business and for which there is a financial market (i.e.,
Australian dollars, Brazilian reais, British pounds sterling, Mexican pesos and Norwegian kroner).
These forward contracts are derivatives as defined by GAAP.
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 losses and gains on the qualifying hedged
positions.
9
Table of Contents
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.
In May 2009, we began a hedging strategy and designated certain of our qualifying FOREX
contracts as cash flow hedges. These 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 is recorded as a component of Accumulated other comprehensive
gain, or AOCG, in our Consolidated Financial Statements. The effective portion of the cash flow
hedge will remain in AOCG 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. Adjustments to record the carrying value of the ineffective portion of our derivative
financial instruments to fair value are recorded as Foreign currency transaction gain (loss) in
our Consolidated Statements of Operations.
Realized gains or losses upon settlement of derivative contracts designated as cash flow
hedges are reported as a component of Contract drilling 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.
For derivative contracts entered into prior to May 2009, we did not seek hedge accounting
treatment under GAAP. Accordingly, prior to May 2009, all adjustments to record the carrying value
of our derivative financial instruments at fair value were reported as Foreign currency
transaction gain (loss) in our Consolidated Statements of Operations.
During the three months ended March 31, 2010, we settled FOREX contracts with an aggregate
notional value of approximately $52.4 million, of which the entire aggregate amount was designated
as an accounting hedge.
The following table presents the amounts recognized in our Consolidated Statements of
Operations related to our FOREX contracts designated as accounting hedges for the three-month
periods ended March 31, 2010 and 2009.
For the Three Months Ended March 31, | ||||||||
Location of Gain Recognized in Income | 2010 | 2009 | ||||||
(In thousands) | ||||||||
Contract drilling expense |
$ | 2,099 | $ | |
The following table presents the amounts recognized in our Consolidated Statements of
Operations related to our FOREX contracts not designated as hedging instruments for the three
months ended March 31, 2010 and 2009.
For the Three Months Ended March 31, | ||||||||
Location of Loss Recognized in Income | 2010 | 2009 | ||||||
(In thousands) | ||||||||
Foreign currency transaction loss |
$ | | $ | (25 | ) |
The amounts presented in the table above include net unrealized gains aggregating $24.8
million for the three months ended March 31, 2009 to record the carrying value of our derivative
financial instruments to their fair value. There were no gains or losses associated with FOREX
contracts not designated as accounting hedges during the three months ended March 31, 2010.
As of March 31, 2010, we had FOREX contracts outstanding in the aggregate notional amount of
$77.6 million, consisting of $30.1 million in Australian dollars, $27.6 million in Brazilian reais,
$10.6 million in British pounds sterling, $4.0 million in Mexican pesos and $5.3 million in
Norwegian kroner. These contracts generally settle monthly through September 2010. As of March
31, 2010, all outstanding derivative contracts had been designated as cash flow hedges. See Note
5.
10
Table of Contents
The following table presents the fair values of our derivative financial instruments at March
31, 2010.
Assets | Liabilities | |||||||||||||||
Balance Sheet | Balance Sheet | |||||||||||||||
Location | Fair Value | Location | Fair Value | |||||||||||||
(In | (In | |||||||||||||||
thousands) | thousands) | |||||||||||||||
Derivatives
designated as
hedging
instruments: |
||||||||||||||||
FOREX contracts |
Prepaid expenses and other current assets |
$ | 1,505 | Accrued liabilities | $ | (560 | ) |
The following table presents the fair values of our derivative financial instruments at
December 31, 2009.
Assets | Liabilities | |||||||||||||||
Balance Sheet | Balance Sheet | |||||||||||||||
Location | Fair Value | Location | Fair Value | |||||||||||||
(In | (In | |||||||||||||||
thousands) | thousands) | |||||||||||||||
Derivatives
designated as
hedging
instruments: |
||||||||||||||||
FOREX contracts |
Prepaid expenses and other current assets |
$ | 2,634 | Accrued liabilities | $ | (230 | ) |
The following table presents the amounts recognized in our Consolidated Balance Sheets and
Consolidated Statements of Operations related to our FOREX contracts designated as cash flow hedges
for the three months ended March 31, 2010.
Location of Gain | ||||||||
Amount of | Recognized in Income | Amount of Gain | ||||||
Pre-Tax Gain | Location of | Amount of | on Derivative | Recognized in Income on | ||||
Recognized in | Pre-Tax Gain | Pre-Tax Gain | (Ineffective Portion | Derivative (Ineffective | ||||
AOCG on | Reclassified from | Reclassified from | and Amount Excluded | Portion and Amount | ||||
Derivative | AOCG into Income | AOCG into Income | from Effectiveness | Excluded from | ||||
(Effective Portion) | (Effective Portion) | (Effective Portion) | Testing) | Effectiveness Testing) | ||||
(In thousands) | (In thousands) | (In thousands) | ||||||
$212
|
Contract drilling expense | $1,670 | Foreign currency transaction gain
|
$ |
As of March 31, 2010, the estimated amount of net unrealized gains associated with our FOREX
contracts that will be reclassified to earnings during the next twelve months was $0.9 million.
The net unrealized gains associated with these derivative financial instruments will be
reclassified to contract drilling expense.
5. Financial Instruments and Fair Value Disclosures
Concentrations of Credit and Market Risk
Financial instruments which 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 place our excess cash investments in high quality 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.
A majority of our investments in debt securities are U.S. government securities with minimal
credit risk. 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. In general, before working for a
customer with whom we have not had a prior business relationship
11
Table of Contents
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.
Our business has experienced negative effects of the current economic downturn such as
customer credit problems, customers attempting to renegotiate or terminate contracts, and one
customer seeking bankruptcy protection. We provide allowances for potential credit losses on a
specific customer basis when necessary; however, we have not historically experienced significant
losses on our trade receivables. At March 31, 2010 and December 31, 2009, our allowance for
doubtful accounts receivable was $40.6 million and $41.7 million, respectively, related to our
operations in Egypt and the insolvency of one of our customers in the United Kingdom. No
additional allowances were deemed necessary for the periods presented.
During 2009, we amended an existing contractual agreement at a customers request to provide
short-term financial relief. The amended contract obligates the customer to pay us, over the term
of the six-well drilling program, $75,000 per day in accordance with our normal credit terms (due
30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day,
through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas
producing properties. Based on the current production payout estimate, we anticipate that the
first payment from the conveyance of the NPI will commence in the second quarter of 2010. Payment
of such amounts, and the timing of such payments, are contingent upon such production and upon
energy sale prices.
At March 31, 2010, the $94.5 million portion of this trade receivable payable from the NPI is
presented as Accounts Receivable in our Consolidated Balance Sheets. At March 31, 2010, we
believe that collectability of the amount owed pursuant to the NPI arrangement is reasonably
assured.
Fair Values
The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents,
marketable securities, accounts receivable, forward exchange contracts and accounts payable
approximate fair value. Fair values and related carrying values of our debt instruments are shown
below.
March 31, 2010 | December 31, 2009 | |||||||||||||||
Fair Value | Carrying Value | Fair Value | Carrying Value | |||||||||||||
(In millions) | ||||||||||||||||
Zero Coupon Debentures |
$ | 4.6 | $ | 4.2 | $ | 5.1 | $ | 4.2 | ||||||||
4.875% Senior Notes |
268.5 | 249.7 | 257.5 | 249.7 | ||||||||||||
5.15% Senior Notes |
269.6 | 249.7 | 263.3 | 249.7 | ||||||||||||
5.70% Senior Notes |
487.0 | 496.7 | 490.4 | 496.7 | ||||||||||||
5.875% Senior Notes |
539.2 | 499.3 | 530.6 | 499.3 |
We have estimated the fair value amounts by using appropriate valuation methodologies and
information available to management as of March 31, 2010 and December 31, 2009, respectively.
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. The following methods and assumptions were used to estimate the fair value of
each class of financial instrument for which it was practicable to estimate that value:
| Cash and cash equivalents The carrying amounts approximate fair value because of the short maturity of these instruments. |
| Marketable securities The fair values of the debt securities, including residential mortgage-backed securities, available for sale were based on the quoted closing market prices on March 31, 2010 and December 31, 2009, respectively. |
| Accounts receivable and accounts payable The carrying amounts approximate fair value based on the nature of the instruments. |
| Forward exchange contracts The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on March 31, 2010 and December 31, 2009, respectively. |
| Long-term debt The fair value of our 5.70% Senior Notes due 2039, 5.875% Senior Notes due 2019, 4.875% Senior Notes due July 1, 2015, and 5.15% Senior Notes due September 1, 2014 was based on the quoted closing market price on March 31, 2010 and December 31, 2009, respectively, from brokers of these instruments. The fair value of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon |
12
Table of Contents
Debentures, was based on the closing market price of our common stock on March 31, 2010 and December 31, 2009, respectively, and the stated conversion rate for these debentures. |
Certain of our assets and liabilities are required to be measured at fair value in accordance
with GAAP. Fair value is defined as the exchange price that would be received for an asset or paid
to transfer a liability (an exit price) in the principal or most advantageous market for the asset
or liability in an orderly transaction between market participants on the measurement date. The
fair value hierarchy prescribed by GAAP requires an entity to maximize the use of observable inputs
and minimize the use of unobservable inputs when measuring fair value. There are three levels of
inputs that may be used to measure fair value:
Level 1 | Quoted prices for identical instruments in active markets. Level 1 assets include short-term investments such as money market funds and U.S. Treasury Bills. Our Level 1 assets at March 31, 2010 consisted of cash held in money market funds of $282.1 million and investments in U.S. Treasury Bills of $650.0 million. Our Level 1 assets at December 31, 2009 consisted of cash held in money market funds of $337.8 million and investments in U.S. Treasury Bills of $400.0 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 and over-the-counter FOREX contracts. Our residential mortgage-backed securities 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. |
Market conditions could cause an instrument to be reclassified from Level 1 to Level 2, or
from Level 2 to Level 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.
