e10vk
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 2010
OR
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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)
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Delaware
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76-0321760 |
(State or other jurisdiction of incorporation or organization)
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(I.R.S. Employer Identification No.) |
15415 Katy Freeway
Houston, Texas 77094
(Address and zip code of principal executive offices)
(281) 492-5300
(Registrants telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class |
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Name of each exchange on which registered |
Common Stock, $0.01 par value per share
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New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of
the Securities Act. Yes
þ No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or
Section 15(d) of the Act. Yes
o No þ
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants knowledge, in
definitive proxy or information statements incorporated by reference in Part III of this Form 10-K
or any amendment to this Form 10-K. þ
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):
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Large accelerated filer þ |
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Accelerated filer o |
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Non-accelerated filer o |
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Smaller reporting company o |
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(Do not check if a smaller reporting company) |
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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
State the aggregate market value of the voting and non-voting common equity held by non-affiliates
computed by reference to the price at which the common equity was last sold as of the last business
day of the registrants most recently completed second fiscal quarter.
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As of June 30, 2010
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$4,286,231,692 |
Indicate the number of shares outstanding of each of the registrants classes of common stock,
as of the latest practicable date.
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As of February 17, 2011
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Common Stock, $0.01 par value per share
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139,026,897 shares |
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive proxy statement relating to the 2010 Annual Meeting of
Stockholders of Diamond Offshore Drilling, Inc., which will be filed within 120 days of
December 31, 2010, are incorporated by reference in Part III of this report.
DIAMOND OFFSHORE DRILLING, INC.
FORM 10-K for the Year Ended December 31, 2010
TABLE OF CONTENTS
2
PART I
Item 1. Business.
General
Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor
with a current fleet of 46 offshore rigs consisting of 32 semisubmersibles, 13 jack-ups and one
drillship. In addition, in December 2010, we entered into a turnkey contract for construction of a
new dynamically positioned, ultra-deepwater drillship with delivery scheduled for late in the
second quarter of 2013, and, in January 2011, we entered into another turnkey contract for the
construction of a second, sister drillship with delivery scheduled for the fourth quarter of 2013.
See Fleet Enhancements and Additions. Unless the context otherwise requires, references in
this report to Diamond Offshore, we, us or our mean Diamond Offshore Drilling, Inc. and our
consolidated subsidiaries. We were incorporated in Delaware in 1989.
The Fleet
Our fleet includes some of the most technologically advanced rigs in the world, enabling us to
offer a broad range of services worldwide in various markets, including the deepwater, harsh
environment, conventional semisubmersible and jack-up markets.
Semisubmersibles. We own and operate 32 semisubmersibles, consisting of 13 high-specification
and 19 intermediate rigs. Semisubmersible rigs consist of an upper working and living deck resting
on vertical columns connected to lower hull members. Such rigs operate in a semi-submerged
position, remaining afloat, off bottom, in a position in which the lower hull is approximately 55
feet to 90 feet below the water line and the upper deck protrudes well above the surface.
Semisubmersibles are typically anchored in position and remain stable for drilling in the
semi-submerged floating position due in part to their wave transparency characteristics at the
water line. Semisubmersibles can also be held in position through the use of a computer controlled
thruster (dynamic-positioning) system to maintain the rigs position over a drillsite. We have five
semisubmersible rigs in our fleet with this capability.
Our high-specification semisubmersibles are generally capable of working in water depths of
4,000 feet or greater or in harsh environments and have other advanced features, as compared to
intermediate semisubmersibles. As of January 24, 2011, six of our 13 high-specification
semisubmersibles were located offshore Brazil, and two were located in the United States, or U.S.,
Gulf of Mexico, or GOM. Of our remaining high-specification semisubmersibles, one was located
offshore each of Angola, Egypt, Indonesia and the Republic of Congo and one was in a shipyard in
Singapore.
Our intermediate semisubmersibles generally work in maximum water depths up to 3,999 feet. As
of January 24, 2011, we had 19 intermediate semisubmersible rigs in various locations around the
world. Nine of these semisubmersibles were operating in the South America region, including eight
offshore Brazil and one offshore the Falkland Islands; three were located in the North Sea; two
were located offshore Australia; one was located offshore Vietnam and one was cold stacked in
Malaysia. Our remaining three intermediate semisubmersibles are located in the GOM, where two have
been cold stacked.
Drillship. We currently have one high-specification drillship, the Ocean Clipper, which was
located offshore Brazil as of January 24, 2011. Drillships, which are typically self-propelled,
are positioned over a drillsite through the use of either an anchoring system or a
dynamic-positioning system similar to those used on certain semisubmersible rigs. Deepwater
drillships compete in many of the same markets as do high-specification semisubmersible rigs. See
Fleet Enhancements and Additions.
Both semisubmersible rigs and drillships are commonly referred to as floaters in the offshore
drilling industry.
Jack-ups. We currently have 13 jack-up drilling rigs. Jack-up rigs are mobile,
self-elevating drilling platforms equipped with legs that are lowered to the ocean floor until a
foundation is established to support the drilling platform. The rig hull includes the drilling rig,
jacking system, crew quarters, loading and unloading facilities, storage areas for bulk and liquid
materials, heliport and other related equipment. Our jack-ups are used for drilling in water
depths from 20 feet to 350 feet. The water depth limit of a particular rig is principally
determined by the length of the rigs legs. A jack-up rig is towed to the drillsite with its hull
riding in the sea, as a vessel, with its legs
3
retracted. Once over a drillsite, the legs are
lowered until they rest on the seabed and jacking continues with the legs penetrating the seabed
until resistance is sufficient to elevate the hull above the surface of the water. After completion
of drilling operations, the hull is lowered until it rests in the water and then the legs are
retracted for relocation to another drillsite.
Most of our jack-up rigs are equipped with a cantilever system that enables the rig to
cantilever or extend its drilling package over the aft end of the rig. This is particularly
important when attempting to drill over existing platforms. Cantilever rigs have historically
earned higher dayrates and achieved greater utilization compared to slot rigs, which do not have
this capability.
As of January 24, 2011, six of our 13 jack-up rigs were located in the GOM, of which four
units have been cold stacked, consisting of two mat-supported cantilevered units, one mat-supported
slot unit and one independent-leg, cantilevered unit. Of our seven remaining jack-up rigs, all of
which are independent-leg cantilevered units, two each were located offshore Egypt and Mexico, and
one was located offshore each of Brazil and Montenegro. Our remaining jack-up rig was en route to
Thailand.
Fleet Enhancements and Additions. Our long-term strategy has been to economically upgrade our
fleet to meet customer demand for advanced, efficient, high-tech rigs, particularly deepwater
semisubmersibles, in order to maximize the utilization of, and dayrates earned by, the rigs in our
fleet. In December 2010 and January 2011, we entered into separate turnkey contracts with Hyundai
Heavy Industries Co., Ltd., or Hyundai, for the construction of two dynamically positioned,
ultra-deepwater drillships with deliveries scheduled for late in the second and fourth quarters of
2013. We expect total cost for the sister drillships, including commissioning, spares and project
management, to aggregate approximately $1.2 billion. In addition, we have also obtained from
Hyundai a fixed-price option for the purchase of a third drillship, which we have the right to
exercise at any time before the end of the first quarter of 2011.
In
June 2009 and September 2009, we acquired two new-build deepwater, dynamically positioned,
semisubmersible drilling rigs, the Ocean Courage and the Ocean Valor, respectively. Including our
rig acquisitions in 2009 and our two recent drillship orders, we have purchased, ordered or
upgraded seven units with capabilities in 10,000 feet of water over the last four years.
We will evaluate further rig acquisition and upgrade opportunities as they arise. However, we
can provide no assurance whether, or to what extent, we will continue to make rig acquisitions or
upgrades to our fleet. See Managements Discussion and Analysis of Financial Condition and
Results of Operations Liquidity and Capital Requirements in Item 7 of this report.
4
More detailed information concerning our fleet of mobile offshore drilling rigs, as of
January 24, 2011, is set forth in the table below.
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Nominal |
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Water Depth |
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Year Built/Latest |
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Current |
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Type and Name |
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Rating (a) |
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Attributes |
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Enhancement (b) |
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Location (c) |
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Customer (d) |
High-Specification Floaters |
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Semisubmersibles (13): |
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Ocean Valor |
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10,000 |
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DP; 6R; 15K; 4M |
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2009 |
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Brazil |
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Petrobras |
Ocean Courage |
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10,000 |
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DP; 6R; 15K; 4M |
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2009 |
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Brazil |
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Petrobras |
Ocean Confidence |
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10,000 |
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DP; 6R; 15K; 4M |
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2001/2009 |
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Republic of Congo |
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Total/Cobalt Angola rig acceptance |
Ocean Monarch |
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10,000 |
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15K; 4M |
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1974/2008 |
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GOM |
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Anadarko (Force Majeure dispute) |
Ocean Endeavor |
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10,000 |
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15K; 4M |
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1975/2007 |
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Egypt |
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Burullus / RASHPETCO |
Ocean Rover |
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8,000 |
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15K; 4M |
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1973/2008 |
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Indonesia |
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Murphy Exploration |
Ocean Baroness |
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7,000 |
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15K; 4M |
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1973/2002 |
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Brazil |
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Petrobras |
Ocean Victory |
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5,500 |
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15K |
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1972/2006 |
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GOM |
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ATP Oil & Gas |
Ocean America |
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5,500 |
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15K |
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1988/1999 |
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Singapore |
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Shipyard Project |
Ocean Valiant |
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5,500 |
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15K |
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1988/1999 |
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Angola |
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Total |
Ocean Star |
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5,500 |
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15K |
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1974/1999 |
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Brazil |
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OGX |
Ocean Alliance |
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5,250 |
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DP; 15K |
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1988/1999 |
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Brazil |
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Petrobras |
Ocean Quest |
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4,000 |
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15K |
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1973/1996 |
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Brazil |
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OGX |
Drillship (1): |
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Ocean Clipper |
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7,875 |
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DP; 15K |
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1976/1999 |
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Brazil |
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Petrobras |
Intermediate Semisubmersibles (19): |
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Ocean Winner |
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4,000 |
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1977/2004 |
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Brazil |
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Petrobras |
Ocean Worker |
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4,000 |
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1982/2008 |
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Brazil |
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Petrobras |
Ocean Yatzy |
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3,300 |
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DP |
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1989/1998 |
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Brazil |
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Petrobras |
Ocean Voyager |
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3,200 |
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1973/1995 |
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GOM |
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Cold stacked |
Ocean Patriot |
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3,000 |
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15K |
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1982/2003 |
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Australia |
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Apache Energy |
Ocean Epoch |
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3,000 |
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1977/2000 |
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Australia |
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Japan Energy |
Ocean General |
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3,000 |
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1976/2000 |
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Vietnam |
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PVEP Dai Hung |
Ocean Yorktown |
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2,850 |
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1976/1996 |
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Brazil |
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Petrobras |
Ocean Concord |
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2,300 |
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1975/1999 |
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Brazil |
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Petrobras |
Ocean Lexington |
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2,200 |
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1976/1995 |
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Brazil |
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OGX |
Ocean Saratoga |
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2,200 |
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1976/1995 |
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GOM |
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Taylor Energy |
Ocean Whittington |
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1,650 |
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1974/1995 |
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Brazil |
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Petrobras |
Ocean Bounty |
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1,500 |
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1977/1992 |
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Malaysia |
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Cold stacked |
Ocean Guardian |
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1,500 |
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15K |
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1985 |
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Falkland Islands |
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Rockhopper Exploration |
Ocean New Era |
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1,500 |
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1974/1990 |
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GOM |
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Cold stacked |
Ocean Princess |
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1,500 |
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15K |
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1977/1998 |
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North Sea/U.K. |
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Talisman |
Ocean Vanguard |
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1,500 |
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15K |
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1982 |
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North Sea/Norway |
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Statoil |
Ocean Nomad |
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1,200 |
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1975/2001 |
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North Sea/U.K. |
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B G International |
Ocean Ambassador |
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1,100 |
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1975/1995 |
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Brazil |
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OGX |
Jack-ups (13): |
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Ocean Scepter |
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350 |
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IC; 15K |
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2008 |
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Brazil |
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OGX-waiting on IBAMA certification |
Ocean Titan |
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350 |
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IC; 15K |
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1974/2004 |
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GOM |
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Actively marketing |
Ocean King |
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300 |
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IC |
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1973/1999 |
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Montenegro |
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Actively marketing |
Ocean Nugget |
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300 |
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IC |
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1976/1995 |
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Mexico |
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PEMEX |
Ocean Summit |
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300 |
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IC |
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1972/2003 |
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Mexico |
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PEMEX |
Ocean Heritage |
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300 |
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IC |
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1981/2002 |
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Egypt |
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SUCO |
Ocean Spartan |
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300 |
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IC |
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1980/2003 |
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GOM |
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Cold stacked |
Ocean Spur |
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300 |
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IC |
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1981/2003 |
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Egypt |
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WEPCO |
Ocean Sovereign |
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300 |
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IC |
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1981/2003 |
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Enroute to Thailand |
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Diamond Offshore/Salamander |
Ocean Champion |
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250 |
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MS |
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1975/2004 |
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GOM |
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Cold stacked |
Ocean Columbia |
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250 |
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IC |
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1978/1990 |
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GOM |
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Actively marketing |
Ocean Crusader |
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200 |
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MC |
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1982/1992 |
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GOM |
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Cold stacked |
Ocean Drake |
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200 |
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MC |
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1983/1986 |
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GOM |
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Cold stacked |
Under Construction (2) |
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Ocean BlackHornet |
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10,000 |
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DP; 7R; 15K; 5M |
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2013 |
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South Korea |
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On order |
Ocean BlackHawk |
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10,000 |
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DP; 7R; 15K; 5M |
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2013 |
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South Korea |
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On order |
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Attributes |
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DP
= Dynamically Positioned/Self-Propelled
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MS = Mat-Supported Slot Rig
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15K = 15,000 psi well control
system |
IC = Independent-Leg Cantilevered Rig
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6R = Six ram blow out preventer
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4M = Four Mud Pumps |
MC = Mat-Supported Cantilevered Rig
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7R = Seven ram blow out
preventer
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5M = Five Mud Pumps |
See the footnotes to this table on the following page.
5
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(a) |
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Nominal water depth (in feet), as described above for semisubmersibles and drillships,
reflects the current operating water depth capability for each drilling unit. In many cases,
individual rigs are capable of drilling, or have drilled in, greater water depths. In all
cases, floating rigs are capable of working successfully at greater depths than their nominal
water depth. On a case by case basis, we may achieve a greater depth capacity by providing
additional equipment. |
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(b) |
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Such enhancements may include water depth upgrades, mud pump additions and increases in deck
load capacity. |
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(c) |
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GOM means U.S. Gulf of Mexico. One of our drilling rigs was en route between geographic
locations. It has been presented in the preceding table in the geographic location in which
it is expected to commence drilling operations in 2011. |
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(d) |
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For ease of presentation in this table, customer names have been shortened or abbreviated. |
Markets
The principal markets for our offshore contract drilling services are the following:
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South America, principally offshore Brazil and the Falkland Islands; |
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Australia and Asia, including Malaysia, Indonesia, Thailand and Vietnam; |
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the Middle East, including Kuwait, Qatar and Saudi Arabia; |
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Europe, principally in the United Kingdom, or U.K., and Norway; |
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West Africa, including Angola and the Republic of Congo; |
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the Mediterranean Basin, including Egypt; and |
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the Gulf of Mexico, including the U.S. and Mexico. |
We actively market our rigs worldwide. From time to time our fleet operates in various other
markets throughout the world as the market demands. See Note 16 Segments and Geographic Area
Analysis to our Consolidated Financial Statements in Item 8 of this report.
We believe our presence in multiple markets is valuable in many respects. For example, we
believe that our experience with safety and other regulatory matters in the U.K. has been
beneficial in Australia and other international areas in which we operate, while production
experience we have gained through our Brazilian and North Sea operations has potential application
worldwide. Additionally, we believe our performance for a customer in one market segment or area
enables us to better understand that customers needs and better serve that customer in different
market segments or other geographic locations.
Offshore Contract Drilling Services
Our contracts to provide offshore drilling services vary in their terms and provisions. We
typically obtain our contracts through competitive bidding, although it is not unusual for us to be
awarded drilling contracts without competitive bidding. Our drilling contracts generally provide
for a basic drilling rate on a fixed dayrate basis regardless of whether or not such drilling
results in a productive well. Drilling contracts may also provide for lower rates during periods
when the rig is being moved or when drilling operations are interrupted or restricted by equipment
breakdowns, adverse weather conditions or other conditions beyond our control. Under dayrate
contracts, we generally pay the operating expenses of the rig, including wages and the cost of
incidental supplies. Historically, dayrate contracts have accounted for the majority of our
revenues. In addition, from time to time, our dayrate contracts may also provide for the ability
to earn an incentive bonus from our customer based upon performance.
A dayrate drilling contract generally extends over a period of time covering either the
drilling of a single well or a group of wells, which we refer to as a well-to-well contract, or a
fixed term, which we refer to as a term contract, and may be terminated by the customer in the
event the drilling unit is destroyed or lost or if drilling operations are suspended for an
extended period of time as a result of a breakdown of equipment or, in some cases, due to other
events beyond the control of either party to the contract. In addition, certain of our contracts
permit the customer to terminate the contract early by giving notice, and in most circumstances may
require the payment of an early termination fee by the customer. The contract term in many
instances may also be extended by the customer exercising options for the drilling of additional
wells or for an additional length of time, generally at competitive market rates and mutually
agreeable terms at the time of the extension. See Risk Factors The terms of our drilling
contracts may limit our ability to attain profitability in a declining market or to benefit from
increasing dayrates in an improving market, Risk Factors Our drilling contracts may be
terminated due to events beyond our control, Risk Factors Our business involves numerous
operating hazards which could expose us to
6
significant losses and significant damage claims. We
are not fully insured against all of these risks and our contractual indemnity provisions may not
fully protect us and Risk Factors We have elected to self-insure for physical damage to rigs
and equipment caused by named windstorms in the U.S. Gulf of Mexico in Item 1A of this report,
which are incorporated herein by reference. For a discussion of our contract backlog, see
Managements Discussion and Analysis of Financial Condition and Results of Operations Overview
Contract Drilling Backlog in Item 7 of this report, which is incorporated herein by reference.
Customers
We provide offshore drilling services to a customer base that includes major and independent
oil and gas companies and government-owned oil companies. During 2010, 2009 and 2008, we performed
services for 46, 47 and 49 different customers, respectively. During 2010, 2009 and 2008, one of
our two customers in Brazil, Petróleo Brasileiro S.A., or Petrobras (a Brazilian multinational
energy company that is majority-owned by the Brazilian government), accounted for 24%, 15% and 13%
of our annual total consolidated revenues, respectively. OGX Petróleo e Gás Ltda., or OGX (a
privately owned Brazilian oil and natural gas company), accounted for 14% of our annual total
consolidated revenues in 2010. No other customer accounted for 10% or more of our annual total
consolidated revenues during 2010, 2009 or 2008.
Brazil is the most active floater market in the world today. As of the date of this report,
the greatest concentration of our operating assets outside the United States is offshore Brazil,
where we have 16 rigs currently working. Our contract backlog attributable to our expected
operations offshore Brazil is $1.6 billion, $1.5 billion and $987.0 million for the years 2011,
2012 and 2013, respectively, and $1.0 billion in the aggregate for the years 2014 to 2016. See
Managements Discussion and Analysis of Financial Condition and Results of Operations Overview
Contract Drilling Backlog included in Item 7 of this report.
We principally market our services in North America through our Houston, Texas office. We
market our services in other geographic locations principally from our regional offices in
Aberdeen, Scotland and Perth, Australia. We provide technical and administrative support functions
from our Houston office.
Competition
The offshore contract drilling industry is highly competitive with numerous industry
participants, none of which at the present time has a dominant market share. The drilling industry
has experienced consolidation in recent years and may experience additional consolidation, which
could create additional large competitors. Some of our competitors may have greater financial or
other resources than we do. We compete with offshore drilling contractors that together have more
than 730 mobile rigs available worldwide.
The offshore contract drilling industry is influenced by a number of factors, including global
economies and demand for oil and natural gas, current and anticipated prices of oil and natural
gas, expenditures by oil and gas companies for exploration and development of oil and natural gas
and the availability of drilling rigs.
Drilling contracts are traditionally awarded on a competitive bid basis. Intense price
competition is often the primary factor in determining which qualified contractor is awarded a job.
Customers may also consider rig availability and location, a drilling contractors operational and
safety performance record, and condition and suitability of equipment. We believe we compete
favorably with respect to these factors.
We compete on a worldwide basis, but competition may vary significantly by region at any
particular time. See Markets. Competition for offshore rigs generally takes place on a global
basis, as these rigs are highly mobile and may be moved, at a cost that may be substantial, from
one region to another. Competing contractors are able to adjust localized supply and demand
imbalances by moving rigs from areas of low utilization and dayrates to areas of greater activity
and relatively higher dayrates. Significant new rig construction and upgrades of existing drilling
units could also intensify price competition. See Risk Factors Our industry is highly
competitive and cyclical, with intense price competition in Item 1A of this report, which is
incorporated herein by reference.
Governmental Regulation
Our operations are subject to numerous international, U.S., state and local laws and
regulations that relate directly or indirectly to our operations, including regulations controlling
the discharge of materials into the environment, requiring removal and clean-up under some
circumstances, or otherwise relating to the protection of
7
the environment, and may include laws or
regulations pertaining to climate change, carbon emissions or energy use. See Risk Factors The
aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico and new regulations
adopted as a result of the investigation into the Macondo well blowout could negatively impact us,
Risk Factors Governmental laws and regulations, both domestic and international, may add to our
costs or limit our drilling activity and Risk Factors Compliance with or breach of
environmental laws can be costly and could limit our operations in Item 1A of this report, which
are incorporated herein by reference.
Operations Outside the United States
Our operations outside the U.S. accounted for approximately 81%, 66% and 59% of our total
consolidated revenues for the years ended December 31, 2010, 2009 and 2008, respectively. See
Risk Factors A significant portion of our operations are conducted outside the United States and
involve additional risks not associated with domestic operations, Risk Factors Our drilling
contracts offshore Mexico expose us to greater risks than we normally assume and Risk Factors
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us in
Item 1A of this report, which are incorporated herein by reference.
Employees
As of December 31, 2010, we had approximately 5,300 workers, including international crew
personnel furnished through independent labor contractors. We have experienced satisfactory labor
relations and provide comprehensive benefit plans for our employees.
Executive Officers of the Registrant
We have included information on our executive officers in Part I of this report in reliance on
General Instruction G(3) to Form 10-K. Our executive officers are elected annually by our Board of
Directors to serve until the next annual meeting of our Board of Directors, or until their
successors are duly elected and qualified, or until their earlier death, resignation,
disqualification or removal from office. Information with respect to our executive officers is set
forth below.
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Age as of |
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Name |
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January 31, 2011 |
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Position |
Lawrence R. Dickerson
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58 |
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President, Chief Executive Officer and Director |
John M. Vecchio
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60 |
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Executive Vice President |
Gary T. Krenek
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52 |
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Senior Vice President and Chief Financial Officer |
William C. Long
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44 |
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Senior Vice President, General Counsel & Secretary |
Beth G. Gordon
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55 |
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Controller Chief Accounting Officer |
Lyndol L. Dew
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56 |
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Senior Vice President Worldwide Operations |
Lawrence R. Dickerson has served as our President and a Director since March 1998 and as our
Chief Executive Officer since June 2008. Mr. Dickerson served as our Chief Operating Officer from
March 1998 to June 2008. Mr. Dickerson served on the United States Commission on Ocean Policy from
2001 to 2004.
John M. Vecchio has served as Executive Vice President since August 2009. Mr. Vecchio
previously served as our Senior Vice President Technical Services from April 2002 to July 2009.
Gary T. Krenek has served as a Senior Vice President and our Chief Financial Officer since
October 2006. Mr. Krenek previously served as our Vice President and Chief Financial Officer since
March 1998.
William C. Long has served as a Senior Vice President and our General Counsel and Secretary
since October 2006. Mr. Long previously served as our Vice President, General Counsel and
Secretary since March 2001 and as our General Counsel and Secretary from March 1999 through
February 2001.
Beth G. Gordon has served as our Controller and Chief Accounting Officer since April 2000.