Assets measured at fair value on a recurring basis are summarized below:
March 31, 2010 | ||||||||||||||||
Fair Value Measurements Using | Assets at Fair | |||||||||||||||
Level 1 | Level 2 | Level 3 | Value | |||||||||||||
(In thousands) | ||||||||||||||||
Assets: |
||||||||||||||||
Short-term investments |
$ | 932,090 | $ | | $ | | $ | 932,090 | ||||||||
FOREX contracts |
| 1,505 | | 1,505 | ||||||||||||
Mortgage-backed securities |
| 798 | | 798 | ||||||||||||
Total assets |
$ | 932,090 | $ | 2,303 | $ | | $ | 934,393 | ||||||||
Liabilities: |
||||||||||||||||
FOREX contracts |
$ | | $ | (560 | ) | $ | | $ | (560 | ) | ||||||
13
Table of Contents
December 31, 2009 | ||||||||||||||||
Fair Value Measurements Using | Assets at Fair | |||||||||||||||
Level 1 | Level 2 | Level 3 | Value | |||||||||||||
(In thousands) | ||||||||||||||||
Assets: |
||||||||||||||||
Short-term investments |
$ | 737,830 | $ | | $ | | $ | 737,830 | ||||||||
FOREX contracts |
| 2,634 | | 2,634 | ||||||||||||
Mortgage-backed securities |
| 857 | | 857 | ||||||||||||
Total assets |
$ | 737,830 | $ | 3,491 | $ | | $ | 741,321 | ||||||||
Liabilities: |
||||||||||||||||
FOREX contracts |
$ | | $ | (230 | ) | $ | | $ | (230 | ) | ||||||
6. Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of the following:
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Rig spare parts and supplies |
$ | 51,551 | $ | 49,122 | ||||
Deferred mobilization costs |
71,584 | 45,502 | ||||||
Prepaid insurance |
3,725 | 11,478 | ||||||
Deferred tax assets |
7,235 | 7,235 | ||||||
Deposits |
3,540 | 3,562 | ||||||
Prepaid taxes |
676 | 26,109 | ||||||
FOREX contracts |
1,505 | 2,634 | ||||||
Other |
7,097 | 9,435 | ||||||
Total |
$ | 146,913 | $ | 155,077 | ||||
7. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized
as follows:
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Drilling rigs and equipment |
$ | 7,025,047 | $ | 6,950,303 | ||||
Land and buildings |
48,283 | 44,640 | ||||||
Office equipment and other |
39,554 | 38,203 | ||||||
Cost |
7,112,884 | 7,033,146 | ||||||
Less: accumulated depreciation |
(2,698,497 | ) | (2,601,094 | ) | ||||
Drilling and other property and equipment, net |
$ | 4,414,387 | $ | 4,432,052 | ||||
8. Accrued Liabilities
Accrued liabilities consist of the following:
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Accrued project/upgrade expenses |
$ | 73,744 | $ | 115,778 | ||||
Payroll and benefits |
62,236 | 69,065 | ||||||
Deferred revenue |
74,625 | 46,666 | ||||||
Rig operating expenses |
32,462 | 29,141 | ||||||
Interest payable |
30,055 | 22,710 | ||||||
Personal injury and other claims |
11,814 | 10,018 | ||||||
FOREX contracts |
560 | 230 | ||||||
Other |
7,148 | 8,263 | ||||||
Total |
$ | 292,644 | $ | 301,871 | ||||
14
Table of Contents
9. Long-Term Debt
Long-term debt consists of the following:
March 31, | December 31, | |||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
Zero Coupon Debentures (due 2020) |
$ | 4,215 | $ | 4,179 | ||||
5.15% Senior Notes (due 2014) |
249,697 | 249,682 | ||||||
4.875% Senior Notes (due 2015) |
249,684 | 249,671 | ||||||
5.875% Senior Notes (due 2019) |
499,307 | 499,292 | ||||||
5.70% Senior Notes (due 2039) |
496,740 | 496,730 | ||||||
1,499,643 | 1,499,554 | |||||||
Less: Current maturities |
4,215 | 4,179 | ||||||
Total |
$ | 1,495,428 | $ | 1,495,375 | ||||
At March 31, 2010, there was $6.0 million aggregate principal amount at maturity, or $4.2
million accreted, or carrying value, of our Zero Coupon Debentures outstanding.
Certain of our long-term debt payments may be accelerated due to rights that the holders of
our debt securities have to put the securities to us. The holders of our outstanding Zero Coupon
Debentures have the right to require us to purchase all or a portion of their outstanding
debentures on June 6, 2010.
The aggregate maturities of long-term debt for each of the five years subsequent to March 31,
2010, are as follows:
(Dollars in thousands) | ||||
2010 |
$ | 4,215 | ||
2011 |
| |||
2012 |
| |||
2013 |
| |||
2014 |
249,697 | |||
Thereafter |
1,245,731 | |||
1,499,643 | ||||
Less: Current maturities |
4,215 | |||
Total |
$ | 1,495,428 | ||
10. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims
by offshore workers alleging personal injuries. We have assessed each claim or exposure to
determine the likelihood that the resolution of the matter might ultimately result in an adverse
effect on our financial condition, results of operations and cash flows. When we determine that an
unfavorable resolution of a matter is probable and such amount of loss can be determined, we record
a reserve for the estimated loss at the time that both of these criteria are met. Our management
believes that we have established adequate reserves for any liabilities that may reasonably be
expected to result from these claims.
Litigation. We are one of several unrelated defendants in lawsuits filed in the Circuit
Courts of the State of Mississippi 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. We expect to receive complete defense and indemnity from Murphy
Exploration & Production Company pursuant to the terms of our 1992 asset purchase agreement with
them. We are unable to estimate our potential exposure, if any, to these lawsuits at this time but
do not believe that ultimate liability, if any, resulting from this litigation will have a material
adverse effect on our financial condition, results of operations and cash flows.
Various other claims have been filed against us in the ordinary course of business. 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 and cash flows.
15
Table of Contents
We intend to defend these matters vigorously; however, we cannot predict with certainty the
outcome or effect of any litigation matters specifically described above or any other pending
litigation or claims. There can be no assurance as to the ultimate outcome of these lawsuits.
Personal Injury Claims. Our deductible for liability coverage for personal injury claims,
which primarily result from Jones Act liability in the Gulf of Mexico, is currently $5.0 million per
occurrence, with no aggregate deductible. 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 reserve for
personal injury claims based on our historical losses and utilizing various actuarial models. At
March 31, 2010, our estimated liability for personal injury claims was $33.6 million, of which
$11.2 million and $22.4 million were recorded in Accrued liabilities and Other liabilities,
respectively, in our Consolidated Balance Sheets. At December 31, 2009, our estimated liability
for personal injury claims was $32.1 million, of which $9.2 million and $22.9 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. As of March 31, 2010 and December 31, 2009, we had no 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 March 31, 2010 in the amount
of $171.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds and
letters of credit, including $63.1 million in letters of credit issued under our $285 million,
syndicated, senior unsecured revolving credit facility. At March 31, 2010, we had purchased five
of our outstanding bonds, totaling $82.4 million, from a related party in previous years after
obtaining competitive quotes. Agreements relating to approximately $82.4 million of performance
bonds can require collateral at any time. As of March 31, 2010, 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.
11. Segments and Geographic Area Analysis
Although we provide contract drilling services with different types of offshore drilling rigs
and also provide such services in many geographic locations, we have aggregated these operations
into one reportable segment based on the similarity of economic characteristics among all divisions
and locations, including the nature of services provided and the type of customers of such
services, in accordance with Financial Accounting Standards Board Accounting Standards Codification
Topic 280, Segment Reporting.
Revenues from contract drilling services by equipment-type are listed below:
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
High-Specification Floaters |
$ | 383,788 | $ | 312,134 | ||||
Intermediate Semisubmersibles |
380,701 | 417,000 | ||||||
Jack-ups |
79,949 | 126,574 | ||||||
Total contract drilling revenues |
844,438 | 855,708 | ||||||
Revenues related to reimbursable expenses |
15,243 | 30,012 | ||||||
Total revenues |
$ | 859,681 | $ | 885,720 | ||||
16
Table of Contents
Geographic Areas
At March 31, 2010, our drilling rigs were located offshore twelve countries in addition to the
United States. As a result, we are exposed to the risk of changes in social, political and
economic conditions inherent in international operations and our results of operations and the
value of our international assets are affected by fluctuations in foreign currency exchange rates.
Revenues by geographic area are presented below by attributing revenues to the individual country
or areas where the services were performed.
Three Months Ended | ||||||||
March 31, | ||||||||
2010 | 2009 | |||||||
(In thousands) | ||||||||
United States |
$ | 238,547 | $ | 356,315 | ||||
International: |
||||||||
South America |
283,115 | 124,701 | ||||||
Australia/Asia/Middle East |
158,929 | 174,225 | ||||||
Europe/Africa/Mediterranean |
136,606 | 149,832 | ||||||
Mexico |
42,484 | 80,647 | ||||||
Total revenues |
$ | 859,681 | $ | 885,720 | ||||
17
Table of Contents
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, 2009. References to Diamond
Offshore, we, us or our mean Diamond Offshore Drilling, Inc., a Delaware corporation, and
its subsidiaries.
We provide contract drilling services to the energy industry around the globe and are a leader
in offshore drilling with a fleet of 47 offshore rigs currently consisting of 32 semisubmersibles,
14 jack-ups and one drillship.
Overview
Industry Conditions
The global economy remained relatively weak in the first quarter of 2010 and although oil
prices improved to the low $80 per barrel range they remained volatile. Dayrates we receive for
new contracts are no longer at the peak levels achieved at the height of the most recent up-cycle.
Given the unpredictable economic environment, the demand for our services and the dayrates we are
able to command could soften further. This volatility and uncertainty could continue until the
global economy improves. Absent global economic improvement the decline in drilling activity could
be further exacerbated by the influx of new-build rigs over the next several years, particularly in
regard to jack-up units.
Early in the economic downturn, we experienced negative effects of the market such as customer
credit problems, customers attempting to renegotiate or terminate contracts, and one customer
seeking bankruptcy protection. More recently, we have experienced some declines in dayrates for
new contracts with industry-wide floater utilization stable at approximately 91%. During the first
quarter of 2010, we signed 14 new contracts totaling approximately $1.5 billion in backlog and
ranging in length from one well to five years. As a result, at the end of the first quarter of
2010 our contract backlog was approximately $9.1 billion, which we expect to help mitigate the
impact of the current market on us in 2010.
Floaters
Our intermediate and high-specification floater rigs account for approximately 89% of our
revenue. Approximately 89% of the time on our intermediate and high-specification floater rigs is
committed for 2010. Additionally, 63% of the time on our floating rigs is committed in 2011.
International Jack-ups
During the first quarter of 2010, demand was weak but stable, while dayrates softened
internationally as existing rigs rolled off contract and met competition from un-contracted
new-build jack-ups that came to market. With industry-wide jack-up utilization standing at only
about 76%, this oversupply of jack-up rigs could have an increasingly negative impact on the
international sector throughout 2010 and beyond.
U.S. Gulf of Mexico Jack-ups
In the domestic jack-up sector, lower natural gas prices have negatively impacted both demand
and dayrates. In response, to reduce costs, we have cold-stacked three of our lower-end jack-up
units, and they are not being actively marketed. Our four remaining higher-specification jack-ups
in the U.S. Gulf of Mexico, or GOM, are largely working under short-term contracts. Absent a
sustained improvement in energy prices, weakness in the GOM jack-up market is likely to continue in
2010, with the possibility of additional rigs being cold-stacked by the industry in an effort to
help bring equipment supply and demand into equilibrium.
18
Table of Contents
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of April 19, 2010, February 1,
2010 (the date reported in our Annual Report on Form 10-K for the year ended December 31, 2009) and
April 15, 2009 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended March
31, 2009). Contract drilling backlog 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
95-98% 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 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.
April 19, | February 1, | April 15, | ||||||||||
2010(1) (2) | 2010 | 2009 | ||||||||||
(In thousands) | ||||||||||||
Contract Drilling Backlog |
||||||||||||
High-Specification Floaters (1) |
$ | 5,175,000 | $ | 4,177,000 | $ | 4,059,000 | ||||||
Intermediate Semisubmersibles (2) |
3,767,000 | 4,030,000 | 5,148,000 | |||||||||
Jack-ups |
185,000 | 249,000 | 390,000 | |||||||||
Total |
$ | 9,127,000 | $ | 8,456,000 | $ | 9,597,000 | ||||||
(1) | Contract drilling backlog as of April 19, 2010 for our high-specification floaters includes $3.3 billion attributable to our expected operations offshore Brazil for the remainder of 2010 and for the years 2011 to 2016. | |
(2) | Contract drilling backlog as of April 19, 2010 for our intermediate semisubmersibles includes $2.8 billion attributable to our expected operations offshore Brazil for the remainder of 2010 and for the years 2011 to 2015. |
The following table reflects the amount of our contract drilling backlog by year as of April
19, 2010.
For the Years Ending December 31, | ||||||||||||||||||||
Total | 2010(1) | 2011 | 2012 | 2013 - 2016 | ||||||||||||||||
(In thousands) | ||||||||||||||||||||
Contract Drilling Backlog |
||||||||||||||||||||
High-Specification Floaters (2) |
$ | 5,175,000 | $ | 1,315,000 | $ | 1,569,000 | $ | 944,000 | $ | 1,347,000 | ||||||||||
Intermediate Semisubmersibles (3) |
3,767,000 | 1,133,000 | 1,030,000 | 860,000 | 744,000 | |||||||||||||||
Jack-ups |
185,000 | 144,000 | 41,000 | | | |||||||||||||||
Total |
$ | 9,127,000 | $ | 2,592,000 | $ | 2,640,000 | $ | 1,804,000 | $ | 2,091,000 | ||||||||||
(1) | Represents a nine-month period beginning April 1, 2010. | |
(2) | Contract drilling backlog as of April 19, 2010 for our high-specification floaters includes $531.0 million, $808.0 million and $667.0 million for the remainder of 2010 and for the years 2011 and 2012, respectively, and $1.3 billion in the aggregate for the years 2013 to 2016, attributable to our expected operations offshore Brazil. | |
(3) | Contract drilling backlog as of April 19, 2010 for our intermediate semisubmersibles includes $560.0 million, $788.0 million and $732.0 million for the remainder of 2010 and for the years 2011 and 2012, respectively, and $687.0 million in the aggregate for the years 2013 to 2015, attributable to our expected operations offshore Brazil. |
19
Table of Contents
The following table reflects the percentage of rig days committed by year as of April 19,
2010. 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 multiplied by the number of days in a particular
year).
For the Years Ending December 31, | ||||||||||||||||
2010(1) | 2011 | 2012 | 2013 - 2016 | |||||||||||||
Rig Days Committed (2) |
||||||||||||||||
High-Specification Floaters |
97 | % | 76 | % | 48 | % | 18 | % | ||||||||
Intermediate Semisubmersibles |
83 | % | 54 | % | 44 | % | 10 | % | ||||||||
Jack-ups |
39 | % | 7 | % | | |
(1) | Represents a nine-month period beginning April 1, 2010. | |
(2) | Includes approximately 675 and 80 scheduled shipyard, survey and mobilization days for 2010 and 2011, respectively. |
General
The two most significant variables affecting our revenues are dayrates for rigs and rig
utilization rates, each of which is a function of rig supply and demand in the marketplace. Demand
for drilling services is dependent upon the level of expenditures set by oil and gas companies for
offshore exploration and development, as well as a variety of political and economic factors. The
availability of rigs in a particular geographical region also affects both dayrates and utilization
rates. These factors are not within our control and are difficult to predict.
Demand affects the number of days our fleet is utilized and the dayrates earned. As
utilization rates increase, dayrates tend to increase as well, reflecting the lower supply of
available rigs. Conversely, as utilization rates decrease, dayrates tend to decrease as well,
reflecting the excess supply of rigs. When a rig is idle, no dayrate is earned and revenues will
decrease as a result. Revenues can also be affected as a result of the acquisition or disposal of
rigs, required surveys and shipyard upgrades. In order to improve utilization or realize higher
dayrates, we may mobilize our rigs from one market to another. However, during periods of
mobilization, revenues may be adversely affected. As a response to changes in demand, we may
withdraw a rig from the market by stacking it or may reactivate a rig stacked previously, which may
decrease or increase revenues, respectively.
We recognize revenue from dayrate drilling contracts as services are performed. In connection
with such drilling contracts, we may receive fees (either lump-sum or dayrate) 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.
From time to time, we may receive fees from our customers for capital improvements to our rigs
(either lump-sum or dayrate). We defer such fees and recognize them into income on a straight-line
basis over the period of the related drilling contract as a component of contract drilling revenue.
We capitalize the costs of such capital improvements and depreciate them over the estimated useful
life of the improvement.
We receive reimbursements 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.
We record these reimbursements at the gross amount billed to the customer, as Revenues related to
reimbursable expenses in our Consolidated Statements of Operations included in Item 1 of Part I of
this report.
Operating Income. Our operating income is primarily affected by revenue factors, but is also
a function of varying levels of operating expenses. Our operating expenses represent all direct
and indirect costs associated with the operation and maintenance of our drilling equipment. The
principal components of our operating costs are, among other things, direct and indirect costs of
labor and benefits, repairs and maintenance, freight, regulatory inspections, boat and helicopter
rentals and insurance. Labor and repair and maintenance costs represent the most significant
components of our operating expenses. In general, our labor costs increase primarily due to higher
salary levels, rig staffing requirements and costs associated with labor regulations in the
geographic regions in which our rigs operate.
20
Table of Contents
Costs to repair and maintain our equipment fluctuate depending upon the type of activity the
drilling unit is performing, as well as the age and condition of the equipment and the regions in
which our rigs are working.
Operating expenses generally are not affected by changes in dayrates, and short-term
reductions in utilization do not necessarily result in lower operating expenses. For instance, if
a rig is to be idle for a short period of time, few decreases in operating expenses may actually
occur since the rig is typically maintained in a prepared or ready-stacked state with a full
crew. In addition, when a rig is idle, we are responsible for certain operating expenses such as
rig fuel and supply boat costs, which are typically costs of the operator when a rig is under
contract. However, if the rig is to be idle for an extended period of time, we may reduce the size
of a rigs crew and take steps to cold stack the rig, which lowers expenses and partially offsets
the impact on operating income. We recognize, as incurred, operating expenses related to
activities such as inspections, painting projects and routine overhauls that meet certain criteria
and which maintain rather than upgrade our rigs. These expenses vary from period to period. Costs
of rig enhancements are capitalized and depreciated over the expected useful lives of the
enhancements. Higher depreciation expense decreases operating income in periods following capital
upgrades.