Lyndol L. Dew has served as a Senior Vice President since September 2006. Previously, Mr. Dew
served as our Vice President International Operations from January 2006 to August 2006 and as our
Vice President North American Operations from January 2003 to December 2005.
8
Access to Company Filings
We are subject to the informational requirements of the Securities Exchange Act of 1934, as
amended, or the Exchange Act, and accordingly file annual, quarterly and current reports, any
amendments to those reports, proxy statements and other information with the United States
Securities and Exchange Commission, or SEC. You may read and copy the information we file with the
SEC at the public reference facilities maintained by the SEC at 100 F Street, N.E., Washington, DC
20549. Please call the SEC at 1-800-SEC-0330 for further information on the operation of the public
reference room. Our SEC filings are also available to the public from the SECs Internet site at
www.sec.gov or from our Internet site at www.diamondoffshore.com. Our website provides a hyperlink
to a third-party SEC filings website where these reports may be viewed and printed at no cost as
soon as reasonably practicable after we have electronically filed such material with, or furnished
it to, the SEC. The information contained on our website, or on other websites linked to our
website, is not part of this report.
Item 1A. Risk Factors.
Our business is subject to a variety of risks, including the risks described below. You
should carefully consider these risks when evaluating us and our securities. The risks and
uncertainties described below are not the only ones facing our company. We are also subject to a
variety of risks that affect many other companies generally, as well as additional risks and
uncertainties not known to us or that we currently believe are not as significant as the risks
described below. If any of the following risks actually occur, our business, financial condition,
results of operations and cash flows, and the trading prices of our securities, may be materially
and adversely affected.
Our business depends on the level of activity in the oil and gas industry, which is significantly
affected by volatile oil and gas prices.
Our business depends on the level of activity in offshore oil and gas exploration, development
and production in markets worldwide. Worldwide demand for oil and gas, oil and gas prices, market
expectations of potential changes in these prices and a variety of political and economic factors
significantly affect this level of activity. However, higher or lower commodity demand and prices
do not necessarily translate into increased or decreased drilling activity since our customers
project development time, reserve replacement needs, as well as expectations of future commodity
demand and prices all combine to affect demand for our rigs. Oil and gas prices have been, and are
expected to continue to be, extremely volatile and are affected by numerous factors beyond our
control, including:
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worldwide demand for oil and gas; |
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the level of economic activity in energy-consuming markets; |
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the worldwide economic environment or economic trends, such as recessions; |
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the ability of the Organization of Petroleum Exporting Countries, commonly called
OPEC, to set and maintain production levels and pricing; |
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the level of production in non-OPEC countries; |
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the worldwide political and military environment, including uncertainty or
instability resulting from an escalation or additional outbreak of armed hostilities in
the Middle East, other oil-producing regions or other geographic areas or further acts
of terrorism in the United States or elsewhere; |
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civil unrest; |
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the cost of exploring for, producing and delivering oil and gas; |
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the discovery rate of new oil and gas reserves; |
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the rate of decline of existing and new oil and gas reserves; |
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available pipeline and other oil and gas transportation capacity; |
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the ability of oil and gas companies to raise capital; |
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weather conditions in the United States and elsewhere; |
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the policies of various governments regarding exploration and development of their
oil and gas reserves; |
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development and exploitation of alternative fuels; |
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competition for customers drilling budgets from land-based energy markets around the
world; |
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domestic and foreign tax policy; and |
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advances in exploration and development technology. |
9
The aftermath of the moratorium on offshore drilling in the U.S. Gulf of Mexico and new regulations
adopted as a result of the investigation into the Macondo well blowout could negatively impact us.
On April 20, 2010, the Macondo well (operated by BP p.l.c. and drilled by Transocean Ltd.) in
the GOM experienced a blowout and immediately began flowing oil into the GOM (the Macondo
incident). Efforts to permanently plug and abandon the well and contain the spill were
successfully completed in September 2010. In the near-term aftermath of the Macondo incident, on
May 30, 2010, the U.S. government imposed a six-month moratorium on certain drilling activities in
water deeper than 500 feet in the GOM and subsequently implemented enhanced safety requirements
applicable to all drilling operations in the GOM, including operations in water shallower than 500
feet. On October 12, 2010, the U.S. government lifted the moratorium subject to compliance with
enhanced safety requirements including those set forth in Notices to Lessees, or NTL, 2010-N05 and
2010-N06, both of which were implemented during the drilling ban. Currently, all operations in the
GOM are required to comply with the Interim Final Rule to Enhance Safety Measures for Energy
Development on the Outer Continental Shelf (Drilling Safety Rule) and the Workplace Safety Rule on
Safety and Environmental Management Systems, both of which were issued on September 30, 2010, as
well as NTL 2010-N10 (known as the Compliance and Review NTL). We continue to evaluate these new
measures to ensure that our rigs and equipment are in full compliance, where applicable.
Additional requirements could be forthcoming based on further recommendations by regulatory
agencies investigating the Macondo incident, as well as restructuring within the Department of the
Interior and the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE. We are
not able to predict the likelihood, nature or extent of additional rulemaking, nor are we able to
predict when the BOEMRE will issue drilling permits to our customers. We are not able to predict
the future impact of these events on our operations. Even with the drilling ban lifted,
requirements regarding certain deepwater drilling activities may remain uncertain until the BOEMRE
resumes its regular permitting of those activities.
The current and future regulatory environment in the GOM could result in a number of rigs
being, or becoming available to be, moved to locations outside of the GOM, which could potentially
put downward pressure on global dayrates and adversely affect our ability to contract our floating
rigs that currently are not contracted or are coming off contract. Additional governmental regulations
concerning licensing, taxation, equipment specifications, training requirements or other matters
could increase the costs of our operations, and escalating costs borne by our customers, along with
permitting delays, could reduce exploration activity in the GOM and therefore demand for our
services. In addition, insurance costs across the industry are expected to increase as a result of
the Macondo incident, and in the future certain insurance coverage is likely to become more costly,
and may become less available or not available at all.
The inability to redeploy our rigs impacted by the drilling moratorium, or to obtain dayrates
sufficient to cover our additional operating expenses and mobilization costs if such impacted rigs
are redeployed in international waters, could adversely affect our financial position, results of
operations and cash flows. In addition, implementation of additional regulations may subject us to
increased costs of operating and/or a reduction in the area of operation in the GOM.
Governmental laws and regulations, both domestic and international, may add to our costs or limit
our drilling activity.
Our operations are affected from time to time in varying degrees by governmental laws and
regulations. The drilling industry is dependent on demand for services from the oil and gas
exploration industry and, accordingly, is affected by changing tax and other laws relating to the
energy business generally. We may be required to make significant capital expenditures to comply
with governmental laws and regulations. It is also possible that these laws and regulations may in
the future add significantly to our operating costs or may significantly limit drilling activity.
Governments in some countries are increasingly active in regulating and controlling the
ownership of concessions, the exploration for oil and gas and other aspects of the oil and gas
industry. The modification of existing laws or regulations or the adoption of new laws or
regulations curtailing exploratory or developmental drilling for oil and gas for economic,
environmental or other reasons could materially and adversely affect our operations by limiting
drilling opportunities.
As awareness of climate change issues increases, governments around the world are beginning to
address the matter. This may result in new environmental regulations that may unfavorably impact
us, our suppliers and our customers. We may be exposed to risks related to new laws or regulations
pertaining to climate change, carbon emissions or energy use that could decrease the use of oil or
natural gas, thus reducing demand for hydrocarbon-
10
based fuel and our drilling services.
Governments may also pass laws or regulations encouraging or mandating the use of alternative
energy sources, such as wind power and solar energy, which may reduce demand for oil and natural
gas and our drilling services. In addition, new laws or regulations, including those that may come
into effect following the Macondo incident, may require an increase in our capital spending for
additional equipment to comply with such requirements and could also result in a reduction in
revenues associated with downtime required to install such equipment.
Compliance with or breach of environmental laws can be costly and could limit our operations.
In the United States and in many of the international locations in which we operate,
regulations controlling the discharge of materials into the environment, requiring removal and
cleanup of materials that may harm the environment or otherwise relating to the protection of the
environment apply to some of our operations. For example, we, as an operator of mobile offshore
drilling units in navigable United States waters and some offshore areas, may be liable for damages
and costs incurred in connection with oil spills related to those operations. Laws and regulations
protecting the environment have become increasingly stringent, and may in some cases impose strict
liability, rendering a person liable for environmental damage without regard to negligence or
fault on the part of that person. These laws and regulations may expose us to liability for the
conduct of or conditions caused by others or for acts that were in compliance with all applicable
laws at the time they were performed.
The United States Oil Pollution Act of 1990, or OPA 90, and similar legislation enacted in
Texas, Louisiana and other coastal states, addresses oil spill prevention and control and
significantly expands liability exposure across all segments of the oil and gas industry. OPA 90
and such similar legislation and related regulations impose a variety of obligations on us related
to the prevention of oil spills and liability for damages resulting from such spills. OPA 90
imposes strict and, with limited exceptions, joint and several liability upon each responsible
party for oil removal costs and a variety of public and private damages.
The application of these requirements or the adoption of new requirements could have a
material adverse effect on our financial position, results of operations and cash flows.
Our industry is highly competitive and cyclical, with intense price competition.
The offshore contract drilling industry is highly competitive with numerous industry
participants, none of which at the present time has a dominant market share. Some of our
competitors may have greater financial or other resources than we do. The drilling industry has
experienced consolidation in the past and may experience additional consolidation, which could
create additional large competitors. Drilling contracts are traditionally awarded on a competitive
bid basis. Intense price competition is often the primary factor in determining which qualified
contractor is awarded a job, although rig availability and location, a drilling contractors safety
record and the quality and technical capability of service and equipment may also be considered.
Mergers among oil and natural gas exploration and production companies, as well as a contraction in
the global economy, have reduced the number of available customers, increasing competition.
Our industry has historically been cyclical. There have been periods of lower demand, excess
rig supply and low dayrates, followed by periods of high demand, short rig supply and high
dayrates. We cannot predict the timing or duration of such business cycles. Periods of excess rig
supply intensify the competition in the industry and often result in rigs being idle for long
periods of time. In response to a contraction in demand for our drilling services, we have cold
stacked seven of our rigs as of the date of this report. We also may be required to idle
additional rigs or to enter into lower rate contracts. Prolonged periods of low utilization and
dayrates could also result in the recognition of impairment charges on certain of our drilling rigs
if future cash flow estimates, based upon information available to management at the time, indicate
that the carrying value of these rigs may not be recoverable.
Significant new rig construction and upgrades of existing drilling units could also intensify
price competition. As of the date of this report, based on analyst reports, we believe that there
are approximately 50 jack-up rigs and 50 floaters on order and scheduled for delivery between 2011
and 2013. The resulting increases in rig supply could be sufficient to further depress rig
utilization and intensify price competition from both existing competitors, as well as new entrants
into the offshore drilling market. As of the date of this report, not all of the rigs currently
under construction have been contracted for future work, which may further intensify price
competition as scheduled delivery dates occur. The majority of the floaters on order are
dynamically positioned drilling units, which further increases competition with our fleet in
certain circumstances, depending on customer requirements.
11
We can provide no assurance that our current backlog of contract drilling revenue will be
ultimately realized.
As of the date of this report, our contract drilling backlog was approximately $6.6 billion
for contracted future work extending, in some cases, until 2016. Generally, contract backlog only
includes future revenues under firm commitments; however, from time to time, we may report
anticipated commitments for which definitive agreements have not yet been, but are expected to be,
executed. We can provide no assurance that we will be able to perform under these contracts due to
events beyond our control or that we will be able to ultimately execute a definitive agreement in
cases where one does not currently exist. In addition, we can provide no assurance that our
customers will be able to or willing to fulfill their contractual commitments to us. Our inability
to perform under our contractual obligations or to execute definitive agreements or our customers
inability to fulfill their contractual commitments to us may have a material adverse effect on our
financial position, results of operations and cash flows. See Managements Discussion and
Analysis of Financial Condition and Results of Operations Overview Contract Drilling Backlog
included in Item 7 of this report.
We rely heavily on a relatively small number of customers and the loss of a significant customer
and/or a dispute that leads to the loss of a customer could have a material adverse impact on our
financial results.
We provide offshore drilling services to a customer base that includes major and independent
oil and gas companies and government-owned oil companies. However, the number of potential
customers has decreased in recent years as a result of mergers among the major international oil
companies and large independent oil companies. In 2010, our five largest customers in the
aggregate accounted for 56% of our consolidated revenues. We expect Petrobras, which accounted for
approximately 24% of our consolidated revenues in 2010, and OGX, which accounted for approximately
14% of our consolidated revenues in 2010, to continue to be significant customers in 2011. Our
contract drilling backlog, as of the date of this report, includes $1.7 billion, or 61% of our
total contracted backlog for 2011, which is attributable to contracts with Petrobras and OGX for
operations offshore Brazil in 2011. While it is normal for our customer base to change over time
as work programs are completed, the loss of any major customer may have a material adverse effect
on our financial position, results of operations and cash flows. See Managements Discussion and
Analysis of Financial Condition and Results of Operations Overview Contract Drilling Backlog
included in Item 7 of this report.
The terms of our drilling contracts may limit our ability to attain profitability in a declining
market or to benefit from increasing dayrates in an improving market.
The duration of offshore drilling contracts is generally determined by customer requirements
and, to a lesser extent, the respective management strategies of the offshore drilling contractors.
In periods of decreasing demand for offshore rigs, drilling contractors generally prefer longer
term contracts, but often at flat or slightly lower dayrates, to preserve dayrates at existing
levels and ensure utilization, while customers prefer shorter contracts that allow them to more
quickly obtain the benefit of lower dayrates. Conversely, in periods of rising demand for offshore
rigs, contractors typically prefer shorter contracts that allow them to more quickly profit from
increasing dayrates. In contrast, during these periods customers with reasonably definite drilling
programs typically prefer longer term contracts to maintain dayrate prices at a consistent level.
An inability to obtain longer term contracts in a declining market or to fully benefit from
increasing dayrates in an improving market through shorter term contracts may limit our
profitability.
Contracts for our drilling units are generally fixed dayrate contracts, and increases in our
operating costs could adversely affect our profitability on those contracts.
Our contracts for our drilling units provide for the payment of a fixed dayrate per rig
operating day, although some contracts do provide for a limited escalation in dayrate due to
increased operating costs incurred by us. Many of our operating costs, such as labor costs, are
unpredictable and fluctuate based on events beyond our control. The gross margin that we realize
on these fixed dayrate contracts will fluctuate based on variations in our operating costs over the
terms of the contracts. In addition, for contracts with dayrate escalation clauses, we may not be
able to fully recover increased or unforeseen costs from our customers. Our inability to recover
these increased or unforeseen costs from our customers could adversely affect our financial
position, results of operations and cash flows.
12
Our drilling contracts may be terminated due to events beyond our control.
Our customers may terminate some of our term drilling contracts if the drilling unit is
destroyed or lost or if we have to suspend drilling operations for a specified period of time as a
result of a breakdown of major equipment or, in some cases, due to other events beyond the control
of either party. In addition, some of our drilling contracts permit the customer to terminate the
contract after specified notice periods by tendering contractually specified termination amounts.
These termination payments may not fully compensate us for the loss of a contract. In addition,
the early termination of a contract may result in a rig being idle for an extended period of time,
which could adversely affect our financial position, results of operations and cash flows. During
periods of depressed market conditions, we may be subject to an increased risk of our customers
seeking to repudiate their contracts. Our customers ability to perform their obligations under
drilling contracts with us may also be adversely affected by restricted credit markets and the
economic downturn. If our customers cancel some of their contracts, and we are unable to secure
new contracts on a timely basis and on substantially similar terms, or if contracts are disputed or
suspended for an extended period of time or if a number of our contracts are renegotiated, it could
adversely affect our financial position, results of operations or cash flows.
Our business involves numerous operating hazards which could expose us to significant losses and
significant damage claims. We are not fully insured against all of these risks and our contractual
indemnity provisions may not fully protect us.
Our operations are subject to the significant hazards inherent in drilling for oil and gas
offshore, such as blowouts, reservoir damage, loss of production, loss of well control, unstable or
faulty sea floor conditions, fires and natural disasters such as hurricanes. The occurrence of any
of these types of events could result in the suspension of drilling operations, damage to or
destruction of the equipment involved and injury or death to rig personnel, damage to producing or
potentially productive oil and gas formations, and oil spillage, oil leaks, well blowouts and
extensive uncontrolled fires, any of which could cause significant environmental damage. In
addition, offshore drilling operations are subject to perils peculiar to marine operations,
including capsizing, grounding, collision and loss or damage from severe weather. Any of the
foregoing events could result in significant damage or loss to our properties and assets,
significant loss of revenues, and significant damage claims against us, which could have a material
adverse effect on our results of operations, financial condition and cash flows.
We maintain liability insurance, which includes coverage for environmental damage; however,
because of contractual provisions and policy limits, our insurance coverage may not adequately
cover our losses and claim costs. In addition, pollution and environmental risks are generally not
fully insurable when they are determined to be the result of criminal acts. Also, we do not
typically purchase loss-of-hire insurance to cover lost revenues when a rig is unable to work.
Accordingly, it is possible that our losses from the hazards we face could have a material adverse
effect on our results of operations, financial condition and cash flows.
Operations also may be suspended because of machinery breakdowns, abnormal drilling
conditions, failure of subcontractors to perform or supply goods or services or personnel
shortages.
Generally our contracts with our customers contain contractual rights to indemnity from our
customer for, among other things, pollution originating from the well, while we retain
responsibility for pollution originating from the rig. However, our contractual rights to
indemnification may be unenforceable or limited due to negligent or willful acts of commission or
omission by us, our subcontractors and/or suppliers and our customers may dispute, or be unable to
meet, their contractual indemnification obligations to us.
We believe that the policy limit under our marine liability insurance is within the range that
is customary for companies of our size in the offshore drilling industry and is appropriate for our
business. However, if an accident or other event occurs that exceeds our coverage limits or is not
an insurable event under our insurance policies, or is not fully covered by contractual indemnity,
it could have a material adverse effect on our results of operations, financial position and cash
flows. There can be no assurance that we will continue to carry the insurance we currently
maintain, that our insurance will cover all types of losses or that those parties with contractual
obligations to indemnify us will necessarily be financially able to indemnify us against all of
these risks. In addition, no assurance can be made that we will be able to maintain adequate
insurance in the future at rates we consider to be reasonable or that we will be able to obtain
insurance against some risks.
Accordingly, the occurrence of any of the hazards we face could have a material adverse effect
on our results of operations, financial condition and cash flows.
13
We have elected to self-insure for physical damage to rigs and equipment caused by named windstorms
in the U.S. Gulf of Mexico.
Because the amount of insurance coverage available to us has been limited, and the cost for
such coverage has increased substantially, we have elected to self-insure for physical damage to
rigs and equipment caused by named windstorms in the U.S. Gulf of Mexico. This results in a higher
risk of losses, which could be material, that are not covered by third party insurance contracts.
If one or more named windstorms in the U.S. Gulf of Mexico cause significant damage to our rigs or
equipment, it could have a material adverse effect on our financial position, results of operations
and cash flows.
A significant portion of our operations are conducted outside the United States and involve
additional risks not associated with domestic operations.
We operate in various regions throughout the world which may expose us to political and other
uncertainties, including risks of:
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terrorist acts, war and civil disturbances; |
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piracy or assaults on property or personnel; |
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kidnapping of personnel; |
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expropriation of property or equipment; |
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renegotiation or nullification of existing contracts; |
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changing political conditions; |
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foreign and domestic monetary policies; |
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the inability to repatriate income or capital; |
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difficulties in collecting accounts receivable and longer collection periods; |
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fluctuations in currency exchange rates; |
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regulatory or financial requirements to comply with foreign bureaucratic actions; |
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travel limitations or operational problems caused by public health threats; and |
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changing taxation policies. |
We are subject to the U.S. Treasury Departments Office of Foreign Assets Control and other
U.S. laws and regulations governing our international operations in addition to worldwide
anti-bribery laws. In addition, international contract drilling operations are subject to various
laws and regulations in countries in which we operate, including laws and regulations relating to:
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the equipping and operation of drilling units; |
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import-export quotas or other trade barriers; |
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repatriation of foreign earnings or capital; |
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oil and gas exploration and development; |
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taxation of offshore earnings and earnings of expatriate personnel; and |
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use and compensation of local employees and suppliers by foreign contractors. |
Some foreign governments favor or effectively require the awarding of drilling contracts to
local contractors, require use of a local agent or require foreign contractors to employ citizens
of, or purchase supplies from, a particular jurisdiction. These practices may adversely affect our
ability to compete in those regions. It is difficult to predict what governmental regulations may
be enacted in the future that could adversely affect the international drilling industry. The
actions of foreign governments may adversely affect our ability to compete.
In addition, as of the date of this report, we have one high specification floater and two
jack-up rigs contracted offshore Egypt. Although these rigs have continued to work throughout the recent
political unrest in Egypt, there have been, and in the future there may be other, disruptions
to the support networks within Egypt, including the banking institutions. See Managements
Discussion and Analysis of Financial Condition and Results of
Operations Overview Egyptian Operations included in Item 7 of this report.
As of the date of this report, the greatest concentration of our operating assets outside the
United States was offshore Brazil, where we had 16 rigs in our fleet either currently working or
contracted to work during 2011.
14
Our drilling contracts offshore Mexico expose us to greater risks than we normally assume.
We currently operate, and expect to continue to operate, our drilling rigs offshore Mexico for
PEMEX Exploración y Producción, or PEMEX, the national oil company of Mexico. The terms of these
contracts expose us to greater risks than we normally assume, such as exposure to greater
environmental liability. In addition, each contract can be terminated by PEMEX on 30 days notice,
contractually or by statute, subject to certain conditions. While we believe that the financial
terms of these contracts and our operating safeguards in place mitigate these risks, we can provide
no assurance that the increased risk exposure will not have a negative impact on our future
operations or financial results.
Fluctuations in exchange rates and nonconvertibility of currencies could result in losses to us.
Due to our international operations, we have experienced currency exchange losses where
revenues are received and expenses are paid in nonconvertible
currencies or where we do
not effectively hedge an exposure to a foreign currency. We may also incur losses as a result of
an inability to collect revenues because of a shortage of convertible currency available to the
country of operation, controls over currency exchange or controls over the repatriation of income
or capital. We can provide no assurance that financial hedging arrangements will effectively hedge
any foreign currency fluctuation losses that may arise.
Changes in laws, effective income tax rates or adverse outcomes resulting from examination of our
tax returns could adversely affect our financial results.
Tax laws and regulations are highly complex and subject to interpretation and disputes. We
conduct our worldwide operations through various subsidiaries in a number of different
jurisdictions. We are subject to the tax laws, tax regulations and income tax treaties within and
between the countries in which we operate as well as countries in which we may be resident. We
determine our income tax expense based on our interpretation of the applicable tax laws and
regulations in effect in each jurisdiction for the period during which we operate and earn income.
Our overall effective tax rate could be adversely and suddenly affected by lower than anticipated
earnings in countries where we have lower statutory rates and higher than anticipated earnings in
countries where we have higher statutory rates, by changes in the valuation of our deferred tax
assets and liabilities or by changes in tax law, tax treaties, regulations, accounting principles
or interpretations thereof in one or more countries in which we operate.
Our income tax returns are subject to review and examination. We do not recognize the benefit
of income tax positions we believe are more likely than not to be disallowed upon challenge by a
tax authority. If any tax authority successfully challenges any tax position taken, or if the terms
of certain income tax treaties are interpreted in a manner that is
adverse to our operations, or if
we lose a material tax dispute in any country, our effective tax rate on our worldwide earnings
could increase substantially and our earnings and cash flows from operations could be materially
adversely affected.
We may be required to accrue additional tax liability on certain of our foreign earnings.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond
Offshore International Limited, or DOIL, our wholly-owned Cayman Islands subsidiary. Since forming
this subsidiary it has been our intention to indefinitely reinvest the earnings of this subsidiary
to finance foreign operations, except for the earnings of Diamond East Asia Limited, or DEAL, a
wholly-owned subsidiary of DOIL. It is our intention to repatriate the earnings of DEAL, and U.S.
income taxes will be provided on such earnings. We do not expect to provide for U.S. taxes on any
future earnings generated by DOIL, except to the extent that these earnings are immediately
subjected to U.S. federal income tax or as they relate to DEAL. Should a future distribution be
made from any unremitted earnings of this subsidiary, we may be required to record additional U.S.
income taxes that, if material, could have an adverse effect on our financial position, results of
operations and cash flows.