Periods of high, sustained utilization may result in cost increases for maintenance and
repairs in order to maintain our equipment in proper, working order. In addition, during periods
of high activity and dayrates, higher prices generally pervade the entire offshore drilling
industry and its support businesses, which cause our costs for goods and services to increase.
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 surveys are performed during scheduled
downtime in a shipyard. Operating expenses increase as a result of these surveys due to the cost
to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance costs.
Repair and maintenance costs may be required resulting from the 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 dry-docking or shipyard time,
except for rigs located in the U.K. and Norwegian sectors of the North Sea.
During the remainder of 2010, five of our rigs will require 5-year surveys, and we expect that
they will be out of service for approximately 325 days in the aggregate. We also expect to spend
an additional approximately 400 days during the remainder of 2010 for intermediate surveys, the
mobilization of rigs, commissioning and contract acceptance testing and extended maintenance
projects. 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
Overview Contract Drilling Backlog.
We are self-insured for physical damage to rigs and equipment caused by named windstorms in
the U.S. Gulf of Mexico. If a named windstorm in the U.S. Gulf of Mexico causes significant damage
to our rigs or equipment, it could have a material adverse effect on our financial position,
results of operations or cash flows. However, under our current insurance policy that expires on
May 1, 2010, we continue to carry physical damage insurance for certain losses other than those
caused by named windstorms in the U.S. Gulf of Mexico, for which our deductible for physical damage
is $25.0 million per occurrence.
We are
in the process of renewing our principal insurance coverages to be effective May 1,
2010. We expect our coverage and policy limits for physical damage insurance and our policy limits
for liability insurance to be similar to our current policy. However, we expect our deductibles
for marine liability coverage, including for personal injury claims, to be $10.0 million for the
first occurrence and to 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 upon the
nature, severity and frequency of claims which might arise during the policy year.
Critical Accounting Estimates
Our significant accounting policies are discussed in Note 1 of our notes to 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, 2009. There were no material changes to these policies during the three months
ended March 31, 2010.
21
Table of Contents
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 and the geographic regions in
which they operate to enhance the readers understanding of our financial condition, changes in
financial condition and results of operations.
Three Months Ended March 31, 2010 and 2009
Comparative data relating to our revenue and operating expenses by equipment type are listed
below.
Three Months Ended | ||||||||||||
March 31, | Favorable/ | |||||||||||
2010 | 2009 | (Unfavorable) | ||||||||||
(In thousands) | ||||||||||||
CONTRACT DRILLING REVENUE |
||||||||||||
High-Specification Floaters |
$ | 383,788 | $ | 312,134 | $ | 71,654 | ||||||
Intermediate Semisubmersibles |
380,701 | 417,000 | (36,299 | ) | ||||||||
Jack-ups |
79,949 | 126,574 | (46,625 | ) | ||||||||
Total Contract Drilling Revenue |
$ | 844,438 | $ | 855,708 | $ | (11,270 | ) | |||||
Revenues Related to Reimbursable
Expenses |
$ | 15,243 | $ | 30,012 | $ | (14,769 | ) | |||||
CONTRACT DRILLING EXPENSE |
||||||||||||
High-Specification Floaters |
$ | 109,155 | $ | 93,628 | $ | (15,527 | ) | |||||
Intermediate Semisubmersibles |
138,599 | 130,715 | (7,884 | ) | ||||||||
Jack-ups |
52,528 | 68,918 | 16,390 | |||||||||
Other |
4,845 | 4,486 | (359 | ) | ||||||||
Total Contract Drilling Expense |
$ | 305,127 | $ | 297,747 | $ | (7,380 | ) | |||||
Reimbursable Expenses |
$ | 14,705 | $ | 29,715 | $ | 15,010 | ||||||
OPERATING INCOME |
||||||||||||
High-Specification Floaters |
$ | 274,633 | $ | 218,506 | $ | 56,127 | ||||||
Intermediate Semisubmersibles |
242,102 | 286,285 | (44,183 | ) | ||||||||
Jack-ups |
27,421 | 57,656 | (30,235 | ) | ||||||||
Other |
(4,845 | ) | (4,486 | ) | (359 | ) | ||||||
Reimbursable expenses, net |
538 | 297 | 241 | |||||||||
Depreciation |
(97,402 | ) | (85,062 | ) | (12,340 | ) | ||||||
General and administrative expense |
(16,654 | ) | (16,315 | ) | (339 | ) | ||||||
Gain on disposition of assets |
884 | 55 | 829 | |||||||||
Total Operating Income |
$ | 426,677 | $ | 456,936 | $ | (30,259 | ) | |||||
Other income (expense): |
||||||||||||
Interest income |
1,282 | 576 | 706 | |||||||||
Interest expense |
(22,321 | ) | (1,117 | ) | (21,204 | ) | ||||||
Foreign currency transaction gain (loss) |
461 | (4,125 | ) | 4,586 | ||||||||
Other, net |
(87 | ) | 1,067 | (1,154 | ) | |||||||
Income before income tax expense |
406,012 | 453,337 | (47,325 | ) | ||||||||
Income tax expense |
(115,159 | ) | (104,756 | ) | (10,403 | ) | ||||||
NET INCOME |
$ | 290,853 | $ | 348,581 | $ | (57,728 | ) | |||||
During the first quarter of 2010, the weak global economy continued to negatively impact
our industry despite an improvement in oil prices from the same time a year ago. Although our
contracted revenue backlog enabled us to partially mitigate the impact of these market conditions,
our operating income decreased 7%, or $30.3 million, compared to the first quarter of 2009.
Aggregate revenues for the first quarter of 2010 decreased $11.3 million, or 1%, compared to the
first quarter of 2009, and average utilization for our overall fleet decreased from 80% during the
first quarter of 2009 to 74% during the first quarter of 2010. Revenues generated by our
intermediate
22
Table of Contents
semisubmersible and jack-up fleets decreased $82.9 million, primarily due to a
reduction in utilization compared to
the first quarter of 2009. However, this decline in revenues was partially offset by a $71.7
million increase in revenues generated by our high-specification floater fleet. In response to a
contraction in demand for our drilling services, as of the date of this report, we have cold
stacked our three mat-supported rigs in the GOM and one intermediate semisubmersible rig, and
currently are not actively marketing these rigs.
Total contract drilling expense increased $7.4 million, or 2%, during the first quarter of
2010 compared to the same period in 2009, primarily due to higher amortized mobilization expenses
and higher operating costs due to several of our rigs operating internationally compared to
operating in the GOM in the first quarter of 2009. This increase was partially offset by lower
costs resulting from fewer regulatory surveys and maintenance projects.
Depreciation expense increased $12.3 million to $97.4 million during the first quarter of
2010, or 14% compared to the first quarter of 2009, due to a higher depreciable asset base.
High-Specification Floaters.
Three Months Ended | ||||||||||||
March 31, | Favorable/ | |||||||||||
2010 | 2009 | (Unfavorable) | ||||||||||
(In thousands) | ||||||||||||
HIGH-SPECIFICATION FLOATERS: |
||||||||||||
CONTRACT DRILLING REVENUE |
||||||||||||
GOM |
$ | 190,120 | $ | 244,874 | $ | (54,754 | ) | |||||
Australia/Asia/Middle East |
40,080 | 34,660 | 5,420 | |||||||||
Europe/Africa/Mediterranean |
56,321 | | 56,321 | |||||||||
South America |
97,267 | 32,600 | 64,667 | |||||||||
Total Contract Drilling Revenue |
$ | 383,788 | $ | 312,134 | $ | 71,654 | ||||||
CONTRACT DRILLING EXPENSE |
||||||||||||
GOM |
$ | 41,941 | $ | 65,174 | $ | 23,233 | ||||||
Australia/Asia/Middle East |
9,238 | 7,409 | (1,829 | ) | ||||||||
Europe/Africa/Mediterranean |
11,001 | | (11,001 | ) | ||||||||
South America |
46,975 | 21,045 | (25,930 | ) | ||||||||
Total Contract Drilling Expense |
$ | 109,155 | $ | 93,628 | $ | (15,527 | ) | |||||
OPERATING INCOME |
$ | 274,633 | $ | 218,506 | $ | 56,127 | ||||||
GOM. Revenues generated by our high-specification floaters operating in the GOM
decreased $54.8 million during the first quarter of 2010 compared to the same period in 2009.
Beginning late in the first quarter of 2009 through early 2010, we relocated four of our
high-specification semisubmersible rigs from the GOM to other international locations. The Ocean
Quest (relocated late first quarter 2009) and Ocean Star (relocated early first quarter 2010) are
currently operating offshore Brazil, and the Ocean Valiant (relocated early third quarter 2009) is
currently operating offshore Angola. The Ocean America is in transit to Australia (relocated late
first quarter 2010) with an expected arrival in mid-second quarter 2010. The effect of these rig
relocations was a net $92.8 million reduction in revenues in the first quarter of 2010 compared to
the same quarter in 2009.
Partially offsetting the negative effect of the rig relocations discussed above was the
operation of the Ocean Monarch for the entire first quarter of 2010, compared to only 17 days
during the first quarter of 2009 following its major upgrade. The Ocean Monarch contributed an
additional $32.2 million in revenues during the first three months of 2010.