Acts of terrorism and other political and military events could adversely affect the markets for
our drilling services.
Terrorist attacks and the continued threat of terrorism in the U.S. and abroad, the
continuation or escalation of existing armed hostilities or the outbreak of additional hostilities
could lead to increased political, economic and financial market instability and a downturn in the
economies of the U.S. and other countries. A lower level of
15
economic activity could result in a
decline in energy consumption or an increase in the volatility of energy prices, either of which
could adversely affect the market for our offshore drilling services, our dayrates or utilization
and, accordingly, our financial position, results of operations and cash flows. While we take steps
that we believe are appropriate to secure our energy assets, there is no assurance that we can
completely secure these assets, completely protect them against a terrorist attack or obtain
adequate insurance coverage for terrorist acts at reasonable rates.
We may be subject to litigation that could have an adverse effect on us.
We are, from time to time, involved in various litigation matters. These matters may include,
among other things, contract disputes, personal injury claims, environmental claims or proceedings,
asbestos and other toxic tort claims, employment and tax matters and other litigation that arises
in the ordinary course of our business. Although we intend to defend these matters vigorously, we
cannot predict with certainty the outcome or effect of any claim or other litigation matter, and
there can be no assurance as to the ultimate outcome of any litigation. Litigation may have an
adverse effect on us because of potential adverse outcomes, defense costs, the diversion of our
managements resources and other factors.
Failure to obtain and retain highly skilled personnel could hurt our operations.
We require highly skilled personnel to operate and provide technical services and support for
our business. To the extent that demand for drilling services and the size of the worldwide
industry fleet increase (including due to the impact of newly
constructed rigs), shortages of
qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and
servicing our rigs, which could adversely affect our results of operations. In addition, the
entrance of new participants into the offshore drilling market would cause further competition for
qualified and experienced personnel as these entities seek to hire personnel with expertise in the
offshore drilling industry. The heightened competition for skilled personnel could adversely
impact our financial position, results of operations and cash flows by limiting our operations or
further increasing our costs.
Although we have paid special cash dividends in the past, we may not pay special cash dividends in
the future and we can give no assurance as to the amount or timing of the payment of any future
special cash dividends.
We have adopted a policy to consider paying special cash dividends, in amounts to be
determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as
the amount of any special cash dividend which may be declared, will be based on our financial
position, earnings, earnings outlook, capital spending plans and other factors that our Board of
Directors considers relevant at that time. Moreover, our dividend policy may change from time to
time. We cannot assure you that we will continue to declare any special cash dividends at all or
in any particular amounts. If in the future we pay special cash dividends less frequently or in
smaller amounts, or cease to pay any special cash dividends, it could have a negative effect on the
market price of our common stock. See Market for the Registrants Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity Securities Dividend Policy included in Item 5
of this report and Managements Discussion and Analysis of Financial Condition and Results of
Operations Sources of Liquidity and Capital Resources and Managements Discussion and Analysis
of Financial Condition and Results of Operations Historical Cash Flows included in Item 7 of
this report.
Rig conversions, upgrades or new-builds may be subject to delays and cost overruns.
From time to time we may undertake to add new capacity through conversions or upgrades to our
existing rigs or through new construction. Projects of this type are subject to risks of delay or
cost overruns inherent in any large construction project resulting from numerous factors, including
the following:
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shortages of equipment, materials or skilled labor; |
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work stoppages; |
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unscheduled delays in the delivery of ordered materials and equipment; |
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unanticipated cost increases; |
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weather interferences; |
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difficulties in obtaining necessary permits or in meeting permit conditions; |
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design and engineering problems; |
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customer acceptance delays; |
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shipyard failures or unavailability; and |
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failure or delay of third party service providers and labor disputes. |
16
Failure to complete a rig upgrade or new construction on time, or failure to complete a rig
conversion or new construction in accordance with its design specifications may, in some
circumstances, result in the delay, renegotiation or cancellation of a drilling contract, resulting
in a loss of revenue to us. If a drilling contract is terminated under these circumstances, we may
not be able to secure a replacement contract with equally favorable terms.
Our debt levels may limit our liquidity and flexibility in obtaining additional financing and in
pursuing other business opportunities.
As of December 31, 2010, we had $1.5 billion in long-term debt. Our ability to meet our debt
service obligations is dependent upon our future performance, which is subject to general economic
conditions, industry cycles and financial, business and other factors affecting our operations,
many of which are beyond our control. Our debt levels and the terms of our indebtedness may limit
our liquidity and flexibility in obtaining additional financing and pursuing other business
opportunities. In addition, our overall debt level and/or market conditions could lead the credit
rating agencies to lower our corporate credit ratings. A downgrade in our corporate credit ratings
could impact our ability to issue additional debt by raising the cost of issuing new debt. As a
consequence, we may not be able to issue additional debt in amounts and/or with terms that we
consider to be reasonable. This could limit our ability to pursue other business opportunities.
We are controlled by a single stockholder, which could result in potential conflicts of interest.
Loews Corporation, which we refer to as Loews, beneficially owned approximately 50.4% of our
outstanding shares of common stock as of February 17, 2011 and is in a position to control actions
that require the consent of stockholders, including the election of directors, amendment of our
Restated Certificate of Incorporation and any merger or sale of substantially all of our assets.
In addition, three officers of Loews serve on our Board of Directors. One of those, James S.
Tisch, the Chairman of the Board of our company, is also the Chief Executive Officer and a director
of Loews. We have also entered into a services agreement and a registration rights agreement with
Loews and we may in the future enter into other agreements with Loews.
Loews is a holding company. In addition to us, its principal subsidiaries are CNA Financial
Corporation, a 90% owned subsidiary engaged in commercial property and casualty insurance;
HighMount Exploration & Production LLC, a wholly owned subsidiary engaged in exploration,
production and marketing of natural gas and natural gas liquids; Boardwalk Pipeline Partners, LP, a
66% owned subsidiary engaged in the operation of interstate natural gas transmission pipeline
systems; and Loews Hotels Holding Corporation, a wholly owned subsidiary engaged in the operation
of hotels. Loews and its subsidiaries and we are generally engaged in businesses sufficiently
different from each other as to make conflicts as to possible corporate opportunities unlikely.
However, it is possible that Loews may in some circumstances be in direct or indirect competition
with us, including competition with respect to certain business strategies and transactions that we
may propose to undertake. In addition, potential conflicts of interest exist or could arise in the
future for our directors who are also officers of Loews with respect to a number of areas relating
to the past and ongoing relationships of Loews and us, including tax and insurance matters,
financial commitments and sales of common stock pursuant to registration rights or otherwise.
Although the affected directors may abstain from voting on matters in which our interests and those
of Loews are in conflict so as to avoid potential violations of their fiduciary duties to
stockholders, the presence of potential or actual conflicts could affect the process or outcome of
Board deliberations. We cannot assure you that these conflicts of interest will not materially
adversely affect us.
Item 1B. Unresolved Staff Comments.
Not applicable.
Item 2. Properties.
We own an eight-story office building containing approximately 170,000 net rentable square
feet on approximately 6.2 acres of land located in Houston, Texas, where our corporate headquarters
are located. We also own two buildings totaling 39,000 square feet and 20 acres of land in New
Iberia, Louisiana, for our offshore drilling warehouse and storage facility, a 13,000-square foot
building and five acres of land in Aberdeen, Scotland, for our North Sea operations, two buildings
totaling 77,200 square feet and 11 acres of land in Macae, Brazil, for our South American
operations and two buildings totaling 20,000 square feet and two acres of land in Ciudad del
17
Carmen, Mexico, for our Mexican operations. Additionally, we currently lease various office,
warehouse and storage facilities in Louisiana, Australia, Brazil, Indonesia, Norway, Malaysia,
Singapore, Egypt, Angola, Republic of Congo, Vietnam and the U.K. to support our offshore drilling
operations.
Item 3. Legal Proceedings.
Not applicable.
PART II
Item 5. Market for the Registrants Common Equity, Related Stockholder Matters and Issuer
Purchases of Equity Securities.
Price Range of Common Stock
Our common stock is listed on the New York Stock Exchange, or NYSE, under the symbol DO.
The following table sets forth, for the calendar quarters indicated, the high and low closing
prices of our common stock as reported by the NYSE.
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Common Stock |
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|
High |
|
Low |
2010 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
106.34 |
|
|
$ |
83.23 |
|
Second Quarter |
|
|
93.01 |
|
|
|
56.94 |
|
Third Quarter |
|
|
68.88 |
|
|
|
58.18 |
|
Fourth Quarter |
|
|
74.12 |
|
|
|
63.39 |
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
First Quarter |
|
$ |
71.41 |
|
|
$ |
54.29 |
|
Second Quarter |
|
|
92.57 |
|
|
|
63.59 |
|
Third Quarter |
|
|
96.85 |
|
|
|
76.21 |
|
Fourth Quarter |
|
|
107.01 |
|
|
|
92.45 |
|
As of February 17, 2011 there were approximately 215 holders of record of our common stock.
This number represents registered shareholders and does not include shareholders who hold their
shares institutionally.
Dividend Policy
In 2010, we paid regular cash dividends of $0.125 per share of our common stock on March 1,
June 1, September 1 and December 1. We also paid special cash dividends in 2010 of $1.875 per
share of our common stock on March 1, $1.375 per share of our common stock on June 1, and $0.75 per
share of our common stock on September 1 and December 1. In 2009, we paid regular cash dividends
of $0.125 per share of our common stock on March 2, June 1, September 1 and December 1. We also
paid special cash dividends in 2009 of $1.875 per share of our common stock on March 2, June 1,
September 1 and December 1.
On February 2, 2011, we declared a regular cash dividend and a special cash dividend of $0.125
and $0.75, respectively, per share of our common stock. Both the regular and special cash
dividends are payable on February 28, 2011 to stockholders of record on February 11, 2011.
We have adopted a policy to consider paying special cash dividends, in amounts to be
determined, on a quarterly basis. Any determination to declare a special cash dividend, as well as
the amount of any special cash dividend which may be declared, will be based on our financial
position, earnings, earnings outlook, capital spending plans and other factors that our Board of
Directors considers relevant at that time.
18
CUMULATIVE TOTAL STOCKHOLDER RETURN
The following graph shows the cumulative total stockholder return for our common stock, the
Standard & Poors 500 Index and a Peer Group Index over the five year period ended December 31,
2010.
Comparison of 2006 2010 Cumulative Total Return (1)
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Dec. 31, |
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Dec. 31, |
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Dec. 31, |
|
Dec. 31, |
|
Dec. 31, |
|
Dec. 31, |
|
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
2010 |
|
|
|
Diamond Offshore |
|
|
100 |
|
|
|
118 |
|
|
|
224 |
|
|
|
98 |
|
|
|
182 |
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|
|
132 |
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S&P 500 |
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100 |
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|
116 |
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|
122 |
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|
77 |
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|
97 |
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|
112 |
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Peer Group (2) |
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100 |
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108 |
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|
167 |
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65 |
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|
111 |
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|
117 |
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(1) |
|
Total return assuming reinvestment of dividends. Assumes $100 invested on December 31,
2005 in our common stock, the S&P 500 Index and a peer group index comprised of a group of
other companies in the contract drilling industry. |
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Our dividend history for the periods reported above is as follows: |
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Q1 |
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Q2 |
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Q3 |
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Q4 |
Year |
|
Regular |
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Special |
|
Regular |
|
Special |
|
Regular |
|
Special |
|
Regular |
|
Special |
2010 |
|
$ |
0.125 |
|
|
$ |
1.875 |
|
|
$ |
0.125 |
|
|
$ |
1.375 |
|
|
$ |
0.125 |
|
|
$ |
0.75 |
|
|
$ |
0.125 |
|
|
$ |
0.75 |
|
2009 |
|
$ |
0.125 |
|
|
$ |
1.875 |
|
|
$ |
0.125 |
|
|
$ |
1.875 |
|
|
$ |
0.125 |
|
|
$ |
1.875 |
|
|
$ |
0.125 |
|
|
$ |
1.875 |
|
2008 |
|
$ |
0.125 |
|
|
$ |
1.25 |
|
|
$ |
0.125 |
|
|
$ |
1.25 |
|
|
$ |
0.125 |
|
|
$ |
1.25 |
|
|
$ |
0.125 |
|
|
$ |
1.875 |
|
2007 |
|
$ |
0.125 |
|
|
$ |
4.00 |
|
|
$ |
0.125 |
|
|
|
|
|
|
$ |
0.125 |
|
|
|
|
|
|
$ |
0.125 |
|
|
$ |
1.25 |
|
2006 |
|
$ |
0.125 |
|
|
$ |
1.50 |
|
|
$ |
0.125 |
|
|
|
|
|
|
$ |
0.125 |
|
|
|
|
|
|
$ |
0.125 |
|
|
|
|
|
|
|
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(2) |
|
The peer group is comprised of the following companies: Ensco plc, Noble Corporation, Pride
International, Inc., Rowan Companies, Inc. and Transocean Ltd. Total return calculations were
weighted according to the respective companys market capitalization. |
19
Item 6. Selected Financial Data.
The following table sets forth certain historical consolidated financial data relating to
Diamond Offshore. We prepared the selected consolidated financial data from our consolidated
financial statements as of and for the periods presented. The selected consolidated financial data
below should be read in conjunction with Managements Discussion and Analysis of Financial
Condition and Results of Operations in Item 7 and our Consolidated Financial Statements (including
the Notes thereto) in Item 8 of this report. Historical data for the three annual periods ending
on or prior to December 31, 2008 have been restated to reflect the effect thereon of the adoption
on January 1, 2009 of an accounting standard that requires all convertible debt securities that may
be settled by the issuer fully or partially in cash to be separated into a debt and an equity
component. The bifurcation requirement applies to both newly issued debt and debt issuances
outstanding for any time during the accounting periods for which financial statements are presented
and has been applied retrospectively to the historical periods as of and for the years ended
December 31, 2008, 2007 and 2006 presented below.
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As of and for the Year Ended December 31, |
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2008 |
|
2007 |
|
2006 |
|
|
2010 |
|
2009 |
|
Adjusted |
|
Adjusted |
|
Adjusted |
|
|
(In thousands, except per share and ratio data) |
Income Statement Data: |
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|
|
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|
|
|
|
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Total revenues |
|
$ |
3,322,974 |
|
|
$ |
3,631,284 |
|
|
$ |
3,544,057 |
|
|
$ |
2,567,723 |
|
|
$ |
2,052,572 |
|
Operating income |
|
|
1,425,374 |
|
|
|
1,903,213 |
|
|
|
1,910,194 |
|
|
|
1,223,044 |
|
|
|
940,029 |
|
Net income |
|
|
955,457 |
|
|
|
1,376,219 |
|
|
|
1,310,547 |
|
|
|
844,464 |
|
|
|
699,088 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
6.87 |
|
|
|
9.90 |
|
|
|
9.43 |
|
|
|
6.13 |
|
|
|
5.41 |
|
Diluted |
|
|
6.87 |
|
|
|
9.89 |
|
|
|
9.42 |
|
|
|
6.11 |
|
|
|
5.14 |
|
|
|
|
|
|
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|
Balance Sheet Data: |
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Drilling and other property and
equipment, net |
|
$ |
4,283,792 |
|
|
$ |
4,432,052 |
|
|
$ |
3,414,373 |
|
|
$ |
3,056,300 |
|
|
$ |
2,644,392 |
|
Total assets |
|
|
6,726,984 |
|
|
|
6,264,261 |
|
|
|
4,954,431 |
|
|
|
4,357,702 |
|
|
|
4,148,006 |
|
Long-term debt (excluding current
maturities) (1) |
|
|
1,495,593 |
|
|
|
1,495,375 |
|
|
|
503,280 |
|
|
|
503,071 |
|
|
|
931,937 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Financial Data: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
$ |
434,262 |
|
|
$ |
1,362,468 |
|
|
$ |
666,857 |
|
|
$ |
647,877 |
|
|
$ |
556,392 |
|
Cash dividends declared per share |
|
|
5.25 |
|
|
|
8.00 |
|
|
|
6.13 |
|
|
|
5.75 |
|
|
|
2.00 |
|
Ratio of earnings to fixed charges (2) |
|
|
15.35 |
x |
|
|
37.29 |
x |
|
|
64.54 |
x |
|
|
31.16 |
x |
|
|
19.03 |
x |
|
|
|
(1) |
|
See Managements Discussion and Analysis of Financial Condition and Results of
Operations Sources of Liquidity and Capital Resources Liquidity and Capital
Requirements in Item 7 and Note 9 Long-Term Debt to our Consolidated Financial
Statements included in Item 8 of this report for a discussion of changes in our long-term
debt. |
|
(2) |
|
For all periods presented, the ratio of earnings to fixed charges has been computed on
a total enterprise basis. Earnings represent pre-tax income from continuing operations
plus fixed charges. Fixed charges include (i) interest, whether expensed or capitalized,
(ii) amortization of debt issuance costs, whether expensed or capitalized, and (iii) a
portion of rent expense, which we believe represents the interest factor attributable to
rent. |
20
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
The following discussion should be read in conjunction with our Consolidated Financial
Statements (including the Notes thereto) in Item 8 of this report.
We provide contract drilling services to the energy industry around the globe and are a leader
in offshore drilling. Our current fleet of 46 offshore drilling rigs consists of 32
semisubmersibles, 13 jack-ups and one drillship.
Overview
Industry Conditions
On October 12, 2010, the U.S. government lifted the ban on certain drilling activities in the
GOM. All drilling in the GOM is now subject to compliance with enhanced safety requirements set
forth in Notices to Lessees, or NTL, 2010-N05 and 2010-N06, both of which were implemented during
the drilling ban. Additionally, all drilling in the GOM is required to comply with the Interim
Final Rule to Enhance Safety Measures for Energy Development on the Outer Continental Shelf
(Drilling Safety Rule) and the Workplace Safety Rule on Safety and Environmental Management
Systems, which have become final, as well as NTL 2010-N10 (known as the Compliance and Review NTL).
We continue to evaluate these new measures to ensure that our rigs and equipment are in full
compliance, where applicable. Additional requirements could be forthcoming based on further
recommendations by regulatory agencies investigating the Macondo incident. We are not able to
predict the likelihood, nature or extent of additional rulemaking. Nor are we able to predict when
the Bureau of Ocean Energy Management, Regulation and Enforcement, or BOEMRE, will issue drilling
permits to our customers. We are not able to predict the future impact of these events on our
operations. Even with the drilling ban lifted, certain deepwater drilling activities remain
suspended until the BOEMRE resumes its regular permitting of those activities.
It has been reported that the industry currently has 36 floating rigs in the GOM that have
been impacted by the moratorium and that five floating rigs have left the GOM since the imposition
of the moratorium, two of which rigs were ours. As of the date of this report, we have two
semisubmersible units under contract in the GOM, in addition to the Ocean Monarch, whose contract
the operator has sought to terminate as discussed below, as well as two jack-up units, one of which
is under contract. Given the continuing uncertainty with respect to drilling activity in the GOM,
our customers may seek to move additional rigs to locations outside of the GOM or perform
activities which are allowed under the enhanced safety requirements. In June 2010, one of our
customers asserted force majeure as a basis for its termination of the drilling contract for the
Ocean Monarch, which had a remaining term of approximately 36 months. The operator has also filed
suit against us in U.S. District Court in Houston seeking a declaratory judgment that its
termination of the drilling contract is warranted under the contract. We do not believe the events
cited by the operator come within the definition of force majeure under the drilling contract, and
we do not believe that the operator has the right to terminate the drilling contract on this basis.
Although we cannot predict with certainty the results of any such litigation, and there can be no
assurance as to its ultimate outcome, we intend to vigorously defend this litigation and challenge
the operators attempt to terminate the drilling contract.
We are continuing to actively seek international opportunities to keep our rigs employed.
However, we can provide no assurance that we will be successful in our efforts to employ our
remaining impacted rigs in the GOM in the near term. In addition, given the ongoing uncertainty in
the GOM with respect to drilling activity and other industry factors, we have cold stacked two
intermediate floaters and four jack-up rigs in the GOM.
While dayrates we receive for new contracts are no longer at the peak levels achieved at the
height of the most recent up-cycle, improving oil prices, which had climbed to approximately $90
per barrel by the end of 2010, appear to be supporting demand for our equipment. As a result,
dayrates for our international floater units appear to have stabilized, though demand for our
services has not risen sufficiently to provide significant pricing power on new contracts.
Additionally, the continuing regulatory uncertainty in the GOM could cause Diamond Offshore or
others to move additional rigs out of the GOM to international locations. If we, or others, move a
large number of additional rigs out of the GOM to international locations, the increased supply of
available rigs entering the international market, coupled with un-contracted new-build rigs
scheduled for delivery between now and the end of 2011, could create downward pressure on dayrates
unless demand improves sufficiently to absorb the new supply.
Since September 30, 2010 through the date of this report, we have entered into 17 new drilling
contracts totaling approximately $457 million in backlog and ranging in duration from one well to
one year. As of February 1, 2011, our contract backlog was approximately $6.6 billion, of which
our contracts in the GOM (excluding amounts related
21
to the contract for the Ocean Monarch discussed
above) represented approximately $141.0 million, or 2%, of our total contract backlog.
Floaters
Our intermediate and high-specification floater rigs, both domestic and international,
accounted for approximately 89% of our revenue during 2010. Approximately 74% of the time on our
intermediate and high-specification floater rigs is committed for 2011. Additionally, 51% of the
time on our floating rigs is committed in 2012.
International Jack-ups
During the fourth quarter of 2010, demand for our international jack-ups remained weak but
stable. However, the high-specification new-build equipment coming to market is enjoying a
significantly higher utilization rate than older existing equipment, and the oversupply of jack-up
rigs could have an increasingly negative impact on the international sector throughout 2011 and
beyond.
U.S. Gulf of Mexico Jack-ups
The jack-up market in the GOM has been negatively impacted by the slow issuance of jack-up
permits subsequent to the lifting of the drilling moratorium, as well as the impact of lower
natural gas prices on both demand and dayrates. Our two remaining jack-ups in the GOM are largely
working under short-term contracts and could experience significant downtime unless permitting
activity increases. Absent an increase in permitting activity and a sustained improvement in
natural gas prices, weakness in the GOM jack-up market is likely to continue in 2011, with the
possibility of additional rigs being cold-stacked by us and others in the industry.
Egyptian Operations
We currently have one high-specification floater and two jack-up rigs contracted offshore
Egypt with an aggregate net book value of $269.9 million, or approximately 6% of our total
operating assets at December 31, 2010. Although these rigs have continued to work throughout the recent
political unrest in Egypt, there have been, and in the future there may be other, disruptions
to the support networks within Egypt, including the banking institutions. At February 1, 2011,
our contract drilling backlog related to our drilling operations offshore Egypt was approximately
$60.0 million, or 2% of our total contract drilling backlog, for 2011. Our customers may attempt
to assert force majeure under the agreements under which these rigs are operating. As of the date
of this report, we have not received any force majeure assertions with respect to our Egyptian
operations.
Contract Drilling Backlog
The following table reflects our contract drilling backlog as of February 1, 2011, October 18,
2010 (the date reported in our Quarterly Report on Form 10-Q for the quarter ended September 30,
2010) and February 1, 2010 (the date reported in our Annual Report on Form 10-K for the year ended
December 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.
22
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 1, |
|
|
October 18, |
|
|
February 1, |
|
|
|
2011 |
|
|
2010 (4) |
|
|
2010 (4) |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Contract Drilling Backlog |
|
|
|
|
|
|
|
|
|
|
|
|
High-Specification Floaters (1) |
|
$ |
3,838,000 |
|
|
$ |
4,371,000 |
|
|
$ |
4,177,000 |
|
Intermediate Semisubmersibles (2) |
|
|
2,700,000 |
|
|
|
3,009,000 |
|
|
|
4,030,000 |
|
Jack-ups (3) |
|
|
107,000 |
|
|
|
122,000 |
|
|
|
249,000 |
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
6,645,000 |
|
|
$ |
7,502,000 |
|
|
$ |
8,456,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Contract drilling backlog as of February 1, 2011 for our high-specification floaters
includes (i) $3.0 billion attributable to our contracted operations offshore Brazil for
the years 2011 to 2016 and (ii) $100.0 million attributable to our contracted operations
in the GOM during 2011. |
|
(2) |
|
Contract drilling backlog as of February 1, 2011 for our intermediate
semisubmersibles includes (i) $2.1 billion attributable to our contracted operations
offshore Brazil for the years 2011 to 2015 and (ii) $36.0 million attributable to our
contracted operations in the GOM during 2011. |
|
(3) |
|
Contract drilling backlog as of February 1, 2011 for our jack-ups includes (i)
$49.0 million attributable to our contracted operations offshore Brazil for the years
2011 and 2012 and (ii) $5.0 million attributable to our contracted operations in the GOM
during 2011. |
|
(4) |
|
Contract drilling backlog as of October 18, 2010 and February 1, 2010 includes
$394.0 million and $424.1 million, respectively, attributable to the Ocean Monarch
pursuant to a contract that the operator has sought to terminate. |
The following table reflects the amount of our contract drilling backlog by year as of
February 1, 2011.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ending December 31, |
|
|
|
Total |
|
|
2011 |
|
|
2012 |
|
|
2013 |
|
|
2014 - 2016 |
|
|
|
(In thousands) |
|
Contract Drilling Backlog |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High-Specification Floaters (1) |
|
$ |
3,838,000 |
|
|
$ |
1,470,000 |
|
|
$ |
1,034,000 |
|
|
$ |
615,000 |
|
|
$ |
719,000 |
|
Intermediate Semisubmersibles (2) |
|
|
2,700,000 |
|
|
|
1,145,000 |
|
|
|
811,000 |
|
|
|
429,000 |
|
|
|
315,000 |
|
Jack-ups (3) |
|
|
107,000 |
|
|
|
103,000 |
|
|
|
4,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
6,645,000 |
|
|
$ |
2,718,000 |
|
|
$ |
1,849,000 |
|
|
$ |
1,044,000 |
|
|
$ |
1,034,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Contract drilling backlog as of February 1, 2011 for our high-specification floaters
includes (i) $851.0 million, $790.0 million and $615.0 million for the years 2011 to
2013, respectively, and $719.0 million in the aggregate for the years 2014 to 2016,
attributable to our contracted operations offshore Brazil and (ii) $100.0 million for
2011 attributable to our contracted operations in the GOM. |
|
(2) |
|
Contract drilling backlog as of February 1, 2011 for our intermediate
semisubmersibles includes (i) $762.0 million, $683.0 million and $372.0 million for the
years 2011 to 2013, respectively, and $315.0 million in the aggregate for the years 2014
to 2016, attributable to our contracted operations offshore Brazil and (ii) $36.0 million
for 2011 attributable to our contracted operations in the GOM. |
|
(3) |
|
Contract drilling backlog as of February 1, 2011 for our jack-ups includes (i)
$45.0 million and $4.0 million for years 2011 and 2012, respectively, attributable to our
contracted operations offshore Brazil and (ii) $5.0 million for 2011 attributable to our
contracted operations in the GOM. |
23
The following table reflects the percentage of rig days committed by year as of February 1,
2011. 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, |
|
|
2011 |
|
2012 |
|
2013 |
|
2014 - 2016 |
Rig Days Committed (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High-Specification Floaters |
|
|
83 |
% |
|
|
60 |
% |
|
|
33 |
% |
|
|
13 |
% |
Intermediate Semisubmersibles |
|
|
66 |
% |
|
|
44 |
% |
|
|
22 |
% |
|
|
5 |
% |
Jack-ups |
|
|
24 |
% |
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Includes approximately 770 and 420 scheduled shipyard, survey and mobilization days
for 2011 and 2012, 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, regulatory 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 8 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. 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.
24
Our operating costs are also impacted by the regulatory environments in which we operate. The
adoption of new regulations could result in additional inspection and certification costs, as well
as require additional capital investment to comply with regulatory requirements. Accordingly, we
cannot fully predict the financial impact of new regulations that have been adopted subsequent to
the Macondo incident in April 2010 for rigs operating in the GOM, or any new regulations that may
arise as the investigation into the incident continues or as a result of further recommendations by
regulatory agencies. New laws or regulations may require an increase in our capital spending for
additional equipment to comply with such requirements. Our business could be negatively impacted
by additional downtime which may be required to obtain necessary equipment and to install such
equipment or to obtain the required inspections or certifications as prescribed under such
regulations.
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.
Our operating income is negatively impacted when we perform certain regulatory inspections,
which we refer to as a 5-year survey, or special survey, that are due every five years for each of
our rigs. Operating revenue decreases because these special surveys are performed during scheduled
downtime in a shipyard. Operating expenses increase as a result of these special surveys due to
the cost to mobilize the rigs to a shipyard, inspection costs incurred and repair and maintenance
costs. Repair and maintenance activities may result from the special survey or may have been
previously planned to take place during this mandatory downtime. The number of rigs undergoing a
5-year survey will vary from year to year, as well as from quarter to quarter.
In addition, operating income may be negatively impacted by intermediate surveys, which are
performed at interim periods between 5-year surveys. Intermediate surveys are generally less
extensive in duration and scope than a 5-year survey. Although an intermediate survey may require
some downtime for the drilling rig, it normally does not require dry-docking or shipyard time,
except for rigs located in the U.K. and Norwegian sectors of the North Sea.
During 2011, seven of our rigs will require 5-year surveys, and we expect that they will be
out of service for approximately 455 days in the aggregate. We also expect to spend an additional
approximately 290 days during 2011 for intermediate surveys, the mobilization of rigs, 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 and cash flows. Under our insurance policy that expires on May 1, 2011, we
carry physical damage insurance for certain losses other than those caused by named windstorms in
the U.S. Gulf of Mexico for which our deductible for physical damage is $25.0 million per
occurrence. We do not typically retain loss-of-hire insurance policies to cover our rigs.
In addition, under our insurance policy that expires on May 1, 2011, we carry marine liability
insurance covering certain legal liabilities, including coverage for certain personal injury
claims, with no exclusions for pollution and/or environmental risk. We believe that the policy
limit for our marine liability insurance is within the range that is customary for companies of our
size in the offshore drilling industry and is appropriate for our business. Our deductibles for
marine liability coverage, including for personal injury claims, are $10.0 million for the first
occurrence and vary in amounts ranging between $5.0 million and, if aggregate claims exceed certain
thresholds, up to $100.0 million for each subsequent occurrence, depending on the nature, severity
and frequency of claims which might arise during the policy year, which under the current policy
commences on May 1 of each year. As a result of the Macondo
25
incident, insurance costs across the
industry are expected to increase and in the future, certain insurance coverage is likely to become
more costly, and may become less available or not available at all.
Construction and Capital Upgrade Projects. We capitalize interest cost for the construction
and upgrade of qualifying assets in accordance with accounting principles generally accepted in the
U.S., or GAAP. The period of interest capitalization covers the duration of the activities
required to make the asset ready for its intended use, and the capitalization period ends when the
asset is substantially complete and ready for its intended use. For the year ended December 31,
2008, we capitalized interest of $16.9 million on qualifying expenditures related to the upgrades
of the Ocean Monarch for ultra-deepwater service and the construction of two jack-up rigs, the
Ocean Shield and Ocean Scepter, through the date of each projects completion. We did not
capitalize interest on any qualifying assets during 2010 or 2009.
Critical Accounting Estimates
Our significant accounting policies are included in Note 1 General Information to our
Consolidated Financial Statements in Item 8 of this report. Judgments, assumptions and estimates
by our management are inherent in the preparation of our financial statements and the application
of our significant accounting policies. We believe that our most critical accounting estimates are
as follows:
Property, Plant and Equipment. We carry our drilling and other property and equipment at
cost. Maintenance and routine repairs are charged to income currently while replacements and
betterments, which meet certain criteria, are capitalized. Depreciation is amortized up to
applicable salvage values by applying the straight-line method over the remaining estimated useful
lives. Our management makes judgments, assumptions and estimates regarding capitalization, useful
lives and salvage values. Changes in these judgments, assumptions and estimates could produce
results that differ from those reported.
We evaluate our property and equipment for impairment whenever changes in circumstances
indicate that the carrying amount of an asset may not be recoverable (such as cold stacking a rig
or excess spending over budget on a new-build or major rig upgrade). We utilize a
probability-weighted cash flow analysis in testing an asset for potential impairment. Our
assumptions and estimates underlying this analysis may include the following:
|
|
|
dayrate by rig; |
|
|
|
|
utilization rate by rig (expressed as the actual percentage of time per year that the
rig would be used); |
|
|
|
|
the per day operating cost for each rig if active, ready-stacked or cold-stacked; |
|
|
|
|
the estimated maintenance, inspection or other costs associated with a rig returning
to work; |
|
|
|
|
salvage value for each rig; and |
|
|
|
|
estimated proceeds that may be received on disposition of the rig. |
Based on these assumptions and estimates, we develop a matrix by assigning probabilities to
various combinations of assumed utilization rates and dayrates. We also consider the impact of a
5% reduction in assumed dayrates for the cold-stacked rigs (holding all other assumptions and
estimates in the model constant).
As
of December 31, 2010, we had cold stacked four jack-up rigs consisting of three
mat-supported rigs and one independent-leg, cantilevered rig (all in the GOM) and three
intermediate semisubmersible drilling rigs (two in the GOM and one in Malaysia). We performed an
impairment review for each of these rigs using the methodology described above. Based on our
analyses, we have concluded that these seven rigs were not subject to impairment at December 31,
2010.
Managements assumptions are an inherent part of our asset impairment evaluation and the use
of different assumptions could produce results that differ from those reported.
26
Personal
Injury Claims. Our deductibles for liability coverage for personal injury claims,
which primarily result from Jones Act liability in the Gulf of
Mexico, are currently $10.0 million per the
first occurrence, with no aggregate deductible, and vary in amounts ranging between $5.0 million
and, if aggregate claims exceed certain thresholds, up to $100.0 million for each subsequent
occurrence, depending on the nature, severity and frequency of claims which might arise during the
policy year. The Jones Act is a federal law that permits seamen to seek compensation for certain
injuries during the course of their employment on a vessel and governs the liability of vessel
operators and marine employers for the work-related injury or death of an employee. We
engage outside consultants to assist us in estimating
our aggregate reserve for personal injury claims based on our historical losses and utilizing
various actuarial models.
The models used in estimating our aggregate reserve for personal injury claims include
actuarial assumptions such as:
|
|
|
claim emergence, or the delay between occurrence and recording of claims; |
|
|
|
|
settlement patterns, or the rates at which claims are closed; |
|
|
|
|
development patterns, or the rate at which known cases develop to their ultimate
level; |
|
|
|
|
average, potential frequency and severity of claims; and |
|
|
|
|
effect of re-opened claims. |
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. |
Income Taxes. We account for income taxes in accordance with accounting standards that
require the recognition of the amount of taxes payable or refundable for the current year and an
asset and liability approach in recognizing the amount of deferred tax liabilities and assets for
the future tax consequences of events that have been currently recognized in our financial
statements or tax returns. In each of our tax jurisdictions we recognize a current tax liability
or asset for the estimated taxes payable or refundable on tax returns for the current year and a
deferred tax asset or liability for the estimated future tax effects attributable to temporary
differences and carryforwards. Deferred tax assets are reduced by a valuation allowance, if
necessary, which is determined by the amount of any tax benefits that, based on available evidence,
are not expected to be realized under a more likely than not approach. We do not establish
deferred tax liabilities for certain of our foreign earnings that we intend to indefinitely
reinvest to finance foreign activities. However, if these earnings become subject to U.S. federal
tax, any required provision could have a material impact on our financial results. We make
judgments regarding future events and related estimates especially as they pertain to the
forecasting of our effective tax rate, the potential realization of deferred tax assets such as
utilization of foreign tax credits, and exposure to the disallowance of items deducted on tax
returns upon audit.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond
Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. Since
forming this subsidiary in 2002, it has been our intention to indefinitely reinvest the earnings of
the subsidiary to finance foreign activities. Consequently, no U.S. federal income taxes are
provided on these earnings except to the extent that such earnings were immediately subject to U.S.
federal income taxes and except for the earnings of Diamond East Asia Limited, or DEAL, a
wholly-owned subsidiary of DOIL. It is our intention to repatriate the earnings of DEAL and,
accordingly, U.S. income taxes are provided on its earnings.
In several of the international locations in which we operate, certain of our wholly-owned
subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide
specialized services and equipment in support of our foreign operations. We apply a transfer
pricing methodology to determine the amount to be charged for providing the services and equipment,
and utilize outside consultants to assist us in the development of such transfer pricing
methodologies. In most cases, there are alternative transfer pricing methodologies that could be
applied to these transactions and, if applied, could result in different chargeable amounts.
We record interest related to accrued unrecognized tax positions in interest expense and
recognize penalties associated with uncertain tax positions in our tax expense.
27
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.
Years Ended December 31, 2010, 2009 and 2008
Comparative data relating to our revenues and operating expenses by equipment type are listed
below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
CONTRACT DRILLING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
High-Specification Floaters |
|
$ |
1,414,697 |
|
|
$ |
1,380,771 |
|
|
$ |
1,322,125 |
|
Intermediate Semisubmersibles |
|
|
1,546,837 |
|
|
|
1,698,584 |
|
|
|
1,629,358 |
|
Jack-ups |
|
|
267,983 |
|
|
|
457,224 |
|
|
|
524,934 |
|
Other |
|
|
219 |
|
|
|
|
|
|
|
|
|
|
|
|
Total Contract Drilling Revenue |
|
$ |
3,229,736 |
|
|
$ |
3,536,579 |
|
|
$ |
3,476,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues Related to Reimbursable Expenses |
|
$ |
93,238 |
|
|
$ |
94,705 |
|
|
$ |
67,640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
High-Specification Floaters |
|
$ |
576,421 |
|
|
$ |
407,203 |
|
|
$ |
367,531 |
|
Intermediate Semisubmersibles |
|
|
605,282 |
|
|
|
557,634 |
|
|
|
581,161 |
|
Jack-ups |
|
|
190,167 |
|
|
|
235,924 |
|
|
|
224,365 |
|
Other |
|
|
19,216 |
|
|
|
23,010 |
|
|
|
11,950 |
|
|
|
|
Total Contract Drilling Expense |
|
$ |
1,391,086 |
|
|
$ |
1,223,771 |
|
|
$ |
1,185,007 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reimbursable Expenses |
|
$ |
91,240 |
|
|
$ |
93,097 |
|
|
$ |
65,895 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
|
|
|
|
|
|
|
|
|
|
|
High-Specification Floaters |
|
$ |
838,276 |
|
|
$ |
973,568 |
|
|
$ |
954,594 |
|
Intermediate Semisubmersibles |
|
|
941,555 |
|
|
|
1,140,950 |
|
|
|
1,048,197 |
|
Jack-ups |
|
|
77,816 |
|
|
|
221,300 |
|
|
|
300,569 |
|
Other |
|
|
(18,997 |
) |
|
|
(23,010 |
) |
|
|
(11,950 |
) |
Reimbursable expenses, net |
|
|
1,998 |
|
|
|
1,608 |
|
|
|
1,745 |
|
Depreciation |
|
|
(393,177 |
) |
|
|
(346,446 |
) |
|
|
(287,417 |
) |
General and administrative expense |
|
|
(66,600 |
) |
|
|
(62,913 |
) |
|
|
(60,142 |
) |
Bad debt expense |
|
|
9,789 |
|
|
|
(9,746 |
) |
|
|
(31,952 |
) |
Casualty loss |
|
|
|
|
|
|
|
|
|
|
(6,281 |
) |
Gain on disposition of assets |
|
|
34,714 |
|
|
|
7,902 |
|
|
|
2,831 |
|
|
|
|
Total Operating Income |
|
$ |
1,425,374 |
|
|
$ |
1,903,213 |
|
|
$ |
1,910,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
2,909 |
|
|
|
4,497 |
|
|
|
11,744 |
|
Interest expense |
|
|
(90,698 |
) |
|
|
(49,610 |
) |
|
|
(10,096 |
) |
Foreign currency transaction gain (loss) |
|
|
1,369 |
|
|
|
11,483 |
|
|
|
(65,566 |
) |
Other, net |
|
|
(2,938 |
) |
|
|
(1,152 |
) |
|
|
770 |
|
|
|
|
Income before income tax expense |
|
|
1,336,016 |
|
|
|
1,868,431 |
|
|
|
1,847,046 |
|
Income tax expense |
|
|
(380,559 |
) |
|
|
(492,212 |
) |
|
|
(536,499 |
) |
|
|
|
NET INCOME |
|
$ |
955,457 |
|
|
$ |
1,376,219 |
|
|
$ |
1,310,547 |
|
|
|
|
28
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
Operating Income. Operating income in 2010 decreased $477.8 million, or 25%, compared to
2009. During 2010, our operating results were negatively impacted by a decline in average daily
revenue earned by our rigs in 2010 from the levels attained in 2009. While our contracted revenue
backlog enabled us to partially mitigate the impact of the weakened market conditions, our total
contract drilling revenue decreased $306.8 million, or 9%, compared to 2009. Revenue generated by
our domestic and international floater rigs decreased an aggregate $117.8 million, or 4%, and
revenue for our combined jack-up fleet decreased $189.2 million, or 41%, during 2010 compared to the
previous year. During 2010, we cold stacked three additional rigs in the GOM, consisting of two
intermediate floaters, which returned from Mexico during the year, and one jack-up rig. However,
the two newest additions to our floater fleet, the Ocean Courage and Ocean Valor, began operating
under contract during the first and fourth quarters of 2010, respectively, and contributed $109.3
million to our revenue during 2010. Total contract drilling expense increased $167.3 million, or
14%, in 2010 compared to 2009 and included normal operating costs for the Ocean Courage and Ocean
Valor, as well as increased amortized mobilization costs and higher other operating costs
associated with rigs operating internationally rather than domestically.
Other significant factors that affected the comparability of our operating income for the years
ended December 31, 2010 and 2009 were as follows:
|
|
|
Bad Debt Expense. In December 2009, we recorded a $10.7 million provision for bad debts
to reserve a portion of the uncollected balance of receivables related to our operations in
Egypt and recovered $0.9 million related to a previously established reserve for bad debt
recorded in 2008 related to our operations in the U.K. During 2010, we recovered $5.6
million and $4.2 million related to previously established reserves for bad debts related
to our operations in Egypt and the U.K., respectively. |
|
|
|
|
Depreciation Expense. Depreciation expense increased $46.7 million, or 13%, during 2010
compared to 2009 primarily due to depreciation associated with capital additions in 2009
and 2010, including depreciation of our two newest high-specification floaters, the Ocean
Courage and Ocean Valor, which were placed in service in September 2009 and March 2010,
respectively, but did not begin drilling operations until 2010. |
|
|
|
|
Gain on Disposition of Assets. Net gain on disposition of assets in 2010 was primarily
related to the sale of the Ocean Shield on July 7, 2010. The rig was sold for net proceeds
of $185.3 million and resulted in a net gain on sale of $32.8 million. Net gain on
disposition of assets in 2009 included a $6.7 million gain on the sale of the Ocean Tower
that was damaged during a hurricane in 2008. |
Interest Expense. Interest expense increased $41.1 million in 2010 compared to 2009,
primarily due to a full year of interest expense in 2010 for our 5.875% Senior Notes due 2019, or
5.875% Senior Notes, and our 5.70% Senior Notes due 2039, or 5.70% Senior Notes, issued in May
2009 and October 2009, respectively ($31.9 million). In addition, during 2010, we recorded $4.8
million in interest expense related to uncertain tax positions compared to a $3.4 million net
reduction of accrued interest expense related to an uncertain tax position for which the statute of
limitations had expired during 2009.
Foreign Currency Transaction Gain (Loss). Foreign currency transaction gain (loss) includes
both realized and unrealized gains and losses from the settlement of and from mark-to-market
accounting for our foreign currency forward exchange, or FOREX, contracts that we have not
designated as accounting hedges. Such gains and losses fluctuate based on the level of
transactions in foreign currencies, as well as fluctuations in such currencies.
During 2009, we recognized net foreign currency exchange gains of $11.5 million, including
$8.9 million realized and unrealized gains on FOREX contracts ($37.3 million in net unrealized
gains from mark-to-market accounting and $28.4 million in net realized losses on settled FOREX
contracts not designated as accounting hedges). During 2010, we designated all of our FOREX
contracts as accounting hedges.
Income Tax Expense. Our income tax expense is a function of the mix between our domestic and
international pre-tax earnings or losses, respectively, as well as the mix of international tax
jurisdictions in which we operate. We recognized $380.6 million of tax expense on pre-tax income
of $1.3 billion for the year ended December 31, 2010 compared to tax expense of $492.2 million on
pre-tax income of $1.9 billion in 2009. The effective annual tax rate
29
of 28.5% in 2010 compared
unfavorably to the effective annual tax rate of 26.3% in 2009 primarily because of higher taxes for
income tax contingencies as well as taxes associated with the sale of the Ocean Shield.
During 2010, we accrued approximately $35.7 million of expense for uncertain tax positions,
primarily in Mexico and Brazil, of which $4.8 million is interest and $12.0 million is penalty
related.
On March 31, 2009, the statute of limitations relative to a 2003 uncertain tax position in
Mexico expired. As a consequence, 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.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
Operating Income. Operating income in 2009 decreased $7.0 million, or less than 1%, compared
to 2008. During 2009, our contracted revenue backlog allowed us to substantially mitigate the
impact of the global economic recession on our business. Despite the downturn in the market, our
contract drilling revenue increased $60.2 million in 2009 compared to 2008. The Ocean Monarch
completed a major upgrade at the end of 2008 and began operating under contract in mid-March 2009,
generating revenue of $124.5 million. Our two new-build jack-up rigs, the Ocean Shield and Ocean
Scepter, were completed in 2008 and contributed incremental revenue of $90.1 million during 2009
compared to 2008. However, our operating results for 2009 were negatively impacted by the
ready-stacking of the Ocean Star, Ocean Victory, Ocean Guardian and Ocean Scepter for extended
periods and the cold stacking of our three mat-supported GOM jack-up rigs. The Ocean Bounty
completed its contract offshore Australia in the third quarter of 2009 and was being prepared for
cold-stacking in Malaysia at the end of 2009. Total contract drilling expense increased $38.8
million, or 3%, in 2009 compared to 2008 and included normal operating costs for the upgraded Ocean
Monarch and a full year of operating costs for our two new-build jack-ups.
Other significant factors that affected the comparability of our operating income for the years
ended December 31, 2009 and 2008 were as follows:
|
|
|
Bad Debt Expense. In December 2008, we recorded a $31.9 million provision for bad debts
to reserve the uncollected balance of one of our customers in the U.K. that had entered
into administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy).
We recovered $0.9 million associated with this reserve for bad debts during 2009. In
December 2009, we recorded a $10.7 million provision for bad debts to reserve a portion of
the uncollected balance of receivables related to our operations in Egypt. |
|
|
|
|
Depreciation Expense. Depreciation expense increased $59.0 million, or 21%, during 2009
compared to 2008 due to a higher depreciable asset base for 2009. Depreciation expense for
2009 included depreciation associated with our capital additions in 2008 and 2009,
including the Ocean Shield, Ocean Scepter and Ocean Monarch, which were all placed in
service at various times during 2008. Depreciation expense for 2009 also included
depreciation of the Ocean Courage, which we acquired in June 2009 and placed in service in
September 2009. |
|
|
|
|
Casualty Loss. In September 2008, one of our jack-up rigs in the GOM sustained
significant damage, including the loss of the rigs derrick, drill floor and related
equipment. During 2008, we wrote off the approximately $2.6 million net book value of the
lost equipment and accrued $3.7 million in estimated salvage costs for recovery of
equipment from the ocean floor. |
|
|
|
|
Gain on Disposition of Assets. Net gain on disposition of assets in 2009 included a
$6.7 million gain on the sale of the Ocean Tower compared to aggregate net gains of $2.8
million in 2008 on the sale and disposition of miscellaneous equipment. |
Interest Income. We earned interest income of $4.5 million in 2009 compared to $11.7 million
in 2008. The $7.2 million decrease in interest income was primarily the result of lower average
interest-bearing cash balances during 2009 compared to 2008.