Total operating costs during the first quarter of 2010 for our high-specification floaters in
the GOM decreased $23.2 million, primarily as a result of a reduction in normal operating costs for
the four rigs transferred out of the GOM, as well as a reduction in costs associated with a 2009
special survey for the Ocean America. The decrease in operating costs, comparing the quarters, was
partially offset by increased costs associated with normal operations of the Ocean Monarch in the
GOM for the entire first quarter of 2010 compared to only a portion of the quarter in 2009.
Australia/Asia/Middle East. During the first quarter of 2010, the Ocean Rover, our
high-specification rig operating offshore Malaysia, generated $5.4 million in additional revenues
compared to the first quarter of 2009.
23
Table of Contents
The increase in revenues was primarily due to an increase
in the average operating dayrate from $389,700 earned during the first quarter of 2009 to $451,100
during the first quarter of 2010.
Europe/Africa/Mediterranean. The Ocean Valiant, which began operating offshore Angola in
mid-September 2009, generated revenues of $56.3 million and incurred normal operating costs of
$11.0 million during the first quarter of 2010.
South America. Revenues earned by our high-specification floaters operating offshore Brazil
in the first quarter of 2010 increased $64.7 million compared to the first quarter of 2009. The
relocated Ocean Quest and Ocean Star generated revenues of $52.9 million offshore Brazil during the
first quarter of 2010. The Ocean Courage, which began operating late in the first quarter of 2010,
generated $15.3 million in revenues.
Contract drilling expense for our operations in Brazil increased $25.9 million during the
first quarter of 2010 compared to the same period in 2009, primarily due to the inclusion of normal
operating costs for the Ocean Quest, Ocean Star and Ocean Courage during the first quarter of 2010.
Operating costs for the first quarter of 2010 also included costs to mobilize the Ocean Alliance
to a shipyard for an intermediate survey and other shipyard work expected to be completed in the
second quarter of 2010.
Intermediate Semisubmersibles.
Three Months Ended | ||||||||||||
March 31, | Favorable/ | |||||||||||
2010 | 2009 | (Unfavorable) | ||||||||||
(In thousands) | ||||||||||||
INTERMEDIATE SEMISUBMERSIBLES: |
||||||||||||
CONTRACT DRILLING REVENUE |
||||||||||||
GOM |
$ | 19,552 | $ | 51,300 | $ | (31,748 | ) | |||||
Mexico |
23,752 | 53,930 | (30,178 | ) | ||||||||
Australia/Asia/Middle East |
85,028 | 116,352 | (31,324 | ) | ||||||||
Europe/Africa/Mediterranean |
66,537 | 124,166 | (57,629 | ) | ||||||||
South America |
185,832 | 71,252 | 114,580 | |||||||||
Total Contract Drilling Revenue |
$ | 380,701 | $ | 417,000 | $ | (36,299 | ) | |||||
CONTRACT DRILLING EXPENSE |
||||||||||||
GOM |
$ | 6,428 | $ | 12,210 | $ | 5,782 | ||||||
Mexico |
10,852 | 10,964 | 112 | |||||||||
Australia/Asia/Middle East |
24,824 | 26,203 | 1,379 | |||||||||
Europe/Africa/Mediterranean |
22,421 | 32,518 | 10,097 | |||||||||
South America |
74,074 | 48,820 | (25,254 | ) | ||||||||
Total Contract Drilling Expense |
$ | 138,599 | $ | 130,715 | $ | (7,884 | ) | |||||
OPERATING INCOME |
$ | 242,102 | $ | 286,285 | $ | (44,183 | ) | |||||
GOM. Revenues for our rigs working in the GOM decreased $31.7 million in the first
quarter of 2010 compared to the same quarter of 2009, primarily due to the relocation of the Ocean
Ambassador to Brazil early in the third quarter of 2009 ($25.6 million). In addition, a decrease
in the average operating dayrate for the Ocean Saratoga from $285,000 in the first quarter of 2009
to $206,600 during the first quarter of 2010 further reduced revenues by $7.1 million.
Contract drilling expense in the GOM decreased by $5.8 million primarily due to the relocation
of the Ocean Ambassador, which incurred $7.6 million in operating costs during the first quarter of
2009. The decline in operating costs was partially offset by incremental costs for the Ocean
Voyager, which returned to the GOM late in the first quarter of 2010 after completion of its
contract with PEMEX Exploración Y Producción, or PEMEX.
Mexico. Operating revenue offshore Mexico decreased $30.2 million for the first quarter of
2010 compared to the prior year quarter, primarily due to the completion of the Ocean Voyagers
contract early in the first quarter of 2010 ($25.8 million). Additionally, the average operating
dayrate earned by the Ocean New Era decreased from $261,700 in the first quarter of 2009 to
$221,100 during the first quarter of 2010, reducing revenues by $3.6 million. We currently have
one semisubmersible rig operating offshore Mexico.
24
Table of Contents
Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working
in the Australia/Asia/Middle East region decreased $31.3 million in the first quarter of 2010
compared to the same period of 2009, primarily due to the stacking of the Ocean Bounty after
completion of its contract offshore Australia at the beginning of the third quarter of 2009.
Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working
in the Europe/Africa/Mediterranean region decreased $57.6 million in the first quarter of 2010
compared to the same period in 2009. We currently have three rigs located in the North Sea (both
U.K. and Norwegian sectors) compared to five rigs during the first quarter of 2009. Subsequent to
the first quarter of 2009, we relocated the Ocean Lexington to Brazil (third quarter of 2009) and
the Ocean Guardian to the Falkland Islands (first quarter of 2010), resulting in a $31.7 million
reduction in revenues generated in the region during the first quarter of 2010 compared to the
prior year quarter. Revenues were further impacted by the early termination of a drilling contract
for the Ocean Nomad in 2009, resulting in a $30.2 million reduction in revenues for the first
quarter of 2010.
Contract drilling expense for our intermediate semisubmersible rigs operating in the
Europe/Africa/Mediterranean markets decreased $10.1 million in the first quarter of 2010 compared
to the first quarter of 2009, primarily due to the relocation of the Ocean Lexington and Ocean
Guardian from the region.
South America. Revenues generated by our intermediate semisubmersibles working in the South
American region increased $114.6 million in the first quarter of 2010 compared to the same period
in 2009. Currently we have nine rigs operating in this region, including the Ocean Guardian in the
Falkland Islands, compared to six rigs operating in the region during the first quarter of 2009.
The three rigs transferred to the region subsequent to the first quarter of 2009 generated $56.4
million in additional revenues during the first quarter of 2010.
Average operating revenue per day for our other intermediate semisubmersible rigs which
operated offshore Brazil during both the 2009 and 2010 periods was $242,300 during the first
quarter of 2010 compared to $181,400 during the first quarter of 2009, which generated $21.0
million in additional revenues. Utilization for these rigs increased from 71% during the first
quarter of 2009 to 97% during the first quarter of 2010 and generated $36.9 million in incremental
revenues.
The $25.3 million increase in operating costs in the region for the first quarter of 2010,
compared to the same quarter of 2009, was primarily the result of two additional rigs operating
offshore Brazil and the Ocean Guardian operating in the Falkland Islands during the current year
quarter.
Jack-Ups.
Three Months Ended | ||||||||||||
March 31, | Favorable/ | |||||||||||
2010 | 2009 | (Unfavorable) | ||||||||||
(In thousands) | ||||||||||||
JACK-UPS: |
||||||||||||
CONTRACT DRILLING REVENUE |
||||||||||||
GOM |
$ | 13,632 | $ | 30,129 | $ | (16,497 | ) | |||||
Mexico |
18,732 | 26,718 | (7,986 | ) | ||||||||
Australia/Asia/Middle East |
33,821 | 23,211 | 10,610 | |||||||||
Europe/Africa/Mediterranean |
13,748 | 25,666 | (11,918 | ) | ||||||||
South America |
16 | 20,850 | (20,834 | ) | ||||||||
Total Contract Drilling Revenue |
$ | 79,949 | $ | 126,574 | $ | (46,625 | ) | |||||
CONTRACT DRILLING EXPENSE |
||||||||||||
GOM |
$ | 20,117 | $ | 24,957 | $ | 4,840 | ||||||
Mexico |
11,043 | 8,059 | (2,984 | ) | ||||||||
Australia/Asia/Middle East |
11,762 | 14,032 | 2,270 | |||||||||
Europe/Africa/Mediterranean |
8,402 | 10,674 | 2,272 | |||||||||
South America |
1,204 | 11,196 | 9,992 | |||||||||
Total Contract Drilling Expense |
$ | 52,528 | $ | 68,918 | $ | 16,390 | ||||||
OPERATING INCOME |
$ | 27,421 | $ | 57,656 | $ | (30,235 | ) | |||||
25
Table of Contents
GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $16.5 million
during the first quarter of 2010 compared to the first quarter of 2009. Average utilization
decreased to 40% during the first quarter of 2010 from 56% during the prior year quarter and
resulted in a $10.0 million reduction in revenues. In addition, average revenue per day for our
GOM jack-up fleet decreased to $54,600 for the first quarter of 2010 from $86,100 during the first
quarter of 2009, resulting in an additional $11.7 million reduction in revenues. The overall
revenue decrease was partially offset by the favorable impact of relocating two rigs to the GOM
subsequent to the first quarter of 2009 (the Ocean Columbia from Mexico and the Ocean Scepter from
Argentina), which generated $5.2 million in incremental revenues in the GOM.
Contract drilling expense for our jack-ups operating in the GOM decreased $4.8 million during
the first quarter of 2010, compared to the same period in 2009, primarily due to a reduction in
operating costs for our three mat-supported jack-up units that were cold stacked in the second
quarter of 2009 and the absence of costs for the Ocean Summit which relocated to Mexico in the
third quarter of 2009. This decrease in costs was partially offset by normal operating,
mobilization and survey and related costs for the Ocean Columbia and Ocean Scepter, which were
incremental to the region in the first quarter of 2010.