Interest Expense. Interest expense in 2009 and 2008 related primarily to interest accrued on
our outstanding indebtedness, net of capitalized interest, and our liabilities for uncertain tax
positions. During 2009, we incurred incremental interest expense of $25.9 million related to our
5.875% Senior Notes and 5.70% Senior Notes, partially offset by a net $3.4 million reduction in
accrued interest expense related to uncertain tax positions. During 2008, we
30
capitalized interest
of $16.9 million related to qualifying construction projects and major upgrades that were all
completed in 2008. We did not capitalize interest costs in 2009 as there were no qualifying
activities during the year.
Foreign Currency Transaction Gain (Loss). During 2009, we recognized net foreign currency
exchange gains of $11.5 million, which included $8.9 million in realized and unrealized gains on
FOREX contracts ($37.3 million in net unrealized gains from mark-to-market accounting and $28.4
million in net realized losses on settled FOREX contracts) and net gains of $2.6 million on other
foreign currency transactions. During 2008, we recognized net foreign currency exchange losses of
$65.6 million, which included $54.0 million in net losses on FOREX contracts ($37.2 million in net
unrealized losses from mark-to-market accounting and $16.8 million in net realized losses on
settled FOREX contracts) and other net foreign currency transaction losses of $11.6 million.
Income Tax Expense. Our income tax expense is a function of the mix between our domestic and
international pre-tax earnings or losses, as well as the mix of international tax jurisdictions in
which we operate. We recognized $492.2 million of tax expense on pre-tax income of $1.9 billion
for the year ended December 31, 2009 compared to tax expense of $536.5 million on pre-tax income of
$1.8 billion in 2008. The effective annual tax rate of 26.3% in 2009 compared favorably to the
effective annual tax rate of 29.1% in 2008 primarily because of higher earnings of DOIL in 2009
which were taxed at lower rates.
Our income tax returns are subject to review and examination in the various jurisdictions in
which we operate and we are currently contesting various tax assessments. We accrue for income tax
contingencies, or uncertain tax positions, that we believe are more likely than not exposures. We
recognized expense of $3.3 million and $3.4 million for uncertain tax positions in 2009 and 2008,
respectively. During the year ended December 31, 2009 we recorded a net reduction to interest
expense related to uncertain tax positions of $3.4 million. During the year ended December 31,
2008, we recognized $0.8 million of interest expense related to uncertain tax positions. Penalty
related tax expense for uncertain tax positions during the years ended December 31, 2009 and 2008
was $4.7 million and $1.1 million, respectively. On March 31, 2009, the statute of limitations
relative to a 2003 uncertain tax position in Mexico expired. As a consequence, 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. In December 2009 we received an
approximately $26 million assessment from the Brazilian tax authorities for the years 2004 and
2005. We contested the tax assessment in January 2010 and are awaiting the outcome of the appeal.
As required by GAAP, only the portion of the tax benefit that has a greater than 50% likelihood of
being realized upon settlement is to be recognized. During 2009 we accrued approximately $7
million of expense attributable to the portion of the tax assessment we determined to be an
uncertain tax position in our 2009 Consolidated Statements of Operations, of which approximately $2
million was interest related and approximately $2 million was penalty related.
31
High-Specification Floaters.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands, except days, percentages and |
|
|
average daily revenue amounts) |
HIGH-SPECIFICATION FLOATERS: |
|
|
|
|
|
|
|
|
|
|
|
|
REVENUE EARNING DAYS (1) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
|
946 |
|
|
|
2,245 |
|
|
|
2,664 |
|
Australia/Asia/Middle East |
|
|
513 |
|
|
|
355 |
|
|
|
293 |
|
Europe/Africa/Mediterranean |
|
|
500 |
|
|
|
108 |
|
|
|
|
|
South America |
|
|
1,603 |
|
|
|
891 |
|
|
|
593 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILIZATION (2) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
|
68 |
% |
|
|
75 |
% |
|
|
91 |
% |
Australia/Asia/Middle East |
|
|
79 |
% |
|
|
97 |
% |
|
|
80 |
% |
Europe/Africa/Mediterranean |
|
|
75 |
% |
|
|
68 |
% |
|
|
|
|
South America |
|
|
69 |
% |
|
|
85 |
% |
|
|
81 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
AVERAGE DAILY REVENUE (3) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
386,000 |
|
|
$ |
419,600 |
|
|
$ |
394,100 |
|
Australia/Asia/Middle East |
|
|
432,700 |
|
|
|
433,700 |
|
|
|
237,200 |
|
Europe/Africa/Mediterranean |
|
|
489,100 |
|
|
|
571,000 |
|
|
|
|
|
South America |
|
|
311,700 |
|
|
|
237,800 |
|
|
|
339,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
397,671 |
|
|
$ |
943,024 |
|
|
$ |
1,051,178 |
|
Australia/Asia/Middle East |
|
|
225,392 |
|
|
|
153,757 |
|
|
|
69,419 |
|
Europe/Africa/Mediterranean |
|
|
270,557 |
|
|
|
66,156 |
|
|
|
|
|
South America |
|
|
521,077 |
|
|
|
217,834 |
|
|
|
201,528 |
|
|
|
|
Total Contract Drilling Revenue |
|
$ |
1,414,697 |
|
|
$ |
1,380,771 |
|
|
$ |
1,322,125 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
125,323 |
|
|
$ |
250,025 |
|
|
$ |
223,954 |
|
Australia/Asia/Middle East |
|
|
66,044 |
|
|
|
34,144 |
|
|
|
35,079 |
|
Europe/Africa/Mediterranean |
|
|
80,330 |
|
|
|
14,037 |
|
|
|
|
|
South America |
|
|
304,724 |
|
|
|
108,997 |
|
|
|
108,498 |
|
|
|
|
Total Contract Drilling Expense |
|
$ |
576,421 |
|
|
$ |
407,203 |
|
|
$ |
367,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
$ |
838,276 |
|
|
$ |
973,568 |
|
|
$ |
954,594 |
|
|
|
|
|
|
|
(1) |
|
A revenue earning day is defined as a 24-hour period during which a
rig earns a dayrate after commencement of operations and excludes mobilization,
demobilization and contract preparation days. |
|
(2) |
|
Utilization is calculated as the ratio of total revenue-earning days
divided by the total calendar days in the period for all of the
specified rigs in our fleet (including
cold-stacked rigs). |
|
(3) |
|
Average daily revenue is defined as contract drilling revenue
for all of the specified rigs in our fleet (excluding
revenues for mobilization, demobilization and contract preparation) per revenue
earning day. |
32
Rig Relocations:
|
|
|
|
|
Rig |
|
Relocation Details |
|
Date |
2010: |
|
|
|
|
Ocean Star
|
|
GOM to South America (Brazil)
|
|
January 2010 |
Ocean Valor
|
|
Completion of construction and relocation
from Singapore shipyard to South America
(Brazil)
|
|
March 2010 |
Ocean Courage
|
|
GOM to South America (Brazil)
|
|
March 2010 |
Ocean Baroness
|
|
GOM to South America (Brazil)
|
|
March 2010 |
Ocean America
|
|
GOM to Australia/Asia/Middle East (Australia)
|
|
March 2010 |
Ocean Confidence
|
|
GOM to Europe/Africa/Mediterranean (Republic of Congo)
|
|
August 2010 |
Ocean Endeavor
|
|
GOM to Europe/Africa/Mediterranean (Egypt)
|
|
August 2010 |
Ocean Rover
|
|
Australia/Asia/Middle East (Malaysia to
Indonesia)
|
|
November 2010 |
|
|
|
|
|
2009: |
|
|
|
|
Ocean Quest
|
|
GOM to South America (Brazil)
|
|
February 2009 |
Ocean Monarch
|
|
Completion of major upgrade and relocation
from Singapore shipyard to GOM
|
|
March 2009 |
Ocean Valiant
|
|
GOM to Europe/Africa/Mediterranean (Angola)
|
|
July 2009 |
|
|
|
|
|
2008: |
|
|
|
|
None |
|
|
|
|
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
GOM. Revenue generated by our high-specification floaters operating in the GOM decreased
$545.4 million during 2010 compared to 2009, as a result of 1,299 fewer revenue earning days
($544.9 million) and a decrease in average daily revenue earned during 2010 ($31.8 million),
partially offset by a $30.7 million contract termination fee from a previous customer of the Ocean
Endeavor. The decrease in revenue earning days in 2010 is primarily due to the relocation of
several of our high-specification rigs to international markets since early 2009 and unplanned
downtime due to a force majeure assertion by one of our customers in the GOM. Contract drilling
expense for our high-specification floaters in the GOM decreased by $124.7 million in 2010 compared
to 2009, primarily due to a $129.5 million reduction attributable to the rigs relocated to other
regions, including $4.3 million of start-up costs for the Ocean Courage incurred in 2009 prior to a
change in contract that redirected the rig to Brazil in early 2010.
Australia/Asia/Middle East. During 2010, revenue from our high-specification rigs operating
in the Australia/Asia/Middle East region increased $71.6 million compared to 2009, primarily due to
158 additional revenue earning days in 2010. The increase in revenue earning days in 2010 is
primarily the result of the relocation of the Ocean America to Australia. Contract drilling
expense for our operations in this region increased $31.9 million in 2010 compared to 2009,
primarily due to the inclusion of normal operating, contract preparation and amortized mobilization
costs for the Ocean America ($30.7 million).
Europe/Africa/Mediterranean. Revenue generated by our high-specification floaters operating
in the Europe/Africa/Mediterranean region increased $204.4 million in 2010 compared to 2009,
primarily due to 392 incremental revenue earning days in 2010 ($223.7 million) and the recognition
of $21.7 million in amortized mobilization fees, partially offset by a decrease in average daily
revenue earned ($41.0 million). The increase in revenue earning days in 2010 is the result of the
relocation of two additional rigs to this region in 2010 and a full year of operation for the Ocean
Valiant. Contract drilling expense for our operations during 2010 increased $66.3 million
compared to 2009 due to the inclusion of normal operating and amortized mobilization costs for the
two rigs relocated to the region in 2010 and a full year of operating costs for the Ocean Valiant.
South America. Revenue earned by our high-specification floaters operating offshore Brazil
increased $303.2 million in 2010 compared to 2009, primarily due to 712 additional revenue earning
days ($169.3 million) combined with an increase in average daily revenue earned by our rigs in this
region ($118.4 million) during 2010 and the recognition of $15.5 million in amortized mobilization
revenue. The increase in revenue earning days is primarily due to the additional rigs operating in
the region during 2010 compared to 2009. Contract drilling expense for our
33
operations in Brazil
increased $195.7 million in 2010 compared to 2009 due to the inclusion of normal operating costs
for the additional rigs operating in the region during 2010, including a full year of contract
drilling expense for the Ocean Quest ($123.8 million) and higher contract drilling expense for
the
remainder of our South American rigs that operated in both 2010 and 2009 ($71.9 million). The
increase in costs for our static fleet in 2010 compared to 2009 reflects higher labor and
personnel-related costs, incremental shipyard and repair costs for the Ocean Alliance
as a result of a 145-day shipyard period for an intermediate inspection and thruster change out,
higher amortized mobilization costs and an increase in revenue-based fees.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
GOM. Revenue generated by our high-specification floaters operating in the GOM decreased
$108.2 million during 2009 compared to 2008, as a result of 419 fewer revenue earning days ($165.4
million), partially offset by the effect of an increase in average daily revenue earned during 2009
($57.3 million). The decrease in revenue earning days in 2009, compared to 2008, was attributable
to downtime associated with contract preparation activities for the Ocean Quest and Ocean Valiant,
scheduled surveys days for the Ocean America and 191 ready-stack days for the Ocean Star, partially
offset by incremental revenue earning days for the Ocean Monarch after completion of its major
upgrade. Contract drilling expense for our high-specification floaters in the GOM increased by
$26.1 million in 2009 compared to 2008 and included an aggregate of $32.0 million in incremental
start-up and operating costs for the Ocean Monarch and start-up costs for the Ocean Courage (prior
to a change in contract that subsequently relocated the rig to Brazil). Contract drilling expense
for 2009 also reflected higher labor and related costs ($5.7 million), higher survey, repair and
mobilization costs ($19.6 million), including incremental costs associated with a special survey
for the Ocean America, and higher overhead costs ($5.8 million) compared to the prior year. These
cost increases were partially offset by a $35.5 million reduction in contract drilling expense
attributable to the two rigs that we relocated out of the GOM during 2009.
Australia/Asia/Middle East. During 2009, our high-specification rig operating offshore
Malaysia, the Ocean Rover, generated $84.3 million in additional revenue compared to 2008,
primarily due to an increase in average daily revenue earned in 2009 ($69.7 million) and an
increase in utilization during 2009 ($14.7 million). Utilization increased in 2009 compared to
2008, when the rig had 67 days of scheduled downtime for a special survey and related repairs.
Contract drilling expense for the Ocean Rover decreased slightly compared to 2008 as lower survey
and mobilization costs ($5.2 million) were partially offset by higher revenue-based agency fees
($2.7 million). Contract drilling expense for 2009 also included $1.2 million in repair costs for
the Ocean Valor while in a shipyard in Singapore.
Europe/Africa/Mediterranean. The Ocean Valiant began operating offshore Angola in the third
quarter of 2009 and generated revenue and incurred contract drilling expense of $66.2 million and
$14.0 million, respectively.
South America. Revenue earned by our high-specification floaters operating offshore Brazil in
2009 increased $16.3 million compared to 2008, primarily due to 298 additional revenue earning days
in 2009 ($101.1 million), partially offset by a decline in average daily revenue earned by our rigs
in the region during 2009 ($90.8 million). The increase in revenue earning days is the result of
the operation of the Ocean Quest offshore Brazil beginning in the first quarter of 2009, as well as
increased utilization of the Ocean Clipper, which experienced significant downtime during 2008 for
a survey and unplanned repairs to its propulsion system. We also recognized $6.0 million in
amortized mobilization revenue associated with the relocation of the Ocean Quest from the GOM
during 2009. Contract drilling expense for our operations in Brazil increased $0.5 million in 2009
compared to 2008 as the impact of the addition of incremental normal operating costs for the Ocean
Quest ($23.1 million) was partially offset by a reduction in costs primarily attributable to the
2008 survey of the Ocean Clipper and repairs to its propulsion system ($15.6 million) and reduced
labor and related costs ($5.1 million).
34
Intermediate Semisubmersibles.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands, except days, percentages and |
|
|
average daily revenue amounts) |
INTERMEDIATE SEMISUBMERSIBLES: |
|
|
|
|
|
|
|
|
|
|
|
|
REVENUE EARNING DAYS (1) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
|
446 |
|
|
|
531 |
|
|
|
483 |
|
Mexico |
|
|
210 |
|
|
|
722 |
|
|
|
779 |
|
Australia/Asia/Middle East |
|
|
1,044 |
|
|
|
1,268 |
|
|
|
1,274 |
|
Europe/Africa/Mediterranean |
|
|
887 |
|
|
|
1,409 |
|
|
|
1,641 |
|
South America |
|
|
2,866 |
|
|
|
1,996 |
|
|
|
1,615 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILIZATION (2) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
|
56 |
% |
|
|
94 |
% |
|
|
75 |
% |
Mexico |
|
|
71 |
% |
|
|
99 |
% |
|
|
95 |
% |
Australia/Asia/Middle East |
|
|
72 |
% |
|
|
87 |
% |
|
|
87 |
% |
Europe/Africa/Mediterranean |
|
|
81 |
% |
|
|
82 |
% |
|
|
90 |
% |
South America |
|
|
87 |
% |
|
|
81 |
% |
|
|
79 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
AVERAGE DAILY REVENUE (3) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
198,900 |
|
|
$ |
248,800 |
|
|
$ |
279,400 |
|
Mexico |
|
|
196,100 |
|
|
|
295,500 |
|
|
|
277,900 |
|
Australia/Asia/Middle East |
|
|
329,000 |
|
|
|
333,700 |
|
|
|
306,600 |
|
Europe/Africa/Mediterranean |
|
|
315,600 |
|
|
|
339,500 |
|
|
|
311,800 |
|
South America |
|
|
263,600 |
|
|
|
217,400 |
|
|
|
215,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
88,605 |
|
|
$ |
132,195 |
|
|
$ |
134,880 |
|
Mexico |
|
|
47,691 |
|
|
|
217,628 |
|
|
|
220,754 |
|
Australia/Asia/Middle East |
|
|
343,419 |
|
|
|
423,117 |
|
|
|
395,124 |
|
Europe/Africa/Mediterranean |
|
|
279,998 |
|
|
|
481,944 |
|
|
|
518,382 |
|
South America |
|
|
787,124 |
|
|
|
443,700 |
|
|
|
360,218 |
|
|
|
|
Total Contract Drilling Revenue |
|
$ |
1,546,837 |
|
|
$ |
1,698,584 |
|
|
$ |
1,629,358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
35,813 |
|
|
$ |
32,184 |
|
|
$ |
44,902 |
|
Mexico |
|
|
19,995 |
|
|
|
46,769 |
|
|
|
54,187 |
|
Australia/Asia/Middle East |
|
|
103,780 |
|
|
|
119,674 |
|
|
|
141,170 |
|
Europe/Africa/Mediterranean |
|
|
107,439 |
|
|
|
137,542 |
|
|
|
167,786 |
|
South America |
|
|
338,255 |
|
|
|
221,465 |
|
|
|
173,116 |
|
|
|
|
Total Contract Drilling Expense |
|
$ |
605,282 |
|
|
$ |
557,634 |
|
|
$ |
581,161 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
$ |
941,555 |
|
|
$ |
1,140,950 |
|
|
$ |
1,048,197 |
|
|
|
|
|
|
|
(1) |
|
A revenue earning day is defined as a 24-hour period during which a
rig earns a dayrate after commencement of operations and excludes mobilization,
demobilization and contract preparation days. |
|
(2) |
|
Utilization is calculated as the ratio of total revenue-earning days
divided by the total calendar days in the period for all of the specified rigs in our fleet (including
cold-stacked rigs). |
|
(3) |
|
Average daily revenue is defined as contract drilling revenue
for all of the specified rigs in our fleet (excluding
revenues for mobilization, demobilization and contract preparation) per revenue
earning day. |
35
Rig Relocations:
|
|
|
|
|
Rig |
|
Relocation Details |
|
Date |
2010: |
|
|
|
|
Ocean Voyager
|
|
Mexico to GOM (cold-stacked June 2010)
|
|
March 2010 |
Ocean New Era
|
|
Mexico to GOM (cold-stacked September
2010)
|
|
August 2010 |
|
|
|
|
|
2009: |
|
|
|
|
Ocean Ambassador
|
|
Contract preparation and relocation from
GOM to South America (Brazil)
|
|
June 2009 |
Ocean Bounty
|
|
Preparations for cold-stacking (Malaysia)
|
|
July 2009 |
Ocean Lexington
|
|
Europe/Africa/Mediterranean (Egypt) to
South America (Brazil)
|
|
September 2009 |
Ocean Guardian
|
|
Europe/Africa/Mediterranean (North Sea)
to South America (Falkland Islands )
|
|
November 2009 |
|
|
|
|
|
2008: |
|
|
|
|
Ocean Ambassador
|
|
Mexico to GOM
|
|
April 2008 |
Ocean Yorktown
|
|
GOM to South America (Brazil)
|
|
May 2008 |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
GOM. Revenue generated by our intermediate semisubmersible fleet located in the GOM in 2010
decreased $43.6 million compared to 2009 due to a reduction in average daily revenue earned ($22.3
million) and 85 fewer revenue earning days ($21.3 million) in 2010. The decrease in dayrates and
utilization was primarily related to the depressed GOM market, which was a contributing factor in
our decision to cold stack two of our intermediate semisubmersible rigs in this market during the
third quarter of 2010. Contract drilling expense for our intermediate floater fleet in the GOM
increased $3.6 million in 2010 compared to 2009, as incremental contract drilling, mobilization and
cold-stacking costs for the Ocean Voyager and Ocean New Era ($16.0 million) were partially offset
by reduced contract drilling expense for the Ocean Ambassador ($13.1 million). We currently have
one working and two cold-stacked intermediate semisubmersible rigs in the GOM.
Mexico. Revenue generated by our intermediate semisubmersibles operating offshore Mexico
decreased $169.9 million in 2010 compared to 2009 due to 512 fewer revenue earning days ($151.3
million) combined with a decrease in average daily revenue earned ($20.9 million). Contract
drilling expense decreased $26.8 million during 2010 compared to 2009. The decline in revenue and
contract drilling expense in 2010 was primarily due to the relocation of both of our Mexico
intermediate semisubmersible rigs to the GOM after completion of their contracts. We currently
have no intermediate semisubmersible rigs operating offshore Mexico.
Australia/Asia/Middle East. Revenue generated by our intermediate semisubmersibles operating
in the Australia/Asia/Middle East region decreased $79.7 million in 2010 compared to 2009, as a
result of 224 fewer revenue earning days ($74.7 million) combined with a decrease in average daily
revenue earned ($5.0 million) during 2010. Contract drilling expense for the Australia/Asia/Middle
East region decreased $15.9 million in 2010 compared to 2009. The decrease in revenue and contract
drilling expense in this region in 2010 was primarily due to cold stacking the Ocean Bounty after
completion of its contract in 2009.
Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working
in the Europe/Africa/Mediterranean region decreased $201.9 million in 2010, primarily due to a 522
day reduction in revenue earning days ($177.3 million) and a reduction in average daily revenue
earned ($21.1 million) in 2010 compared to 2009. Revenue earning days decreased in 2010 due to the
relocation of two rigs to the South American region and approximately 100 days of planned downtime
for a special survey of our rig in Norway. Contract drilling expense in the
Europe/Africa/Mediterranean region decreased $30.1 million in 2010 compared to 2009, primarily due
to the two rigs moved to the South American region ($50.3 million), partially offset by incremental
costs associated with the regulatory survey of the Ocean Vanguard.
South America. Revenue generated by our intermediate semisubmersibles operating in the South
American region increased $343.4 million in 2010 compared to 2009. Both revenue earning days and
average daily revenue
36
earned increased in 2010 compared to 2009, and contributed incremental
revenue of $189.1 million and $132.3 million, respectively. The increase in revenue is partially
attributable to a full year of operations for the Ocean Ambassador and Ocean Lexington in 2010,
compared to only a partial year of operations in 2009 after their
relocation to the region, combined with higher dayrates earned in 2010, compared to 2009. We also
recognized $22.0 million in incremental amortized mobilization revenue in 2010 compared to the
prior year. Contract drilling expense in the region increased $116.8 million in 2010 compared to
2009, primarily due to the increase in the number of rigs operating in the region ($87.7 million)
and higher contract drilling expense for our rigs operating offshore Brazil during both years,
primarily for labor and personnel related expenditures, revenue-based fees and incremental costs
associated with a special survey for the Ocean Winner.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
GOM. Revenue generated by our intermediate semisubmersible fleet operating in the GOM in 2009
decreased $2.7 million compared to 2008, primarily due to lower average daily revenue earned in
2009. The effect of reduced average daily revenue was partially offset by an increase in revenue
earning days, primarily as a result of the 2008 relocation of the Ocean Ambassador. Contract
drilling expense for our intermediate floater fleet in the GOM decreased $12.7 million in 2009
compared to 2008, primarily due to a reduction in costs as a result of rigs transferred out of the
GOM ($14.2 million), partially offset by higher overhead costs ($1.0 million) and labor and related
costs ($0.9 million) for our remaining intermediate semisubmersible fleet in the GOM.
Mexico. Revenue generated by our intermediate semisubmersibles operating offshore Mexico
decreased $3.1 million and reflected a 57 day decrease in revenue earning days ($15.8 million),
partially offset by an increase in average daily revenue earned in 2009 compared to 2008 ($12.7
million). Contract drilling expense decreased $7.4 million during 2009 compared to 2008. The
decline in revenue and contract drilling expense in 2009 was primarily due to the relocation of the
Ocean Ambassador out of the region.
Australia/Asia/Middle East. Operating revenue for our intermediate semisubmersibles working
in the Australia/Asia/Middle East region increased $28.0 million in 2009 compared to 2008,
primarily due to an increase in average daily revenue earned during 2009 ($34.4 million), partially
offset by a $4.5 million reduction in amortized mobilization revenue associated with the Ocean
Patriots relocation within the region (New Zealand to Australia) in 2008. In 2009, we elected to
cold stack the Ocean Bounty after completion of its contract offshore Australia in July and were in
the process of finding a suitable location at the end of 2009. Contract drilling expense for the
Australia/Asia/Middle East region decreased $21.5 million in 2009 compared to 2008, primarily due
to reduced costs for the Ocean Bounty ($11.4 million), lower survey, repair and mobilization costs
($7.2 million), as a result of the completion of special surveys of the Ocean Patriot and Ocean
General in 2008, and lower shorebase support costs ($1.9 million) associated with a Melbourne
shorebase office that was closed in 2008.
Europe/Africa/Mediterranean. Operating revenue for our intermediate semisubmersibles working
in the Europe/Africa/Mediterranean region decreased $36.4 million in 2009 compared to 2008.
Revenue earning days decreased by 232 days in 2009 ($72.3 million) compared to 2008, while average
daily revenue increased in 2009 ($39.0 million). The decrease in revenue earning days in 2009 was
the result of the early termination of a drilling contract for the Ocean Nomad and intermittent
work for the Ocean Guardian, partially offset by reduced downtime for the Ocean Princess, which
completed its 2008 special survey in early 2009. Contract drilling expense in the
Europe/Africa/Mediterranean region decreased $30.2 million in 2009 compared to 2008, primarily due
to lower labor and personnel-related costs for our rigs operating in the North Sea ($4.6 million),
including the reversal of a previously recorded reserve for paid time off for our U.K. national
employees, and reduced costs associated with regulatory surveys ($13.5 million), including repairs.
Contract drilling expense in this region also decreased as a result of the relocation of two rigs
to Brazil in the second half of 2009 ($10.1 million).
South America. Revenue generated by our intermediate semisubmersibles working in the South
American region increased $83.5 million in 2009 compared to 2008, primarily due to 381 incremental
revenue earning days in 2009 ($81.8 million). In addition, 2009 revenue was favorably impacted by
a slight increase in average daily revenue earned compared to 2008 ($4.4 million). Contract
drilling expense for our intermediate semisubmersibles increased $48.3 million in 2009, compared to
2008, primarily due to an increase in the number of rigs operating in the region ($15.8 million).
Contract drilling expense for 2009 also reflected higher overall operating and support costs,
including revenue-based agency fees and non-income taxes ($11.2 million), labor and related costs
($7.0
million), maintenance and other costs associated with customer acceptance testing and
inspections ($6.7 million) and shorebase support and overhead costs ($6.2 million).
37
Jack-Ups.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands, except days, percentages and |
|
|
average daily revenue amounts) |
JACK-UPS: |
|
|
|
|
|
|
|
|
|
|
|
|
REVENUE EARNING DAYS (1) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
|
945 |
|
|
|
807 |
|
|
|
2,346 |
|
Mexico |
|
|
667 |
|
|
|
767 |
|
|
|
687 |
|
Australia/Asia/Middle East |
|
|
570 |
|
|
|
642 |
|
|
|
673 |
|
Europe/Africa/Mediterranean |
|
|
846 |
|
|
|
961 |
|
|
|
841 |
|
South America |
|
|
|
|
|
|
205 |
|
|
|
95 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
UTILIZATION (2) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
|
39 |
% |
|
|
39 |
% |
|
|
91 |
% |
Mexico |
|
|
91 |
% |
|
|
89 |
% |
|
|
94 |
% |
Australia/Asia/Middle East |
|
|
96 |
% |
|
|
84 |
% |
|
|
84 |
% |
Europe/Africa/Mediterranean |
|
|
77 |
% |
|
|
90 |
% |
|
|
95 |
% |
South America |
|
|
0 |
% |
|
|
56 |
% |
|
|
62 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
AVERAGE DAILY REVENUE (3) |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
58,300 |
|
|
$ |
78,100 |
|
|
$ |
80,800 |
|
Mexico |
|
|
130,300 |
|
|
|
134,900 |
|
|
|
148,200 |
|
Australia/Asia/Middle East |
|
|
127,300 |
|
|
|
207,100 |
|
|
|
137,700 |
|
Europe/Africa/Mediterranean |
|
|
59,800 |
|
|
|
95,600 |
|
|
|
128,400 |
|
South America |
|
|
|
|
|
|
234,700 |
|
|
|
199,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING REVENUE |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
55,812 |
|
|
$ |
63,016 |
|
|
$ |
189,500 |
|
Mexico |
|
|
88,603 |
|
|
|
105,431 |
|
|
|
105,055 |
|
Australia/Asia/Middle East |
|
|
72,561 |
|
|
|
140,783 |
|
|
|
92,596 |
|
Europe/Africa/Mediterranean |
|
|
50,567 |
|
|
|
93,080 |
|
|
|
115,652 |
|
South America |
|
|
440 |
|
|
|
54,914 |
|
|
|
22,131 |
|
|
|
|
Total Contract Drilling Revenue |
|
$ |
267,983 |
|
|
$ |
457,224 |
|
|
$ |
524,934 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CONTRACT DRILLING EXPENSE |
|
|
|
|
|
|
|
|
|
|
|
|
GOM |
|
$ |
64,544 |
|
|
$ |
72,454 |
|
|
$ |
99,533 |
|
Mexico |
|
|
40,607 |
|
|
|
38,209 |
|
|
|
33,303 |
|
Australia/Asia/Middle East |
|
|
36,185 |
|
|
|
50,097 |
|
|
|
42,184 |
|
Europe/Africa/Mediterranean |
|
|
38,630 |
|
|
|
38,896 |
|
|
|
35,058 |
|
South America |
|
|
10,201 |
|
|
|
36,268 |
|
|
|
14,287 |
|
|
|
|
Total Contract Drilling Expense |
|
$ |
190,167 |
|
|
$ |
235,924 |
|
|
$ |
224,365 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING INCOME |
|
$ |
77,816 |
|
|
$ |
221,300 |
|
|
$ |
300,569 |
|
|
|
|
|
|
|
(1) |
|
A revenue earning day is defined as a 24-hour period during which a
rig earns a dayrate after
commencement of operations and excludes mobilization, demobilization and contract
preparation days. |
|
(2) |
|
Utilization is calculated as the ratio of total revenue-earning days
divided by the total calendar days in the period for all of the
specified rigs in our fleet (including
cold-stacked rigs). |
|
(3) |
|
Average daily revenue is defined as contract drilling revenue
for all of the specified rigs in our fleet (excluding
revenues for mobilization, demobilization and contract preparation) per revenue
earning day. |
38
Rig Relocations:
|
|
|
|
|
Rig |
|
Relocation Details |
|
Date |
2010: |
|
|
|
|
Ocean Shield
|
|
Sold
|
|
July 2010 |
Ocean Scepter
|
|
GOM to South America (Brazil)
|
|
August 2010 |
Ocean Spartan
|
|
Cold-stacked (GOM)
|
|
September 2010 |
|
|
|
|
|
2009: |
|
|
|
|
Ocean Champion
|
|
Cold-stacked (GOM)
|
|
June 2009 |
Ocean Crusader
|
|
Cold-stacked (GOM)
|
|
June 2009 |
Ocean Drake
|
|
Cold-stacked (GOM)
|
|
June 2009 |
Ocean Summit
|
|
GOM to Mexico
|
|
July 2009 |
Ocean Columbia
|
|
Mexico to GOM
|
|
November 2009 |
Ocean Scepter
|
|
South America (Argentina) to GOM
|
|
December 2009 |
|
|
|
|
|
2008: |
|
|
|
|
Ocean Shield
|
|
Placed in service; Australia/Asia/Middle
East (Malaysia)
|
|
May 2008 |
Ocean Heritage
|
|
Australia/Asia/Middle East to
Europe/Africa/Mediterranean (Egypt)
|
|
June 2008 |
Ocean Scepter
|
|
Placed in service; South America (Argentina)
|
|
September 2008 |
Ocean Tower
|
|
Removed from service (hurricane damage)
|
|
October 2008 |
Year Ended December 31, 2010 Compared to Year Ended December 31, 2009
GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $7.2 million during
2010 compared to 2009 due to a decrease in average daily revenue earned during 2010 ($18.7
million), partially offset by the effect of 138 incremental revenue earning days during 2010
($10.8 million). Due to continued unfavorable market conditions in the GOM, we elected to cold
stack an additional jack-up rig in the third quarter of 2010, leaving us with four cold-stacked
jack-up rigs in the GOM at December 31, 2010. Contract drilling expense for our jack-ups in the GOM
decreased $7.9 million during 2010 compared to 2009, primarily due to cold stacking of four of our
jack-up rigs ($26.3 million) and the absence of costs associated with a special survey in 2009.
However, the reduction in contract drilling expense in 2010 was partially offset by incremental
costs resulting from the net increase of one rig in the GOM in 2010 compared to the prior year.
Mexico. Revenue generated by our jack-up rigs operating offshore Mexico decreased $16.8
million in 2010 compared to 2009, primarily due to 100 fewer revenue earning days ($13.5 million)
and a decrease in average daily revenue earned ($3.1 million). Contract drilling expense increased
$2.4 million in 2010 compared to 2009 due to higher overhead, shorebase support and amortized
mobilization costs.
Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the
Australia/Asia/Middle East region decreased $68.2 million in 2010 compared to 2009, primarily due
to a reduction in average daily revenue ($45.5 million) and 72 fewer revenue earning days ($14.9
million) in 2010. In addition, revenue in 2009 included $7.8 million in amortized mobilization
revenue related to the Ocean Shields move to Australia. Revenue earning days during 2010
decreased due to the sale of the Ocean Shield in July 2010. Contract drilling expense decreased
$13.9 million in 2010 compared to 2009, primarily due to a reduction in costs for the Ocean Shield
($10.9 million) and costs associated with the Ocean
Sovereigns 2009 survey and shipyard project.
39
Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the
Europe/Africa/Mediterranean region decreased $42.5 million in 2010 compared to 2009, primarily due
to a decrease in average daily revenue earned ($30.3 million) and a decrease of 115 revenue earning
days ($11.0 million) during 2010. Contract drilling expense decreased $0.3 million in 2010
compared to 2009 due to fewer operating days for the Ocean King, which completed its bareboat
charter offshore Croatia in July 2010, partially offset by an increase in costs associated with a
survey and related repairs for the Ocean Spur that was completed in the fourth quarter of 2010.
South America. Revenue and contract drilling expense decreased $54.5 million and $26.1
million, respectively, in 2010 compared to 2009. Our only jack-up rig in this region, the Ocean
Scepter, operated offshore Argentina until July 2009 and was subsequently relocated to the GOM. We
moved this rig back to the region in August 2010 for a contract offshore Brazil, where it incurred
$10.2 million in expense related to customer acceptance activities during 2010. The rig is
expected to begin drilling under contract in the first quarter of 2011.
Year Ended December 31, 2009 Compared to Year Ended December 31, 2008
GOM. Revenue generated by our jack-up rigs operating in the GOM decreased $126.5 million
during 2009 compared to 2008 due to 1,539 fewer revenue earning days in 2009 ($124.3 million)
compounded by the effect of a lower average daily revenue earned in 2009 ($2.1 million). The
decline in revenue earning days was reflective of the depressed GOM market, and as a result of such
market factors, in 2009 we elected to cold stack our three mat-supported jack-ups in this region.
In addition, the Ocean Tower, which received extensive damage during a 2008 hurricane, was removed
from service in October 2008 and subsequently sold in 2009. Contract drilling expense for our
jack-ups operating in the GOM decreased $27.1 million during 2009 compared to 2008, primarily due
to significantly reduced operating costs for the Ocean Tower and our three cold-stacked rigs ($24.1
million) and a reduction in labor and related costs for our
actively-marketed jack-up fleet in the
GOM ($4.9 million). The decrease in costs in 2009 was partially offset by 2009 survey and repair
costs for two rigs and demobilization costs for the Ocean
Columbia, which relocated to the GOM for a
shipyard project ($1.9 million).
Mexico. Revenue and contract drilling expense generated by our jack-up rigs operating offshore
Mexico increased $0.4 million and $4.9 million, respectively, in 2009 compared to the prior year.
The effect on revenue of an increase in revenue earning days in 2009 was mostly offset by a
decrease in average daily revenue earned during the 2009 period. Contract drilling expense
increased primarily due to costs associated with contract preparation activities, customer
acceptance and the inclusion of normal operating costs of the Ocean Summit, partially offset by
lower operating costs for the Ocean Columbia due to its relocation to the GOM.
Australia/Asia/Middle East. Revenue generated by our jack-up rigs operating in the
Australia/Asia/Middle East region increased $48.2 million in 2009 compared to 2008 and included
$57.3 million of incremental revenues earned by the Ocean Shield. However, total revenue earning
days decreased in 2009 as incremental operating days for the Ocean Shield were more than offset by
an increase in unpaid shipyard days for the Ocean Sovereign and due to the relocation of the Ocean
Heritage to another region. Contract drilling expense increased $7.9 million in 2009 compared to
2008, primarily due to costs associated with the Ocean
Sovereigns 2009 survey and shipyard project
and a net increase in normal operating costs in the region ($3.1 million). Contract drilling
expense in 2009 also included $11.5 million in incremental operating costs, including amortized
mobilization costs, for the Ocean Shield. Operating costs in 2009 were partially offset by reduced
costs for the Ocean Heritage ($6.6 million).
Europe/Africa/Mediterranean. Revenue generated by our jack-up rigs operating in the
Europe/Africa/Mediterranean region decreased $22.6 million in 2009 compared to 2008, primarily due
to a decrease in average daily revenue earned in 2009 ($31.5 million), partially offset by the
impact of an increase in revenue earning days during the same period ($15.4 million). In
addition, during 2008, we recognized a $6.5 million lump-sum demobilization fee for the Ocean Spur
upon completion of its initial contract offshore Egypt. Contract drilling expense increased $3.8
million in 2009 compared to 2008, primarily due to the inclusion of a full year of operating costs
in 2009 for the Ocean Heritage ($4.4 million).
South America. Our newly constructed jack-up rig, the Ocean Scepter, began operating offshore
Argentina late in the third quarter of 2008. The Ocean Scepter completed its contract in July
2009.
40
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 December 31, 2010, we had $464.4 million in Cash and cash equivalents and $612.3 million
in Investments and marketable securities, representing our investment of cash available for
current operations.
Cash Flows from Operations. Our cash flows from operations are impacted by the ability of our
customers to weather the 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.
These external factors which affect our cash flows from operations, many which are not within
our control, are difficult to predict. For a description of other factors that could affect our
cash flows from operations, see Overview Industry Conditions, Forward-Looking
Statements and Risk Factors in Item 1A of this report.
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, an aggregate drilling rate of $560,000 per day, consisting of
$75,000 per day payable 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, payable through the
conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing
properties. As of December 31, 2010, we had drilled four wells for this customer and were owed
$85.0 million payable through the NPI. We began receiving monthly payments from the conveyance of
the NPI in July 2010 and through the date of this report have received an aggregate of $13.7
million through the NPI.
Based on current production payout estimates, we expect to collect $49.6 million of the
receivable within the next twelve months and the remaining $35.4 million of the receivable within
the following twelve months. However, payment of such amounts, and the timing of such payments, are
contingent upon such production and upon energy sale prices.
$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 December 31, 2010, the applicable margin on LIBOR loans
would have been 0.24%. See Liquidity and Capital
Requirements Credit Ratings. As of December 31, 2010, there were no loans outstanding under the Credit
Facility; however $21.9 million in letters of credit were issued and outstanding under the Credit
Facility.
41
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, our ongoing rig equipment replacement and enhancement programs, and our obligations
relating to the construction of our new drillships. 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. The following table sets forth our contractual cash obligations
at December 31, 2010.
Contractual Obligations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments Due By Period |
|
|
|
|
|
|
Less than |
|
|
|
|
|
After 5 |
|
|
Total |
|
1 year |
|
1 3 years |
|
4 5 years |
|
years |
|
|
(In thousands) |
Long-term debt (principal and interest) (1)
|
|
$ |
2,688,625 |
|
|
$ |
82,938 |
|
|
$ |
165,876 |
|
|
$ |
652,998 |
|
|
$ |
1,786,813 |
|
Construction contracts (2)
|
|
|
514,757 |
|
|
|
154,427 |
|
|
|
360,330 |
|
|
|
|
|
|
|
|
|
Operating leases
|
|
|
3,300 |
|
|
|
1,900 |
|
|
|
1,400 |
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations
|
|
$ |
3,206,682 |
|
|
$ |
239,265 |
|
|
$ |
527,606 |
|
|
$ |
652,998 |
|
|
$ |
1,786,813 |
|
|
|
|
|
|
|
(1) |
|
See Note 9 Long-Term Debt to our Consolidated Financial Statements in Item 8
of this report. |
|
(2) |
|
In December 2010, we entered into a turnkey contract with Hyundai
for the construction of a dynamically positioned, ultra-deepwater drillship with delivery
scheduled for late in the second quarter of 2013. See Note 11 Commitments and Contingencies Purchase Obligations to
our Consolidated Financial Statements in Item 8 of this report. |
The above table excludes FOREX contracts in the aggregate notional amount of $140.3 million
outstanding at December 31, 2010. See further information regarding these contracts in Item 7A.
Quantitative and Qualitative Disclosures About Market Risk Foreign Exchange Risk and Note 6
Derivative Financial Instruments to our Consolidated Financial Statements in Item 8 of this
report.
As of December 31, 2010, the total unrecognized tax benefit related to uncertain tax positions
was $45.9 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 other purchase obligations for major rig upgrades or any other significant
obligations at December 31, 2010, except for those related to our direct rig operations, which
arise during the normal course of business. However, in January 2011, we entered into a turnkey
contract with Hyundai for the construction of a second dynamically positioned, ultra-deepwater drillship with delivery
scheduled for the fourth quarter of 2013. See Note 18 Subsequent Event to our Consolidated Financial Statements in Item 8 of this report.
42
Other Commercial Commitments Letters of Credit.
We were contingently liable as of December 31, 2010 in the amount of $101.6 million under
certain performance, bid, supersedeas and custom bonds and letters of credit, including $21.9
million in letters of credit issued under our Credit Facility. Three of these bonds totaling
$47.7 million were purchased from a related party after obtaining competitive quotes. Agreements
relating to approximately $47.7 million of performance bonds can require collateral at any time.
As of December 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. See Note 12
Related-Party Transactions to our Consolidated Financial Statements included in Item 8 of this
report. The table below provides a list of these obligations in U.S. dollar equivalents and their
time to expiration.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Years Ending December 31, |
|
|
Total |
|
2011 |
|
2012 |
|
Thereafter |
|
|
(In thousands) |
Other Commercial Commitments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Customs bonds |
|
$ |
5,559 |
|
|
$ |
5,559 |
|
|
$ |
|
|
|
$ |
|
|
Performance bonds |
|
|
68,159 |
|
|
|
50,866 |
|
|
|
17,293 |
|
|
|
|
|
Other |
|
|
27,869 |
|
|
|
27,869 |
|
|
|
|
|
|
|
|
|
|
|
|
Total obligations |
|
$ |
101,587 |
|
|
$ |
84,294 |
|
|
$ |
17,293 |
|
|
$ |
|
|
|
|
|
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.
During 2010, we spent approximately $434 million on capital expenditures, including
approximately $80 million towards the commissioning and outfitting for service of the Ocean Courage
and Ocean Valor and approximately $354 million relating to our ongoing rig equipment replacement
and enhancement programs, equipment required for our long-term international contracts and other
corporate requirements.
We have budgeted approximately $320 million on capital expenditures for 2011 associated with
our ongoing rig equipment replacement and enhancement programs and other corporate requirements.
In addition, as of the date of this report, we have spent approximately $310 million in 2011
towards the construction of two new, ultra-deepwater drillships with delivery scheduled for late in
the second and fourth quarters of 2013. We expect to finance our 2011 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 December 31, 2010 and 2009, we had no off-balance sheet debt or other arrangements.
43
Historical Cash Flows
The following is a discussion of our historical cash flows from operating, investing and
financing activities for the year ended December 31, 2010 compared to 2009.
Net Cash Provided by Operating Activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
2010 |
|
2009 |
|
Change |
|
|
(In thousands) |
Net income |
|
$ |
955,457 |
|
|
$ |
1,376,219 |
|
|
$ |
(420,762 |
) |
Net changes in operating assets and liabilities |
|
|
(3,119 |
) |
|
|
(286,069 |
) |
|
|
282,950 |
|
Proceeds from settlement of FOREX contracts
designated as accounting hedges |
|
|
3,307 |
|
|
|
8,895 |
|
|
|
(5,588 |
) |
(Gain) on sale and disposition of assets |
|
|
(34,714 |
) |
|
|
(7,902 |
) |
|
|
(26,812 |
) |
(Gain) loss on sale of marketable securities |
|
|
7 |
|
|
|
(619 |
) |
|
|
626 |
|
(Gain) on FOREX contracts |
|
|
(3,307 |
) |
|
|
(17,751 |
) |
|
|
14,444 |
|
Deferred tax provision |
|
|
(6,916 |
) |
|
|
85,524 |
|
|
|
(92,440 |
) |
Depreciation and other non-cash items, net |
|
|
371,603 |
|
|
|
358,517 |
|
|
|
13,086 |
|
|
|
|
|
|
$ |
1,282,318 |
|
|
$ |
1,516,814 |
|
|
$ |
(234,496 |
) |
|
|
|
Our cash flows from operations in 2010 decreased $234.5 million compared to 2009. This
decrease is primarily due to lower earnings resulting from an aggregate reduction in average
utilization of and dayrates earned by our drilling fleet, increased mobilization costs, and the
effect of lower deferred mobilization fees. The decrease in operating cash flows for the 2010
period was partially offset by a decrease in net cash required to satisfy working capital
requirements in 2010 compared to 2009.
We used $283.0 million less cash to satisfy working capital needs during 2010 primarily due to
a decrease in our outstanding accounts receivable balances and an increase in accounts payable at
December 31, 2010 compared to the prior year. Trade and other receivables generated cash of $143.1
million in 2010 compared to using cash of $219.9 million in 2009 and accounts payable and accrued
liabilities generated cash of $33.3 million in 2010 compared to using cash of $26.7 million in
2009. During 2010, we made U.S. federal income tax payments of $427.5 million compared to $252.4
million in 2009. We paid foreign income taxes, net of refunds, of $128.5 million and $176.2
million during 2010 and 2009, respectively.
Net Cash Used in Investing Activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
2010 |
|
2009 |
|
Change |
|
|
(In thousands) |
Purchase of marketable securities |
|
$ |
(5,660,518 |
) |
|
$ |
(4,473,575 |
) |
|
$ |
(1,186,943 |
) |
Proceeds from sale of marketable securities |
|
|
5,450,230 |
|
|
|
4,473,891 |
|
|
|
976,339 |
|
Capital expenditures (including rig acquisitions) |
|
|
(434,262 |
) |
|
|
(1,362,468 |
) |
|
|
928,206 |
|
Proceeds from disposition of assets |
|
|
188,066 |
|
|
|
40,462 |
|
|
|
147,604 |
|
Cost to settle FOREX contracts not
designated as accounting hedges |
|
|
|
|
|
|
(28,445 |
) |
|
|
28,445 |
|
|
|
|
|
|
$ |
(456,484 |
) |
|
$ |
(1,350,135 |
) |
|
$ |
893,651 |
|
|
|
|
Our investing activities used $456.5 million in 2010 compared to $1.4 billion in 2009. During
2010, we purchased marketable securities, net of sales, of $210.3 million compared to net sales of
$0.3 million during 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 2010, we spent $434.3 million related to ongoing capital maintenance programs,
including rig modifications to meet contractual requirements and final commissioning and initial
outfitting costs of the Ocean Courage and Ocean Valor, compared to $1.4 billion in 2009. Capital
expenditures in 2009 included $1.0 billion for the purchase of two newbuild, dynamically
positioned, semisubmersible drilling rigs, the Ocean Valor and Ocean Courage. See Liquidity
and Capital Requirements Capital Expenditures.
44
On July 7, 2010, we completed the sale of the Ocean Shield for net proceeds of $185.3 million.
During 2009, we completed the sale of the Ocean Tower and received net proceeds of $35.4 million.
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 2009, the strengthening U.S. dollar (or, conversely, the weakening
foreign currency) negatively impacted these expiring FOREX contracts and resulted in our having to
pay a net $28.5 million on settlement of these contracts during 2009. During 2010, all of our
FOREX contracts were designated as accounting hedges, the settlement of which was recognized as a
component of Net Cash Provided by Operating Activities.