Mexico. Revenue generated by our jack-up fleet operating offshore Mexico during the first
quarter of 2010 decreased $8.0 million compared to same quarter in 2009, primarily due to the
relocation of the Ocean Columbia to the GOM after completion of its contract with PEMEX in the
fourth quarter of 2009 and unpaid downtime for an intermediate survey of the Ocean Nugget. The
overall negative impact on revenues was partially offset by incremental revenue generated by the
Ocean Summit during the first quarter of 2010.
The $3.0 million increase in operating costs during the first quarter of 2010, compared to the
first quarter of 2009, was primarily attributable to the inclusion of normal operating costs for
the Ocean Summit, partially offset by a reduction in operating costs resulting from the relocation
of the Ocean Columbia to the GOM during the first quarter of 2010.
Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the
Australia/Asia/Middle East region increased $10.6 million in the first quarter of 2010 compared to
the same period in 2009. The increase in revenues generated in the region was primarily due to an
increase in utilization for the Ocean Sovereign, which operated the entire current year quarter
compared to the first quarter of 2009 when the rig incurred 59 days of unpaid downtime for a
regulatory survey and shipyard projects.
Contract drilling expense for our jack-up rigs operating in the Australia/Asia/Middle East
region decreased $2.3 million in the first quarter of 2010 due to a reduction in costs associated
with the 2009 survey of the Ocean Sovereign, partially offset by an increase in operating costs for
the Ocean Shield.
Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the
Europe/Africa/Mediterranean region decreased $11.9 million during the first quarter of 2010
compared to the same period in 2009. The decrease in revenue was primarily due to lower dayrates
earned by each of our jackup-rigs in the region, compared to those earned during the same quarter
of the prior year. Average operating revenue per day decreased from $118,900 during the first
quarter of 2009 to $61,300 for the first quarter of 2010.
Operating costs in the Europe/Africa/Mediterranean region decreased $2.3 million during the
first quarter of 2010, compared to the same quarter in 2009, primarily due to the absence of costs
associated with a survey and repairs for the Ocean Heritage during the prior year quarter.
South America. Contract drilling revenues and expenses decreased in the first quarter of 2010
compared to same period in 2009. Our sole jack-up rig in the South America region, the Ocean
Scepter, completed its contract offshore Argentina in the third quarter of 2009 and was
subsequently relocated to the GOM at the end of 2009.
Depreciation.
Depreciation expense increased $12.3 million to $97.4 million during the first quarter of 2010
compared to $85.1 million during the same period in 2009, primarily due to depreciation associated
with capital additions in 2009 and 2010, including depreciation of our recently acquired Ocean
Courage that was placed in service in September 2009.
26
Table of Contents
Interest Expense.
Interest expense for the quarters ended March 31, 2010 and 2009 relates primarily to interest
accrued on our outstanding indebtedness and our liabilities for uncertain tax positions. During
the first quarter of 2010, interest expense included $7.3 million related to our 5.875% Senior
Notes due 2019, issued in May 2009, and $7.1 million related to our 5.70% Senior Notes due 2039.
During the first quarter of 2009, we reversed $5.5 million of previously accrued interest expense
related to an uncertain tax position for which the statute of limitations had expired.
Income Tax Expense.
Our estimated annual effective tax rate for the three months ended March 31, 2010 was 28.6%,
compared to the 25.1% estimated annual effective tax rate for the same period in 2009. The higher
effective tax rate in the current quarter is a result of differences in the mix of our domestic and
international pre-tax earnings and losses, respectively, as well as the mix of international tax
jurisdictions in which we operate. Also contributing to the higher effective tax rate in the
current period was the expiration on December 31, 2009 of a tax law provision which allowed us to
defer recognition of certain foreign earnings for U.S. income tax purposes. The United States
Congress currently has a bill pending to extend this tax law provision for an additional year
which, if passed, is expected to be retroactive to January 1, 2010 and would allow us to defer
recognition of certain foreign earnings for U.S. income tax purposes. However, our estimated
annual effective tax rate for the three months ended March 31, 2010 reflects applicable tax law as
of March 31, 2010 as the pending legislation has not been enacted.
During the three months ended March 31, 2009, we reversed $5.5 million of previously accrued
interest expense and $5.9 million of previously accrued tax expense ($0.8 million of which had been
accrued for penalties) due to the expiration of the statute of limitations related to a 2003
uncertain tax position.
Sources of Liquidity and Capital Resources
Our principal sources of liquidity and capital resources are cash flows from our operations
and our cash reserves. We may also make use of our $285 million credit facility for cash
liquidity. See $285 Million Revolving Credit Facility.
At March 31, 2010, we had $306.1 million in Cash and cash equivalents and $650.8 million in
Investments and marketable securities, representing our investment of cash available for current
operations. Our Consolidated Balance Sheets at March 31, 2010 also included a $100.0 million
Payable for purchase of marketable securities relating to an investment in U.S. Treasury Bills
that did not settle until the subsequent month.
Cash Flows from Operations. Our cash flows from operations are impacted by the ability of our
customers to weather instability in the U.S. and global economies and restrictions in the credit
market, as well as the volatility in energy prices. In general, before working for a customer with
whom we have not had a prior business relationship and/or whose financial stability may appear
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.
If a potential customer is unable to obtain an adequate level of credit, it may preclude us from
doing business with that potential customer.
During 2009, we amended an existing contractual agreement at a customers request to provide
short-term financial relief. The amended contract obligates the customer to pay us over the term
of the six-well drilling program, $75,000 per day in accordance with our normal credit terms (due
30 days after receipt of invoice) and the remainder of the contractual dayrate, $485,000 per day,
through the conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas
producing properties. Based on the current production payout estimate, we anticipate that the
first payment from the conveyance of the NPI will commence in the second quarter of 2010. Payment
of such amounts, and the timing of such payments, are contingent upon such production and upon
energy sale prices.
At March 31, 2010, the $94.5 million portion of this trade receivable payable from the NPI is
presented as Accounts receivable in our Consolidated Balance Sheets included in Item 1 Part I of
this report. At March 31, 2010, we believe that collectability of the amount owed pursuant to the
NPI arrangement is reasonably assured.
These external factors which affect our cash flows from operations are not within our control
and are difficult to predict. For a description of other factors that could affect our cash flows
from operations, see Overview
27
Table of Contents
Industry Conditions, Forward-Looking Statements and Risk Factors in Item 1A of our Annual
Report on Form 10-K for the year ended December 31, 2009.
$285 Million Revolving Credit Facility. We maintain a $285 million syndicated, senior
unsecured revolving credit facility, or Credit Facility, for general corporate purposes, including
loans and performance or standby letters of credit, that will mature on November 2, 2011.
Loans under the Credit Facility bear interest at a rate per annum equal to, at our election,
either (i) the higher of the prime rate or the federal funds rate plus 0.5% or (ii) the London
Interbank Offered Rate, or LIBOR, plus an applicable margin, varying from 0.20% to 0.525%, based on
our current credit ratings. Under our Credit Facility, we also pay, based on our current credit
ratings, and as applicable, other customary fees, including, but not limited to, a facility fee on
the total commitment under the Credit Facility regardless of usage and a utilization fee that
applies if the aggregate of all loans outstanding under the Credit Facility equals or exceeds 50%
of the total commitment under the facility. Changes in credit ratings could lower or raise the
fees that we pay under the Credit Facility.
The Credit Facility contains customary covenants, including, but not limited to, the
maintenance of a ratio of consolidated indebtedness to total capitalization, as defined in the
Credit Facility, of not more than 60% at the end of each fiscal quarter and limitations on liens,
mergers, consolidations, liquidation and dissolution, changes in lines of business, swap
agreements, transactions with affiliates and subsidiary indebtedness.
Based on our current credit ratings at March 31, 2010, the applicable margin on LIBOR loans
would have been 0.24%. As of March 31, 2010, there were no loans outstanding under the Credit
Facility; however $63.1 million in letters of credit were issued and outstanding under the Credit
Facility.
Liquidity and Capital Requirements
Our liquidity and capital requirements are primarily a function of our working capital needs,
capital expenditures and debt service requirements. We determine the amount of cash required to
meet our capital commitments by evaluating the need to upgrade rigs to meet specific customer
requirements and by evaluating our ongoing rig equipment replacement and enhancement programs,
including water depth and drilling capability upgrades. We believe that our operating cash flows
and cash reserves will be sufficient to meet both our working capital requirements and our capital
commitments over the next twelve months; however, we will continue to make periodic assessments
based on industry conditions and will adjust capital spending programs if required.
In addition, 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 market
conditions and other factors beyond our control. Additionally, we may also make use of our Credit
Facility to finance capital expenditures or for other general corporate purposes.
Contractual Cash Obligations.
At March 31, 2010, we had foreign currency forward exchange, or FOREX, contracts outstanding
in the aggregate notional amount of $77.6 million outstanding. See further information regarding
these contracts in Item 3, Quantitative and Qualitative Disclosures About Market Risk Foreign
Exchange Risk and Note 4 Derivative Financial Instruments to our Consolidated Financial
Statements in Item 1 of Part I of this report.
As of March 31, 2010, the total unrecognized tax benefit related to uncertain tax positions
was $34.3 million. Due to the high degree of uncertainty regarding the timing of future cash
outflows associated with the liabilities recognized in this balance, we are unable to make
reasonably reliable estimates of the period of cash settlement with the respective taxing
authorities.
We had no purchase obligations for major rig upgrades or any other significant obligations at
March 31, 2010, except for those related to our direct rig operations, which arise during the
normal course of business.
28
Table of Contents
Other Commercial Commitments Letters of Credit.
We were contingently liable as of March 31, 2010 in the amount of $171.6 million under certain
performance, bid, supersedeas, tax appeal and custom bonds and letters of credit, including $63.1
million in letters of credit issued under our Credit Facility. We purchased five of these bonds
totaling $82.4 million from a related party after obtaining competitive quotes. Agreements
relating to approximately $82.4 million of performance bonds can require collateral at any time.
As of March 31, 2010, 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 March 31, | ||||||||||||||||
Total | 2010 | 2011 | Thereafter | |||||||||||||
(In thousands) | ||||||||||||||||
Other Commercial Commitments |
||||||||||||||||
Customs bonds |
$ | 47,085 | $ | 47,085 | $ | | $ | | ||||||||
Performance bonds |
96,121 | 49,535 | 34,762 | 11,824 | ||||||||||||
Other |
28,422 | 27,422 | 1,000 | | ||||||||||||
Total obligations |
$ | 171,628 | $ | 124,042 | $ | 35,762 | $ | 11,824 | ||||||||
Credit Ratings.
Our current credit rating is Baa1 for Moodys Investors Services and A- for Standard & Poors.
Although our long-term ratings continue at investment grade levels, lower ratings would result in
higher rates for borrowings under our Credit Facility and could also result in higher interest
rates on future debt issuances.
Capital Expenditures.
We have budgeted approximately $435 million on capital expenditures for 2010 associated with
our ongoing rig equipment replacement and enhancement programs, equipment required for our
long-term international contracts and other corporate requirements. In addition, we expect to
spend approximately $75 million in 2010 towards the commissioning and outfitting for service of the
recently acquired Ocean Courage and Ocean Valor. During the first quarter of 2010, we spent
approximately $107.8 million towards these programs. We expect to finance our 2010 capital
expenditures through the use of our existing cash balances or internally generated funds. From
time to time, however, we may also make use of our Credit Facility to finance capital expenditures.
Off-Balance Sheet Arrangements.
At March 31, 2010 and December 31, 2009, we had no off-balance sheet debt or other
arrangements.
Historical Cash Flows
The following is a discussion of our historical cash flows from operating, investing and
financing activities for the three months ended March 31, 2010 compared to the three months ended
March 31, 2009.
Net Cash Provided by Operating Activities.
Three Months Ended March 31, | ||||||||||||
2010 | 2009 | Change | ||||||||||
(In thousands) | ||||||||||||
Net income |
$ | 290,853 | $ | 348,581 | $ | (57,728 | ) | |||||
Net changes in operating assets and liabilities |
54,975 | (91,118 | ) | 146,093 | ||||||||
Proceeds from settlement of FOREX contracts
designated as accounting hedges |
2,099 | | 2,099 | |||||||||
Gain on sale and disposition of assets |
(884 | ) | (55 | ) | (828 | ) | ||||||
Loss (gain) on sale of marketable securities |
1 | (597 | ) | 598 | ||||||||
(Gain) loss on FOREX contracts |
(2,099 | ) | 25 | (2,124 | ) | |||||||
Deferred tax provision |
(4,843 | ) | 8,365 | (13,208 | ) | |||||||
Depreciation and other non-cash items, net |
124,779 | 141,878 | (17,100 | ) | ||||||||
$ | 464,881 | $ | 407,079 | $ | 57,802 | |||||||
29
Table of Contents
Our cash flows from operations during the first three months of 2010 increased $57.8 million,
or 14%, compared to the same period in 2009, primarily due to a decrease in net cash needed to
satisfy our working capital needs partially offset by a decrease in earnings in 2010 compared to
2009. We used $146.1 million less cash to satisfy our working capital requirements during the
first quarter of 2010 compared to the first quarter of 2009. Trade and other receivables used cash
of $44.8 million during the first three months of 2010 compared to $114.0 million during the
comparable period of 2009. The reduction in working capital requirements in the first quarter of
2010 also reflects an increase in U.S. and foreign income taxes payable on earnings during the
first quarter of 2010 compared to the same period of the prior year, which contributed an aggregate
$70.4 million to net cash flows from operations. During the first three months of 2010, we made
U.S. federal income tax payments and paid foreign income taxes, net of refunds, of $0.5 million and
$37.3 million, respectively. During the first three months of 2009, we paid foreign income taxes
net of refunds of $47.8 million.
Net Cash Used in Investing Activities.
Three Months Ended March 31, | ||||||||||||
2010 | 2009 | Change | ||||||||||
(In thousands) | ||||||||||||
Purchase of marketable securities |
$ | (1,349,900 | ) | $ | (1,149,112 | ) | $ | (200,788 | ) | |||
Proceeds from sale and maturities of marketable securities |
1,200,053 | 1,348,964 | (148,911 | ) | ||||||||
Capital expenditures |
(107,798 | ) | (130,408 | ) | 22,610 | |||||||
Proceeds from disposition of assets |
989 | 325 | 664 | |||||||||
Cost of settlement of FOREX contracts |
| (24,789 | ) | 24,789 | ||||||||
$ | (256,656 | ) | $ | 44,980 | $ | (301,636 | ) | |||||
Our investing activities used $256.7 million during the first three months of 2010 compared to
providing $45.0 million during the comparable period in 2009. During the first quarter of 2010 we
purchased marketable securities, net of sales, of $149.8 million compared to net sales of $199.9
million during the same period in 2009. Our level of investment activity is dependent on our
working capital and other capital requirements during the year, as well as a response to actual or
anticipated events or conditions in the securities markets.
During the first three months of 2010, we spent approximately $107.8 million related to
ongoing capital maintenance programs, including rig modifications to meet contractual requirements,
and commissioning/outfitting the Ocean Courage and Ocean Valor, compared to $130.4 million during
the same period in 2009.
Prior to May 2009, we entered into FOREX contracts as economic hedges of our foreign currency
requirements; however, we did not designate these contracts as accounting hedges. During the
latter part of 2008 and during the first quarter of 2009, the strengthening U.S. dollar (or,
conversely, the weakening foreign currency) negatively impacted these expiring FOREX contracts and
resulted in aggregate, net realized losses of $24.8 million for the first quarter of 2009. We have
presented the settlement of these contracts within Net Cash Used in Investing Activities.
Net Cash Used in Financing Activities.
Three Months Ended March 31, | ||||||||||||
2010 | 2009 | Change | ||||||||||
(In thousands) | ||||||||||||
Payment of dividends |
$ | (278,597 | ) | $ | (278,257 | ) | $ | (340 | ) | |||
Other |
9 | | 9 | |||||||||
$ | (278,588 | ) | $ | (278,257 | ) | $ | (331 | ) | ||||
During the first three months of 2010, we paid cash dividends totaling $278.6 million,
consisting of a regular cash dividend of $17.4 million, or $0.125 per share of our common stock,
and a special cash dividend of $261.2 million, or $1.875 per share of our common stock. During the
first three months of 2009, we paid cash dividends totaling $278.3 million, consisting of a regular
cash dividend of $17.4 million, or $0.125 per share of our common stock, and a special cash
dividend of $260.9 million, or $1.875 per share of our common stock.
On April 21, 2010, we declared a regular quarterly cash dividend and a special cash dividend
of $0.125 and $1.375, respectively, per share of our common stock. Both the quarterly and special
cash dividends are payable on June 1, 2010 to stockholders of record on May 3, 2010.
30
Table of Contents
Our Board of Directors has adopted a policy to consider paying special cash dividends, in
amounts to be determined, on a quarterly basis. Our Board of Directors may, in subsequent
quarters, consider paying additional special cash dividends, in amounts to be determined, if it
believes that our financial position, earnings, earnings outlook, capital spending plans and other
relevant factors warrant such action at that time.
Depending on market conditions, we may, from time to time, purchase shares of our common stock
in the open market or otherwise. We did not repurchase any shares of our outstanding common stock
during the three-month periods ended March 31, 2010 and 2009.
Forward-Looking Statements
We or our representatives may, from time to time, either in this report, in periodic press
releases or otherwise, make or incorporate by reference certain written or oral statements that are
forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as
amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended,
or the Exchange Act. All statements other than statements of historical fact are, or may be deemed
to be, forward-looking statements. Forward-looking statements include, without limitation, any
statement that may project, indicate or imply future results, events, performance or achievements,
and may contain or be identified by the words expect, intend, plan, predict, anticipate,
estimate, believe, should, could, 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 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 include, but are not limited to,
information concerning our possible or assumed future results of operations and statements about
the following subjects:
| future market conditions and the effect of such conditions on our future results of operations; | ||
| future uses of and requirements for financial resources; | ||
| interest rate and foreign exchange risk; | ||
| future contractual obligations; | ||
| future operations outside the United States including, without limitation, our operations in Mexico and Brazil; | ||
| business strategy; | ||
| growth opportunities; | ||
| competitive position; | ||
| expected financial position; | ||
| future cash flows and contract backlog; | ||
| future regular or special dividends; | ||
| financing plans; | ||
| market outlook; | ||
| tax planning; | ||
| debt levels, including impacts of the financial crisis and restrictions in the credit market; | ||
| 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 and other capital projects; | ||
| delivery dates and drilling contracts related to rig conversion or upgrade projects or rig acquisitions; | ||
| plans and objectives of management; | ||
| idling drilling rigs or reactivating stacked rigs; | ||
| performance of contracts; | ||
| outcomes of legal proceedings; | ||
| compliance with applicable laws; 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, 2009; |
31
Table of Contents
| general economic and business conditions, including the extent and duration of the continuing financial crisis and restrictions in the credit market, the worldwide economic downturn and recession; | ||
| 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; | ||
| our inability to obtain contracts for our rigs that do not have contracts; | ||
| the cancellation of contracts included in our reported contract backlog; | ||
| advances in exploration and development technology; | ||
| the worldwide political and military environment, including in oil-producing regions; | ||
| casualty losses; | ||
| operating hazards inherent in drilling for oil and gas offshore; | ||
| the risk of physical damage to rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico; | ||
| industry fleet capacity; | ||
| market conditions in the offshore contract drilling industry, including 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 expropriation or nationalization of equipment and assets; | ||
| risks of potential contractual liabilities pursuant to our various drilling contracts in effect from time to time; | ||
| the ability of customers and suppliers to meet their obligations to us and our subsidiaries; | ||
| 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, carbon emissions or energy use; | ||
| compliance with 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 and adequacy of insurance; | ||
| the results of financing efforts; | ||
| the risk that future regular or special dividends may not be declared; | ||
| adequacy of our sources of liquidity; | ||
| risks resulting from our indebtedness; | ||
| the availability of qualified personnel to operate and service our drilling rigs; and | ||
| various other matters, many of which are beyond our control. |
32
Table of Contents
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.