Net Cash Used in Financing Activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
|
2010 |
|
2009 |
|
Change |
|
|
(In thousands) |
Redemption of zero coupon debentures |
|
$ |
(4,238 |
) |
|
$ |
|
|
|
$ |
(4,238 |
) |
Issuance of senior notes |
|
|
|
|
|
|
995,975 |
|
|
|
(995,975 |
) |
Payment of dividends |
|
|
(733,661 |
) |
|
|
(1,115,211 |
) |
|
|
381,550 |
|
Other |
|
|
41 |
|
|
|
(7,078 |
) |
|
|
7,119 |
|
|
|
|
|
|
$ |
(737,858 |
) |
|
$ |
(126,314 |
) |
|
$ |
(611,544 |
) |
|
|
|
On May 28, 2010, we redeemed the then outstanding $4.2 million accreted value, or $6.0 million
in aggregate principal amount at maturity, of our Zero Coupon Convertible Debentures due 2020, or
Zero Coupon Debentures, at a redemption price of $706.28 per $1,000 principal amount at maturity
for cash.
In 2009, we issued two tranches of senior, unsecured debt aggregating $1.0 billion for general
corporate purposes and paid $8.7 million in fees related to these issuances.
During 2010, we paid cash dividends totaling $733.7 million, consisting of aggregate regular
cash dividends totaling $69.5 million, or $0.125 per share of our common stock per quarter, and
aggregate special cash dividends totaling $664.2 million, or $1.875 and $1.375 per share of our
common stock in the first and second quarters of 2010, respectively, and $0.75 per share of our
common stock in each of the last two quarters of 2010. During 2009, we paid cash dividends
totaling $1.1 billion, which consisted of aggregate regular cash dividends of $69.5 million, or
$0.125 per share of our common stock per quarter, and aggregate special cash dividends of $1.0
billion, or $1.875 per share of our common stock per quarter.
On February 2, 2011, we declared a regular cash dividend and a special cash dividend of $0.125
and $0.75, respectively, per share of our common stock. Both the quarterly and special cash
dividends are payable on February 28, 2011 to stockholders of record on February 11, 2011.
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 years ended December 31, 2010 and 2009.
Other
Currency Risk. Some of our subsidiaries conduct a portion of their operations in the local
currency of the country where they conduct operations. Currency environments in which we have
significant business operations include Brazil, the U.K., Australia, Angola and Mexico. When
possible, we attempt to minimize our currency exchange risk by seeking international contracts
payable in local currency in amounts equal to our estimated operating costs payable in local
currency with the balance of the contract payable in U.S. dollars. At present,
however, only a limited number of our contracts are payable both in U.S. dollars and the local
currency.
45
To the extent that we are not able to cover our local currency operating costs with customer
payments in the local currency, we also utilize FOREX contracts to reduce our currency exchange
risk. Our FOREX contracts may obligate us to exchange predetermined amounts of specified foreign
currencies at specified foreign exchange rates on specific 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 record currency transaction gains and losses as Foreign currency transaction gain (loss)
in our Consolidated Statements of Operations. Gains and losses arising from the settlement of our
FOREX contracts that have been designated as cash flow hedges are reported as a component of
Contract drilling expense in our Consolidated Statements of Operations.
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, Egypt and Brazil; |
|
|
|
|
effects of the Macondo well blowout, including, without limitation, the impact of the
moratorium and its aftermath on drilling in the U.S. Gulf of Mexico, related delays in
permitting activities and related regulations and market developments; |
|
|
|
|
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; |
|
|
|
|
our customers termination of the drilling contract for the Ocean Monarch and the
related litigation; |
|
|
|
|
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,
construction projects or rig acquisitions; |
|
|
|
|
plans and objectives of management; |
|
|
|
|
idling drilling rigs or reactivating stacked rigs; |
|
|
|
|
asset impairment evaluations; |
|
|
|
|
performance of contracts; |
|
|
|
|
outcomes of legal proceedings; |
|
|
|
|
compliance with applicable laws; and |
|
|
|
|
adequacy of insurance or indemnification. |
46
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; |
|
|
|
|
general economic and business conditions, including the extent and duration of the
recent 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; |
|
|
|
|
invalidity of assumptions used in the design of our controls and procedures; |
|
|
|
|
the results of financing efforts; |
|
|
|
|
the risk that future regular or special dividends may not be declared; |
47
|
|
|
adequacy of our sources of liquidity; |
|
|
|
|
risks resulting from our indebtedness; |
|
|
|
|
public health threats; |
|
|
|
|
negative publicity; |
|
|
|
|
impairments of assets; |
|
|
|
|
the availability of qualified personnel to operate and service our drilling rigs; and |
|
|
|
|
various other matters, many of which are beyond our control. |
The risks and uncertainties included here are not exhaustive. Other sections of this report
and our other filings with the SEC include additional factors that could adversely affect our
business, results of operations and financial performance. Given these risks and uncertainties,
investors should not place undue reliance on forward-looking statements. Forward-looking
statements included in this report speak only as of the date of this report. We expressly disclaim
any obligation or undertaking to release publicly any updates or revisions to any forward-looking
statement to reflect any change in our expectations or beliefs with regard to the statement or any
change in events, conditions or circumstances on which any forward-looking statement is based.
48
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The information included in this Item 7A 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 7 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 December 31, 2010 and 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 December 31, 2010 and 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 December 31, 2010 and 2009, there were no loans outstanding
under the Credit Facility (however, as of December 31, 2010 and 2009, $21.9 million and $63.3
million, respectively, in letters of credit were issued and outstanding under the Credit Facility).
Our long-term debt, as of December 31, 2010 and 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 $117.0 million and $121.3 million as of December
31, 2010 and 2009, respectively. A 100-basis point decrease would result in an increase in market
value of $135.5 million and $136.2 million as of December 31, 2010 and 2009, respectively.
49
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 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 December 31, 2010, we had FOREX contracts outstanding in the aggregate notional
amount of $140.3 million, consisting of $35.1 million in Australian dollars, $81.2 million in
Brazilian reais, $9.2 million in British pounds sterling, $3.0 million in Mexican pesos and $11.8
million in Norwegian kroner. These contracts generally settle monthly through July 2011. At
December 31, 2010, we have presented the fair value of our outstanding FOREX contracts as a current
asset of $4.3 million in Prepaid expenses and other current assets and a current liability of
$(0.1) million in Accrued liabilities in our Consolidated Balance Sheets included in Item 8 of
this report. We have presented the fair value of our outstanding FOREX contracts at December 31,
2009 as a current asset of $2.6 million in Prepaid expenses and other current assets and a
current liability of $(0.2) million in Accrued liabilities in our Consolidated Balance Sheets
included in Item 8 of this report.
The following table presents our exposure to market risk by category (interest rates and
foreign currency exchange rates):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Asset (Liability) |
|
Market Risk |
|
|
December 31, |
|
December 31, |
|
|
2010 |
|
2009 |
|
2010 |
|
2009 |
|
|
(In thousands) |
Interest rate: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Marketable securities |
|
$ |
612,300 |
(a) |
|
$ |
400,900 |
(a) |
|
$ |
(1,100 |
) (c) |
|
$ |
(300 |
) (c) |
Long-term debt |
|
|
1,585,100 |
(b) |
|
|
1,546,900 |
(b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign Exchange: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Forward exchange
contracts
receivable positions |
|
|
4,300 |
(d) |
|
|
2,600 |
(d) |
|
|
(23,500 |
) (e) |
|
|
(17,600 |
) (e) |
Forward exchange
contracts
liability positions |
|
|
(100 |
) (d) |
|
|
(200 |
) (d) |
|
|
(2,100 |
) (e) |
|
|
(3,700 |
) (e) |
|
|
|
(a) |
|
The fair market value of our investment in marketable securities, excluding repurchase
agreements, is based on the quoted closing market prices on December 31, 2010 and 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 market prices on December 31, 2010. |
|
(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
December 31, 2010 and 2009. |
|
(d) |
|
The fair value of our foreign currency forward exchange contracts is based on both quoted
market prices and valuations derived from pricing models on December 31, 2010 and 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 December 31,
2010 and 2009, with all other variables held constant. |
50
Item 8. Financial Statements and Supplementary Data.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of Diamond Offshore Drilling, Inc. and
subsidiaries (the Company) as of December 31, 2010 and 2009, and the related consolidated
statements of operations, stockholders equity, comprehensive income and cash flows for each of the
three years in the period ended December 31, 2010. These financial statements are the
responsibility of the Companys management. Our responsibility is to express an opinion on the
financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement. An
audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the
financial statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall financial statement
presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects,
the financial position of Diamond Offshore Drilling, Inc. and
subsidiaries as of December 31, 2010 and 2009, and the results
of their
operations and its cash flows for each of the three years in the period ended December 31, 2010, in
conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the Companys internal control over financial reporting as of December 31,
2010, based on the criteria established in Internal ControlIntegrated Framework issued by the
Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 23,
2011 expressed an unqualified opinion on the Companys internal control over financial reporting.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2011
51
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Diamond Offshore Drilling, Inc. and Subsidiaries
Houston, Texas
We have audited the internal control over financial reporting of Diamond Offshore Drilling, Inc.
and subsidiaries (the Company) as of December 31, 2010, based on criteria established in Internal
Control Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. The Companys management is responsible for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal control over financial
reporting, included in Item 9A of this Form 10-K under the heading Managements Annual Report on
the Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the
Companys internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether effective internal control over financial reporting was
maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and
evaluating the design and operating effectiveness of internal control based on the assessed risk,
and performing such other procedures as we considered necessary in the circumstances. We believe
that our audit provides a reasonable basis for our opinion.
A companys internal control over financial reporting is a process designed by, or under the
supervision of, the companys principal executive and principal financial officers, or persons
performing similar functions, and effected by the companys board of directors, management, and
other personnel to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A companys internal control over financial reporting includes
those policies and procedures that (1) pertain to the maintenance of records that, in reasonable
detail, accurately and fairly reflect the transactions and dispositions of the assets of the
company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles,
and that receipts and expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and (3) provide reasonable assurance
regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the
companys assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the
possibility of collusion or improper management override of controls, material misstatements due to
error or fraud may not be prevented or detected on a timely basis. Also, projections of any
evaluation of the effectiveness of the internal control over financial reporting to future periods
are subject to the risk that the controls may become inadequate because of changes in conditions,
or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2010, based on the criteria established in Internal Control
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight
Board (United States), the consolidated financial statements as of and for the year ended December
31, 2010 of the Company and our report dated February 23, 2011 expressed an unqualified opinion on
those financial statements.
/s/ Deloitte & Touche LLP
Houston, Texas
February 23, 2011
52
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share data)
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
2010 |
|
|
2009 |
|
ASSETS |
|
|
|
|
|
|
|
|
Current assets: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
464,393 |
|
|
$ |
376,417 |
|
Marketable securities |
|
|
612,346 |
|
|
|
400,853 |
|
Accounts receivable, net of allowance for doubtful accounts |
|
|
609,606 |
|
|
|
791,023 |
|
Prepaid expenses and other current assets |
|
|
177,153 |
|
|
|
155,077 |
|
|
|
|
|
|
|
|
Total current assets |
|
|
1,863,498 |
|
|
|
1,723,370 |
|
Drilling
and other property and equipment, net of accumulated depreciation |
|
|
4,283,792 |
|
|
|
4,432,052 |
|
Long-term receivable |
|
|
35,361 |
|
|
|
|
|
Other assets |
|
|
544,333 |
|
|
|
108,839 |
|
|
|
|
|
|
|
|
Total assets |
|
$ |
6,726,984 |
|
|
$ |
6,264,261 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND STOCKHOLDERS EQUITY |
|
|
|
|
|
|
|
|
Current liabilities: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
99,236 |
|
|
$ |
75,015 |
|
Accrued liabilities |
|
|
469,190 |
|
|
|
301,871 |
|
Taxes payable |
|
|
57,862 |
|
|
|
32,410 |
|
Current portion of long-term debt |
|
|
|
|
|
|
4,179 |
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
626,288 |
|
|
|
413,475 |
|
Long-term debt |
|
|
1,495,593 |
|
|
|
1,495,375 |
|
Deferred tax liability |
|
|
542,258 |
|
|
|
546,024 |
|
Other liabilities |
|
|
201,133 |
|
|
|
178,745 |
|
|
|
|
|
|
|
|
Total liabilities |
|
|
2,865,272 |
|
|
|
2,633,619 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingencies (Note 11) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders equity: |
|
|
|
|
|
|
|
|
Preferred
stock (par value $0.01, 25,000,000 shares authorized, none issued and outstanding) |
|
|
|
|
|
|
|
|
Common stock (par value $0.01, 500,000,000 shares authorized;
143,943,624 shares issued and 139,026,824 shares outstanding
at December 31, 2010; 143,942,978 shares issued and
139,026,178 shares outstanding at December 31, 2009) |
|
|
1,439 |
|
|
|
1,439 |
|
Additional paid-in capital |
|
|
1,972,550 |
|
|
|
1,965,513 |
|
Retained earnings |
|
|
1,998,995 |
|
|
|
1,776,498 |
|
Accumulated other comprehensive gains |
|
|
3,141 |
|
|
|
1,605 |
|
Treasury stock, at cost (4,916,800 shares at December 31, 2010
and 2009) |
|
|
(114,413 |
) |
|
|
(114,413 |
) |
|
|
|
|
|
|
|
Total stockholders equity |
|
|
3,861,712 |
|
|
|
3,630,642 |
|
|
|
|
|
|
|
|
Total liabilities and stockholders equity |
|
$ |
6,726,984 |
|
|
$ |
6,264,261 |
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
53
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling |
|
$ |
3,229,736 |
|
|
$ |
3,536,579 |
|
|
$ |
3,476,417 |
|
Revenues related to reimbursable expenses |
|
|
93,238 |
|
|
|
94,705 |
|
|
|
67,640 |
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
3,322,974 |
|
|
|
3,631,284 |
|
|
|
3,544,057 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
Contract drilling, excluding depreciation |
|
|
1,391,086 |
|
|
|
1,223,771 |
|
|
|
1,185,007 |
|
Reimbursable expenses |
|
|
91,240 |
|
|
|
93,097 |
|
|
|
65,895 |
|
Depreciation |
|
|
393,177 |
|
|
|
346,446 |
|
|
|
287,417 |
|
General and administrative |
|
|
66,600 |
|
|
|
62,913 |
|
|
|
60,142 |
|
Bad debt (recovery) expense |
|
|
(9,789 |
) |
|
|
9,746 |
|
|
|
31,952 |
|
Casualty loss |
|
|
|
|
|
|
|
|
|
|
6,281 |
|
Gain on disposition of assets |
|
|
(34,714 |
) |
|
|
(7,902 |
) |
|
|
(2,831 |
) |
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
1,897,600 |
|
|
|
1,728,071 |
|
|
|
1,633,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating income |
|
|
1,425,374 |
|
|
|
1,903,213 |
|
|
|
1,910,194 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other income (expense): |
|
|
|
|
|
|
|
|
|
|
|
|
Interest income |
|
|
2,909 |
|
|
|
4,497 |
|
|
|
11,744 |
|
Interest expense |
|
|
(90,698 |
) |
|
|
(49,610 |
) |
|
|
(10,096 |
) |
Foreign currency transaction gain (loss) |
|
|
1,369 |
|
|
|
11,483 |
|
|
|
(65,566 |
) |
Other, net |
|
|
(2,938 |
) |
|
|
(1,152 |
) |
|
|
770 |
|
|
|
|
|
|
|
|
|
|
|
Income before income tax expense |
|
|
1,336,016 |
|
|
|
1,868,431 |
|
|
|
1,847,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income tax expense |
|
|
(380,559 |
) |
|
|
(492,212 |
) |
|
|
(536,499 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
955,457 |
|
|
$ |
1,376,219 |
|
|
$ |
1,310,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
6.87 |
|
|
$ |
9.90 |
|
|
$ |
9.43 |
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
6.87 |
|
|
$ |
9.89 |
|
|
$ |
9.42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average shares outstanding: |
|
|
|
|
|
|
|
|
|
|
|
|
Shares of common stock |
|
|
139,026 |
|
|
|
139,007 |
|
|
|
138,959 |
|
Dilutive potential shares of common stock |
|
|
44 |
|
|
|
90 |
|
|
|
114 |
|
|
|
|
|
|
|
|
|
|
|
Total weighted-average shares
outstanding assuming dilution |
|
|
139,070 |
|
|
|
139,097 |
|
|
|
139,073 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash dividends declared per share of common stock |
|
$ |
5.25 |
|
|
$ |
8.00 |
|
|
$ |
6.125 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
54
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF STOCKHOLDERS EQUITY
(In thousands, except number of shares)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
Total |
|
|
Common Stock |
|
Paid-in |
|
Retained |
|
Comprehensive |
|
Treasury Stock |
|
Stockholders |
|
|
Shares |
|
Amount |
|
Capital |
|
Earnings |
|
Gains (Losses) |
|
Shares |
|
Amount |
|
Equity |
|
|
|
January 1, 2008 |
|
|
143,787,206 |
|
|
$ |
1,438 |
|
|
$ |
1,943,190 |
|
|
$ |
1,060,158 |
|
|
$ |
15 |
|
|
|
4,916,800 |
|
|
$ |
(114,413 |
) |
|
$ |
2,890,388 |
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,310,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,310,547 |
|
Dividends to stockholders
($6.125 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(851,128 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(851,128 |
) |
Anti-dilution adjustment
paid to stock plan
participants ($5.625 per
share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,669 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,669 |
) |
Conversion of long-term debt |
|
|
71,574 |
|
|
|
1 |
|
|
|
3,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,533 |
|
Reversal of deferred tax
liability related to
imputed interest on
converted debentures |
|
|
|
|
|
|
|
|
|
|
532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
532 |
|
Stock options exercised |
|
|
59,070 |
|
|
|
|
|
|
|
2,002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,002 |
|
Stock-based compensation,
net of tax |
|
|
|
|
|
|
|
|
|
|
7,785 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,785 |
|
Net gain on investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
495 |
|
|
|
|
|
|
|
|
|
|
|
495 |
|
|
|
|
December 31, 2008 |
|
|
143,917,850 |
|
|
|
1,439 |
|
|
|
1,957,041 |
|
|
|
1,516,908 |
|
|
|
510 |
|
|
|
4,916,800 |
|
|
|
(114,413 |
) |
|
|
3,361,485 |
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,376,219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,376,219 |
|
Dividends to stockholders
($8.00 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,112,058 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,112,058 |
) |
Anti-dilution adjustment
paid to stock plan
participants ($7.50 per
share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,571 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,571 |
) |
Stock options exercised |
|
|
25,128 |
|
|
|
|
|
|
|
1,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,069 |
|
Stock-based compensation,
net of tax |
|
|
|
|
|
|
|
|
|
|
7,403 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,403 |
|
Net gain on foreign
currency forward exchange
contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,563 |
|
|
|
|
|
|
|
|
|
|
|
1,563 |
|
Net loss on investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(468 |
) |
|
|
|
|
|
|
|
|
|
|
(468 |
) |
|
|
|
December 31, 2009 |
|
|
143,942,978 |
|
|
|
1,439 |
|
|
|
1,965,513 |
|
|
|
1,776,498 |
|
|
|
1,605 |
|
|
|
4,916,800 |
|
|
|
(114,413 |
) |
|
|
3,630,642 |
|
|
|
|
Net income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
955,457 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
955,457 |
|
Dividends to stockholders
($5.25 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(729,888 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(729,888 |
) |
Anti-dilution adjustment
paid to stock plan
participants ($4.75 per
share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,072 |
) |
Stock options exercised |
|
|
646 |
|
|
|
|
|
|
|
31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31 |
|
Stock-based compensation,
net of tax |
|
|
|
|
|
|
|
|
|
|
7,006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7,006 |
|
Net gain on foreign
currency forward exchange
contracts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,170 |
|
|
|
|
|
|
|
|
|
|
|
1,170 |
|
Net gain on investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
366 |
|
|
|
|
|
|
|
|
|
|
|
366 |
|
|
|
|
December 31, 2010 |
|
|
143,943,624 |
|
|
$ |
1,439 |
|
|
$ |
1,972,550 |
|
|
$ |
1,998,995 |
|
|
$ |
3,141 |
|
|
|
4,916,800 |
|
|
$ |
(114,413 |
) |
|
$ |
3,861,712 |
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
55
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
|
2010 |
|
|
2009 |
|
|
2008 |
|
Net income |
|
$ |
955,457 |
|
|
$ |
1,376,219 |
|
|
$ |
1,310,547 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive gains, net of tax: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign currency forward exchange contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain |
|
|
2,334 |
|
|
|
6,395 |
|
|
|
|
|
Reclassification adjustment for gain
included in net income |
|
|
(1,164 |
) |
|
|
(4,832 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain on investments |
|
|
343 |
|
|
|
41 |
|
|
|
507 |
|
Reclassification adjustment for gain
(loss) included in net income |
|
|
23 |
|
|
|
(509 |
) |
|
|
(12 |
) |
|
|
|
|
|
|
|
|
|
|
Total other comprehensive gain |
|
|
1,536 |
|
|
|
1,095 |
|
|
|
495 |
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
956,993 |
|
|
$ |
1,377,314 |
|
|
$ |
1,311,042 |
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
56
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
|
Operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
955,457 |
|
|
$ |
1,376,219 |
|
|
$ |
1,310,547 |
|
Adjustments to reconcile net income to net cash |
|
|
|
|
|
|
|
|
|
|
|
|
provided by operating activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
393,177 |
|
|
|
346,446 |
|
|
|
287,417 |
|
Gain on disposition of assets |
|
|
(34,714 |
) |
|
|
(7,902 |
) |
|
|
(2,831 |
) |
Casualty loss |
|
|
|
|
|
|
|
|
|
|
6,281 |
|
Loss (gain) on sale of marketable securities, net |
|
|
7 |
|
|
|
(619 |
) |
|
|
(1,282 |
) |
(Gain) loss on foreign currency forward exchange contracts |
|
|
(3,307 |
) |
|
|
(17,751 |
) |
|
|
54,010 |
|
Deferred tax provision |
|
|
(6,916 |
) |
|
|
85,524 |
|
|
|
61,404 |
|
Accretion of discounts on marketable securities |
|
|
(648 |
) |
|
|
(679 |
) |
|
|
(2,258 |
) |
Amortization/write-off of debt issuance costs |
|
|
882 |
|
|
|
672 |
|
|
|
529 |
|
Amortization of debt discounts |
|
|
277 |
|
|
|
299 |
|
|
|
242 |
|
Stock-based compensation expense |
|
|
5,928 |
|
|
|
6,440 |
|
|
|
6,293 |
|
Excess tax benefits from stock-based payment arrangements |
|
|
|
|
|
|
(99 |
) |
|
|
(1,392 |
) |
Deferred income, net |
|
|
17,777 |
|
|
|
37,405 |
|
|
|
4,610 |
|
Deferred expenses, net |
|
|
(59,208 |
) |
|
|
(46,640 |
) |
|
|
(20,556 |
) |
Other assets, noncurrent |
|
|
2,477 |
|
|
|
(2,775 |
) |
|
|
(6,240 |
) |
Other liabilities, noncurrent |
|
|
10,941 |
|
|
|
17,448 |
|
|
|
10,235 |
|
Proceeds from settlement of foreign currency forward
exchange contracts designated as accounting hedges |
|
|
3,307 |
|
|
|
8,895 |
|
|
|
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
143,096 |
|
|
|
(219,867 |
) |
|
|
(42,451 |
) |
Prepaid expenses and other current assets |
|
|
1,519 |
|
|
|
3,503 |
|
|
|
1,318 |
|
Accounts payable and accrued liabilities |
|
|
33,326 |
|
|
|
(26,698 |
) |
|
|
(27,150 |
) |
Taxes payable |
|
|
(181,060 |
) |
|
|
(43,007 |
) |
|
|
(19,038 |
) |
|
|
|
Net cash provided by operating activities |
|
|
1,282,318 |
|
|
|
1,516,814 |
|
|
|
1,619,688 |
|
|
|
|
Investing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Capital expenditures |
|
|
(434,262 |
) |
|
|
(412,444 |
) |
|
|
(666,857 |
) |
Rig acquisitions |
|
|
|
|
|
|
(950,024 |
) |
|
|
|
|
Proceeds from disposition of assets, net of disposal costs |
|
|
188,066 |
|
|
|
40,462 |
|
|
|
5,881 |
|
Proceeds from sale and maturities of marketable securities |
|
|
5,450,230 |
|
|
|
4,473,891 |
|
|
|
1,493,803 |
|
Purchase of marketable securities |
|
|
(5,660,518 |
) |
|
|
(4,473,575 |
) |
|
|
(1,888,792 |
) |
Cost to settle foreign currency forward exchange
contracts not designated as accounting hedges |
|
|
|
|
|
|
(28,445 |
) |
|
|
(16,800 |
) |
|
|
|
Net cash used in investing activities |
|
|
(456,484 |
) |
|
|
(1,350,135 |
) |
|
|
(1,072,765 |
) |
|
|
|
Financing activities: |
|
|
|
|
|
|
|
|
|
|
|
|
Redemption of zero coupon debentures |
|
|
(4,238 |
) |
|
|
|
|
|
|
|
|
Issuance of 5.875% senior unsecured notes |
|
|
|
|
|
|
499,255 |
|
|
|
|
|
Issuance of 5.70% senior unsecured notes |
|
|
|
|
|
|
496,720 |
|
|
|
|
|
Debt issuance costs and arrangement fees |
|
|
(98 |
) |
|
|
(8,671 |
) |
|
|
|
|
Payment of dividends |
|
|
(733,661 |
) |
|
|
(1,115,211 |
) |
|
|
(852,153 |
) |
Proceeds from stock options exercised |
|
|
139 |
|
|
|
1,494 |
|
|
|
2,002 |
|
Excess tax benefits from share-based payment arrangements |
|
|
|
|
|
|
99 |
|
|
|
1,392 |
|
Redemption of remaining 1.5% debentures |
|
|
|
|
|
|
|
|
|
|
(73 |
) |
|
|
|
Net cash used in financing activities |
|
|
(737,858 |
) |
|
|
(126,314 |
) |
|
|
(848,832 |
) |
|
|
|
Net change in cash and cash equivalents |
|
|
87,976 |
|
|
|
40,365 |
|
|
|
(301,909 |
) |
Cash and cash equivalents, beginning of year |
|
|
376,417 |
|
|
|
336,052 |
|
|
|
637,961 |
|
|
|
|
Cash and cash equivalents, end of year |
|
$ |
464,393 |
|
|
$ |
376,417 |
|
|
$ |
336,052 |
|
|
|
|
The accompanying notes are an integral part of the consolidated financial statements.