ITEM 3. Quantitative and Qualitative Disclosures About Market Risk.
The information included in this Item 3 is considered to constitute forward-looking
statements for purposes of the statutory safe harbor provided in Section 27A of the Securities Act
and Section 21E of the Exchange Act. See Managements Discussion and Analysis of Financial
Condition and Results of Operations Forward-Looking Statements in Item 2 of Part I of this
report.
Our measure of market risk exposure represents an estimate of the change in fair value of our
financial instruments. Market risk exposure is presented for each class of financial instrument
held by us at March 31, 2010 and December 31, 2009, assuming immediate adverse market movements of
the magnitude described below. We believe that the various rates of adverse market movements
represent a measure of exposure to loss under hypothetically assumed adverse conditions. The
estimated market risk exposure represents the hypothetical loss to future earnings and does not
represent the maximum possible loss or any expected actual loss, even under adverse conditions,
because actual adverse fluctuations would likely differ. In addition, since our investment
portfolio is subject to change based on our portfolio management strategy as well as in response to
changes in the market, these estimates are not necessarily indicative of the actual results that
may occur.
Exposure to market risk is managed and monitored by our senior management. Senior management
approves the overall investment strategy that we employ and has responsibility to ensure that the
investment positions are consistent with that strategy and the level of risk acceptable to us. We
may manage risk by buying or selling instruments or entering into offsetting positions.
Interest Rate Risk
We have exposure to interest rate risk arising from changes in the level or volatility of
interest rates. Our investments in marketable securities are primarily in fixed maturity
securities. We monitor our sensitivity to interest rate risk by evaluating the change in the value
of our financial assets and liabilities due to fluctuations in interest rates. The evaluation is
performed by applying an instantaneous change in interest rates by varying magnitudes on a static
balance sheet to determine the effect such a change in rates would have on the recorded market
value of our investments and the resulting effect on stockholders equity. The analysis presents
the sensitivity of the market value of our financial instruments to selected changes in market
rates and prices which we believe are reasonably possible over a one-year period.
The sensitivity analysis estimates the change in the market value of our interest sensitive
assets and liabilities that were held on March 31, 2010 and December 31, 2009, due to instantaneous
parallel shifts in the yield curve of 100 basis points, with all other variables held constant.
The interest rates on certain types of assets and liabilities may fluctuate in advance of
changes in market interest rates, while interest rates on other types may lag behind changes in
market rates. Accordingly, the analysis may not be indicative of, is not intended to provide, and
does not provide a precise forecast of the effect of changes in market interest rates on our
earnings or stockholders equity. Further, the computations do not contemplate any actions we could
undertake in response to changes in interest rates.
Loans under our $285 million syndicated, senior unsecured revolving Credit Facility bear
interest at our option at a rate per annum equal to (i) the higher of the prime rate or the federal
funds rate plus 0.5% or (ii) LIBOR plus an applicable margin, varying from 0.20% to 0.525%, based
on our current credit ratings. As of March 31, 2010 and December 31, 2009, there were no loans
outstanding under the Credit Facility (however, $63.1 million and $63.3 million in letters of
credit were issued and outstanding under the Credit Facility at March 31, 2010 and December 31,
2009, respectively).
33
Table of Contents
Our long-term debt, as of March 31, 2010 and December 31, 2009, is denominated in U.S.
dollars. Our debt has been primarily issued at fixed rates, and as such, interest expense would not
be impacted by interest rate shifts. The impact of a 100-basis point increase in interest rates on
fixed rate debt would result in a decrease in market value of $119.8 million and $121.3 million as
of March 31, 2010 and December 31, 2009, respectively. A 100-basis point decrease would result in
an increase in market value of $135.3 million and $136.2 million as of March 31, 2010 and December
31, 2009, respectively.
Foreign Exchange Risk
Foreign exchange rate risk arises from the possibility that changes in foreign currency
exchange rates will impact the value of financial instruments. It is customary for us to enter
into foreign currency forward exchange, or FOREX, contracts in the normal course of business.
These 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 certain
contracts is the average spot rate for the contract period. As of March 31, 2010 we had FOREX
contracts outstanding, in the aggregate notional amount of $77.6 million, consisting of $30.1
million in Australian dollars, $27.6 million in Brazilian reais, $10.6 million in British pounds
sterling, $4.0 million in Mexican pesos and $5.3 million in Norwegian kroner. These contracts
settle at various times through September 2010.
At March 31, 2010, we have presented the fair value of our outstanding FOREX contracts as a
current asset of $1.5 million in Prepaid expenses and other current assets and a current
liability of $0.6 million in Accrued liabilities in our Consolidated Balance Sheets.
The following table presents our exposure to market risk by category (interest rates and
foreign currency exchange rates):
Fair Value Asset (Liability) | Market Risk | |||||||||||||||
March 31, | December 31, | March 31, | December 31, | |||||||||||||
2010 | 2009 | 2010 | 2009 | |||||||||||||
(In thousands) | ||||||||||||||||
Interest rate: |
||||||||||||||||
Marketable securities |
$ | 650,756 | (a) | $ | 400,853 | (a) | $ | (200 | ) (c) | $ | (300 | ) (c) | ||||
Long-term debt |
(1,568,900 | ) (b) | (1,546,900 | ) (b) | | | ||||||||||
Foreign Exchange: |
||||||||||||||||
FOREX contracts
receivable positions |
1,500 | (d) | 2,600 | (d) | (11,400 | ) (e) | (17,600 | ) (e) | ||||||||
FOREX contracts
liability positions |
(600 | ) (d) | (200 | ) (d) | (3,000 | ) (e) | (3,700 | ) (e) |
(a) | The fair market value of our investment in marketable securities is based on the quoted closing market prices on March 31, 2010 and December 31, 2009. | |
(b) | The fair values of our 4.875% Senior Notes due July 1, 2015, 5.15% Senior Notes due September 1, 2014, 5.875% Senior Notes due May 1, 2019 and 5.70% Senior Notes due October 15, 2039 are based on the quoted closing market prices on March 31, 2010 and December 31, 2009. The fair value of our Zero Coupon Convertible Debentures due 2020 is based on the closing market price of our common stock on March 31, 2010 and December 31, 2009. | |
(c) | The calculation of estimated market risk exposure is based on assumed adverse changes in the underlying reference price or index of an increase in interest rates of 100 basis points at March 31, 2010 and December 31, 2009. | |
(d) | The fair value of our FOREX contracts is based on both quoted market prices and valuations derived from pricing models on March 31, 2010 and December 31, 2009. | |
(e) | The calculation of estimated foreign exchange risk assumes an instantaneous 20% decrease in the foreign currency exchange rates versus the U.S. dollar from their values at March 31, 2010 and December 31, 2009, with all other variables held constant. |
34
Table of Contents
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 March 31, 2010. Based on their
participation in that evaluation, our CEO and CFO concluded that our disclosure controls and
procedures were effective as of March 31, 2010.
There were no changes in our internal control over financial reporting identified in
connection with the foregoing evaluation that occurred during our first fiscal quarter of 2010 that
have materially affected, or are reasonably likely to materially affect, our internal control over
financial reporting.
PART II. OTHER INFORMATION
ITEM 6. Exhibits.
See the Exhibit Index for a list of those exhibits filed or furnished herewith.
35
Table of Contents
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DIAMOND OFFSHORE DRILLING, INC. (Registrant) |
||||
Date April 27, 2010 | By: | \s\ Gary T. Krenek | ||
Gary T. Krenek | ||||
Senior Vice President and Chief Financial Officer | ||||
Date April 27, 2010 | \s\ Beth G. Gordon | |||
Beth G. Gordon Controller (Chief Accounting Officer) |
||||
36
Table of Contents
EXHIBIT INDEX
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 22, 2007) of Diamond
Offshore Drilling, Inc. (incorporated by reference to Exhibit 3.1 to our Current
Report on Form 8-K filed October 26, 2007). |
|||
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. |
* | Filed or furnished herewith. | |
** | The documents formatted in XBRL (Extensible Business Reporting Language) and attached as Exhibit 101 to this report are deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act, are deemed not filed for purposes of section 18 of the Exchange Act, and otherwise, not subject to liability under these sections. |
37