57
DIAMOND OFFSHORE DRILLING, INC.
AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. General Information
Diamond Offshore Drilling, Inc. is a leading, global offshore oil and gas drilling contractor
with a current fleet of 46 offshore rigs consisting of 32 semisubmersibles, 13 jack-ups and one
drillship. In December 2010 and January 2011, we entered into separate turnkey contracts for the
construction of two sister ultra-deepwater drillships with delivery scheduled for late in the
second and fourth quarters of 2013. See Note 18. Unless the context otherwise requires,
references in these Notes to Diamond Offshore, we, us or our mean Diamond Offshore
Drilling, Inc. and our consolidated subsidiaries. We were incorporated in Delaware in 1989.
As of February 17, 2011, Loews Corporation, or Loews, owned 50.4% of the outstanding shares of
our common stock.
Principles of Consolidation
Our consolidated financial statements include the accounts of Diamond Offshore Drilling, Inc.
and our subsidiaries after elimination of intercompany transactions and balances.
Use of Estimates in the Preparation of Financial Statements
The preparation of financial statements in conformity with accounting principles generally
accepted in the U.S., or 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.
Reclassifications
Certain amounts applicable to the prior periods have been reclassified to conform to the
classifications currently followed. Such reclassifications do not affect earnings.
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.
We classify our investments in marketable securities as available for sale and they are stated
at fair value in our Consolidated Balance Sheets. Accordingly, any unrealized gains and losses,
net of taxes, are reported in our Consolidated Balance Sheets in Accumulated other comprehensive
gain (loss) 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).
The effect of exchange rate changes on cash balances held in foreign currencies was not
material for the years ended December 31, 2010, 2009 and 2008.
58
Provision for Bad Debts
We record a provision for bad debts on a case-by-case basis when facts and circumstances
indicate that a customer receivable may not be collectible. In establishing these reserves, we
consider historical and other factors that predict collectability, including write-offs, recoveries
and the monitoring of credit quality. Such provision is reported as a component of Operating
expense in our Consolidated Statements of Operations. See Note 2.
Derivative Financial Instruments
Our derivative financial instruments consist of foreign currency forward exchange, or FOREX,
contracts which we may designate as cash flow hedges. In accordance with GAAP, each derivative
contract is stated in the balance sheet at its fair value with gains and losses reflected in the
income statement except that, to the extent the derivative qualifies for and is designated as an
accounting hedge, the gains and losses are reflected in income in the same period as offsetting
gains and losses on the qualifying hedged positions.
Realized gains or losses upon settlement of derivative contracts not designated as cash flow
hedges are reported as Foreign currency transaction gain (loss) in our Consolidated Statements of
Operations. See Notes 6 and 7.
Drilling and Other Property and Equipment
Our drilling and other property and equipment are carried at cost. We charge maintenance and
routine repairs to income currently while replacements and betterments, which meet certain
criteria, are capitalized. Costs incurred for major rig upgrades are accumulated in construction
work-in-progress, with no depreciation recorded on the additions, until the month the upgrade is
completed and the rig is placed in service. Upon retirement or sale of a rig, the cost and related
accumulated depreciation are removed from the respective accounts and any gains or losses are
included in our results of operations. Depreciation is recognized up to applicable salvage values
by applying the straight-line method over the remaining estimated useful lives from the year the
asset is placed in service. Drilling rigs and equipment are depreciated over their estimated
useful lives ranging from three to 30 years.
Capitalized Interest
We capitalize interest cost for the construction and upgrade of qualifying assets. For the
year ended December 31, 2008 we capitalized interest on qualifying expenditures related to the
major upgrade of one of our existing drilling rigs and the construction of two jack-up rigs through
the date of each projects completion. All qualifying construction and upgrade projects were
completed at December 31, 2008.
A reconciliation of our total interest cost to Interest expense as reported in our
Consolidated Statements of Operations is as follows:
|
|
|
|
|
|
|
For the Year Ended |
|
|
|
December 31, 2008 |
|
|
|
(In thousands) |
|
Total interest cost including amortization of debt issuance costs |
|
$ |
26,966 |
|
Capitalized interest |
|
|
(16,870 |
) |
|
|
|
|
Total interest expense as reported |
|
$ |
10,096 |
|
|
|
|
|
We did not capitalize any interest cost during the years ended December 31, 2010 and 2009 as
there were no qualifying expenditures during the period.
Asset Retirement Obligations
At December 31, 2010 and 2009, we had no asset retirement obligations.
59
Impairment of Long-Lived Assets
We evaluate our property and equipment for impairment whenever changes in circumstances
indicate that the carrying amount of an asset may not be recoverable (such as cold-stacking a rig
or excess spending over budget on a new-build or major rig upgrade). We utilize a
probability-weighted cash flow analysis in testing an asset for potential impairment. Our
assumptions and estimates underlying this analysis may include the following:
|
|
|
dayrate by rig; |
|
|
|
|
utilization rate by rig (expressed as the actual percentage of time per year that the
rig would be used); |
|
|
|
|
the per day operating cost for each rig if active, ready-stacked or cold-stacked; |
|
|
|
|
the estimated maintenance, inspection or other costs associated with a rig returning
to work; |
|
|
|
|
salvage value for each rig; and |
|
|
|
|
estimated proceeds that may be received on disposition of the rig. |
Based on these assumptions and estimates, we develop a matrix by assigning probabilities to various
combinations of assumed utilization rates and dayrates.
2010. As of December 31, 2010, our cold-stacked fleet consisted of one independent-leg,
cantilevered and three mat-supported jack-up rigs (all in the U.S. Gulf of Mexico, or GOM) and
three intermediate semisubmersible rigs (two in the GOM and one in Malaysia). We performed an
impairment review for each of these rigs using the methodology described above. Based on our
analyses, we concluded that these seven rigs were not subject to impairment at December 31, 2010.
2009. As of December 31, 2009, we had cold-stacked our three mat-supported jack-up rigs and
were in the process of cold-stacking an intermediate semisubmersible drilling rig in Malaysia. We
performed an impairment review for each of these rigs using the methodology described above. Based
on our analyses, we concluded that these four rigs were not subject to impairment at December 31,
2009.
2008. As of December 31, 2008, all of our drilling rigs were either under contract, in
shipyards for surveys or contract modifications or, as in the case of the upgraded Ocean Monarch,
mobilizing to the U.S., except for two jack-up rigs. One of these idle units, the Ocean Tower, was
damaged during Hurricane Ike in September 2008 (see Note 15) and taken out of service. The rig was
subsequently sold in October 2009 for a net gain of $6.7 million. At December 31, 2008, the second
of our idle rigs was ready stacked while waiting to begin drilling operations in early January
2009. Consequently, we determined that an impairment test of our drilling equipment was not needed
as all of our drilling units were being marketed at the time, and we did not have any cold-stacked
rigs at December 31, 2008.
Managements assumptions are an inherent part of our asset impairment evaluation and the use
of different assumptions could produce results that differ from those reported.
Fair Value of Financial Instruments
We believe that the carrying amount of our current financial instruments approximates fair
value because of the short maturity of these instruments. For non-current financial instruments we
use quoted market prices, when available, and discounted cash flows to estimate fair value. See
Note 7.
Debt Issuance Costs
Debt issuance costs are included in our Consolidated Balance Sheets in Other assets and are
amortized over the respective terms of the related debt.
Income Taxes
We account for income taxes in accordance with accounting standards that require the
recognition of the amount of taxes payable or refundable for the current year and an asset and
liability approach in recognizing the amount of deferred tax liabilities and assets for the future
tax consequences of events that have been currently recognized in our financial statements or tax
returns. In each of our tax jurisdictions we recognize a current tax liability or asset for the
estimated taxes payable or refundable on tax returns for the current year and a deferred tax asset
or liability for the
60
estimated future tax effects attributable to temporary differences and
carryforwards. Deferred tax assets are reduced by
a valuation allowance, if necessary, which is determined by the amount of any tax benefits
that, based on available
evidence, are not expected to be realized under a more likely than not
approach. We make judgments regarding future events and related estimates especially as they
pertain to the forecasting of our effective tax rate, the potential realization of deferred tax
assets such as utilization of foreign tax credits, and exposure to the disallowance of items
deducted on tax returns upon audit.
We record interest related to accrued unrecognized tax positions in interest expense and
recognize penalties associated with uncertain tax positions in our tax expense. See Note 13.
Treasury Stock
Depending on market conditions, we may, from time to time, purchase shares of our common stock
in the open market or otherwise. We account for the purchase of treasury stock using the cost
method, which reports the cost of the shares acquired in Treasury stock as a deduction from
stockholders equity in our Consolidated Balance Sheets. We did not repurchase any shares of our
outstanding common stock during 2010, 2009 or 2008.
Comprehensive Income (Loss)
Comprehensive income (loss) is the change in equity of a business enterprise during a period
from transactions and other events and circumstances except those transactions resulting from
investments by owners and distributions to owners. Comprehensive income (loss) for the three years
ended December 31, 2010, 2009 and 2008 includes net income (loss) and unrealized holding gains and
losses on marketable securities and financial derivatives designated as cash flow accounting
hedges. See Note 10.
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 years ended December 31, 2010, 2009 and 2008, we recognized net foreign
currency gains (losses) of $1.4 million, $11.5 million and $(65.6) million, respectively. See Note
6.
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 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.
61
2. Supplemental Financial Information
Consolidated Balance Sheet Information
Accounts receivable, net of provision for bad debts, consist of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
(In thousands) |
Trade receivables |
|
$ |
633,224 |
|
|
$ |
812,180 |
|
Value added tax receivables |
|
|
5,003 |
|
|
|
10,273 |
|
Unbilled third party claims |
|
|
45 |
|
|
|
6,315 |
|
Related party receivables |
|
|
538 |
|
|
|
115 |
|
Other |
|
|
2,704 |
|
|
|
3,838 |
|
|
|
|
|
|
|
641,514 |
|
|
|
832,721 |
|
Allowance for doubtful accounts |
|
|
(31,908 |
) |
|
|
(41,698 |
) |
|
|
|
Total |
|
$ |
609,606 |
|
|
$ |
791,023 |
|
|
|
|
During 2008, we recorded a $31.9 million provision for bad debts to reserve the uncollected
balance of one of our customers in the United Kingdom, or U.K., that had entered into
administration (a U.K. insolvency proceeding similar to U.S. Chapter 11 bankruptcy). In 2009,
we recorded a $10.7 million provision for bad debts to reserve a portion of the uncollected
balance of receivables related to our operations in Egypt and recovered $0.9 million
associated with the reserve for bad debts recorded in 2008. During 2010, we recovered $4.2
million and $5.5 million associated with the reserves for bad debts recorded in 2008 and 2009,
respectively. No additional allowances were deemed necessary for the years presented.
Prepaid expenses and other current assets consist of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
(In thousands) |
Rig spare parts and supplies |
|
$ |
50,288 |
|
|
$ |
49,122 |
|
Deferred mobilization costs |
|
|
76,868 |
|
|
|
45,502 |
|
Prepaid insurance |
|
|
9,587 |
|
|
|
11,478 |
|
Deferred tax assets |
|
|
9,557 |
|
|
|
7,235 |
|
Deposits |
|
|
827 |
|
|
|
3,562 |
|
Prepaid taxes |
|
|
20,347 |
|
|
|
27,679 |
|
FOREX contracts |
|
|
4,326 |
|
|
|
2,634 |
|
Other |
|
|
5,353 |
|
|
|
7,865 |
|
|
|
|
Total |
|
$ |
177,153 |
|
|
$ |
155,077 |
|
|
|
|
Accrued liabilities consist of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
(In thousands) |
Accrued capital project/upgrade costs |
|
$ |
28,947 |
|
|
$ |
64,940 |
|
Payroll and benefits |
|
|
76,041 |
|
|
|
69,065 |
|
Deferred revenue |
|
|
69,825 |
|
|
|
46,666 |
|
Rig operating expenses |
|
|
81,371 |
|
|
|
79,965 |
|
Interest payable |
|
|
21,219 |
|
|
|
22,710 |
|
Personal injury and other claims |
|
|
11,758 |
|
|
|
10,018 |
|
Accrued drillship construction installment |
|
|
154,427 |
|
|
|
|
|
Other |
|
|
25,602 |
|
|
|
8,507 |
|
|
|
|
Total |
|
$ |
469,190 |
|
|
$ |
301,871 |
|
|
|
|
62
Consolidated Statement of Cash Flows Information
We paid interest totaling $83.5 million, $39.5 million and $25.1 million on long-term debt for
the years ended December 31, 2010, 2009 and 2008, respectively. We paid $0.9 million in interest
on Internal Revenue Service assessments during the year ended December 31, 2010.
We paid $128.5 million, $176.2 million and $120.7 million in foreign income taxes, net of
foreign tax refunds, during the years ended December 31, 2010, 2009 and 2008, respectively. We
paid $427.5 million, $252.4 million and $393.2 million in U.S. federal income taxes during the
years ended December 31, 2010, 2009 and 2008, respectively. We paid state income taxes, net of
refunds, of $0.1 million and $0.2 million during the years ended December 31, 2010 and 2009,
respectively, and received a $0.1 million refund of state income tax during the year ended December
31, 2008.
Cash payments for capital expenditures for the years ended December 31, 2010, 2009 and 2008
included $64.9 million, $59.4 million and $43.0 million, respectively, of capital expenditures that
were accrued but unpaid on December 31, 2009, 2008 and 2007, respectively. Capital expenditures
that were accrued but not paid as of December 31, 2010 and 2009 totaled $28.9 million and $64.9
million, respectively. We have included these amounts in Accrued liabilities in our Consolidated
Balance Sheets at December 31, 2010 and 2009.
We recorded income tax benefits of $0, $1.0 million and $1.5 million related to the exercise
of employee stock options in 2010, 2009 and 2008, respectively.
During 2008, holders of $33,000 in accreted, or carrying, value through the date of conversion
of our Zero Coupon Convertible Debentures due 2020, or Zero Coupon Debentures, elected to convert
their outstanding debentures into shares of our common stock. Also during 2008, the holders of
$3.5 million in principal amount of our 1.5% Convertible Senior Debentures due 2031, or 1.5%
Debentures, elected to convert their outstanding debentures into shares of our common stock. See
Note 9.
3. Stock-Based Compensation
Our Second Amended and Restated 2000 Stock Option Plan, as amended, or Stock Plan, provides
for the issuance of either incentive stock options or non-qualified stock options to our employees,
consultants and non-employee directors. Our Stock Plan also authorizes the award of stock
appreciation rights, or SARs, in tandem with stock options or separately. The maximum aggregate
number of shares of our common stock for which stock options or SARs may be granted is 1,500,000
shares. The exercise price per share may not be less than the fair market value of the common
stock on the date of grant. Generally, stock options and SARs vest ratably over a four year period
and expire in ten years.
Total compensation cost recognized for Stock Plan transactions for the years ended December
31, 2010, 2009 and 2008 was $6.0 million, $6.5 million and $6.3 million, respectively. Tax
benefits recognized for the years ended December 31, 2010, 2009 and 2008 related thereto were $2.0
million, $2.1 million and $2.1 million, respectively.
The fair value of options and SARs granted under the Stock Plan during each of the years ended
December 31, 2010, 2009 and 2008 was estimated using the Black Scholes pricing model.
The following are the weighted average assumptions used in estimating the fair value of our
options and SARs:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
|
Expected life of stock options/SARs (in years) |
|
|
5 |
|
|
|
5 |
|
|
|
5 |
|
Expected volatility |
|
|
35.99 |
% |
|
|
37.24 |
% |
|
|
31.96 |
% |
Dividend yield |
|
|
.70 |
% |
|
|
.62 |
% |
|
|
.51 |
% |
Risk free interest rate |
|
|
1.88 |
% |
|
|
2.17 |
% |
|
|
2.66 |
% |
Expected life of stock options and SARs is based on historical data as is the expected
volatility. The dividend yield is based on the current approved regular dividend rate in effect
and the current market price at the time of
grant. Risk free interest rates are determined using the U.S. Treasury yield curve at time of
grant with a term equal to the expected life of the options and SARs.
63
A summary of activity under the Stock Plan as of December 31, 2010 and changes during the year
then ended is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted- |
|
Aggregate |
|
|
|
|
|
|
|
|
|
|
Average Remaining |
|
Intrinsic |
|
|
|
|
|
|
Weighted- |
|
Contractual |
|
Value |
|
|
Number of |
|
Average |
|
Term |
|
(In |
|
|
Awards |
|
Exercise Price |
|
(Years) |
|
Thousands) |
|
|
|
Awards outstanding at January 1, 2010 |
|
|
681,743 |
|
|
$ |
94.82 |
|
|
|
|
|
|
|
|
|
Granted |
|
|
195,750 |
|
|
$ |
72.81 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(1,251 |
) |
|
$ |
54.43 |
|
|
|
|
|
|
|
|
|
Forfeited |
|
|
(32,623 |
) |
|
$ |
90.60 |
|
|
|
|
|
|
|
|
|
Expired |
|
|
(22,095 |
) |
|
$ |
100.19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards outstanding at December 31, 2010 |
|
|
821,524 |
|
|
$ |
89.66 |
|
|
|
7.7 |
|
|
$ |
1,532 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards exercisable at December 31, 2010 |
|
|
460,213 |
|
|
$ |
91.73 |
|
|
|
7.0 |
|
|
$ |
1,088 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The weighted-average grant date fair values of awards granted during the years ended December
31, 2010, 2009 and 2008 were $23.62, $28.46 and $33.73, respectively. The total intrinsic value of
awards exercised during the years ended December 31, 2010, 2009 and 2008 was $8,000, $1.5 million
and $6.3 million, respectively. The total fair value of awards vested during the years ended
December 31, 2010, 2009 and 2008 was $6.6 million, $6.6 million and $5.3 million, respectively. As
of December 31, 2010 there was $7.4 million of total unrecognized compensation cost related to
nonvested stock options and SARs granted under the Stock Plan which we expect to recognize over a
weighted average period of 2.73 years.
4. Earnings Per Share
A reconciliation of the numerators and the denominators of the basic and diluted per-share
computations follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands, except per share data) |
Net income basic (numerator): |
|
$ |
955,457 |
|
|
$ |
1,376,219 |
|
|
$ |
1,310,547 |
|
Effect of dilutive potential shares |
|
|
|
|
|
|
|
|
|
|
|
|
Zero Coupon Debentures |
|
|
56 |
|
|
|
94 |
|
|
|
32 |
|
1.5% Debentures |
|
|
|
|
|
|
|
|
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income including conversions diluted
(numerator): |
|
$ |
955,513 |
|
|
$ |
1,376,313 |
|
|
$ |
1,310,601 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-average shares basic (denominator): |
|
|
139,026 |
|
|
|
139,007 |
|
|
|
138,959 |
|
Effect of dilutive potential shares |
|
|
|
|
|
|
|
|
|
|
|
|
Zero Coupon Debentures |
|
|
21 |
|
|
|
51 |
|
|
|
51 |
|
1.5% Debentures |
|
|
|
|
|
|
|
|
|
|
19 |
|
Stock options and SARs |
|
|
23 |
|
|
|
39 |
|
|
|
44 |
|
|
|
|
Weighted-average shares including conversions
diluted (denominator): |
|
|
139,070 |
|
|
|
139,097 |
|
|
|
139,073 |
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
6.87 |
|
|
$ |
9.90 |
|
|
$ |
9.43 |
|
|
|
|
Diluted |
|
$ |
6.87 |
|
|
$ |
9.89 |
|
|
$ |
9.42 |
|
|
|
|
Our computation of diluted earnings per share, or EPS, for the year ended December 31,
2010 excludes stock options representing 11,447 shares of common stock and 584,319 SARs. Our
computation of diluted EPS for the year ended December 31, 2009 excludes stock options representing 8,291 shares of common stock and 413,610
64
SARs. Our computation of diluted EPS for the year ended December 31, 2008 excludes
stock options representing 3,362 shares of common stock and 254,821 SARs.
The inclusion of such potentially dilutive shares in the computation of diluted EPS for any of
the years ended December 31, 2010, 2009 and 2008 would have been antidilutive for the respective
period.
5. Marketable Securities
We report our investments in marketable securities as current assets in our Consolidated
Balance Sheets in Marketable securities, representing the investment of cash available for
current operations.
Our investments in marketable securities are classified as available for sale and are
summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
Amortized |
|
Unrealized |
|
Market |
|
|
Cost |
|
Gain (Loss) |
|
Value |
|
|
(In thousands) |
U.S. Treasury Bills (due within one year) |
|
$ |
599,965 |
|
|
$ |
15 |
|
|
$ |
599,980 |
|
Corporate bonds |
|
|
11,200 |
|
|
|
560 |
|
|
|
11,760 |
|
Mortgage-backed securities |
|
|
553 |
|
|
|
53 |
|
|
|
606 |
|
|
|
|
Total |
|
$ |
611,718 |
|
|
$ |
628 |
|
|
$ |
612,346 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2009 |
|
|
Amortized |
|
Unrealized |
|
Market |
|
|
Cost |
|
Gain (Loss) |
|
Value |
|
|
(In thousands) |
U.S. Treasury Bills (due within one year) |
|
$ |
399,997 |
|
|
$ |
(1 |
) |
|
$ |
399,996 |
|
Mortgage-backed securities |
|
|
792 |
|
|
|
65 |
|
|
|
857 |
|
|
|
|
Total |
|
$ |
400,789 |
|
|
$ |
64 |
|
|
$ |
400,853 |
|
|
|
|
Proceeds from maturities and sales of marketable securities and gross realized gains and
losses are summarized as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Proceeds from maturities |
|
$ |
5,450,000 |
|
|
$ |
1,925,000 |
|
|
$ |
550,000 |
|
Proceeds from sales |
|
|
230 |
|
|
|
2,548,891 |
|
|
|
943,803 |
|
Gross realized gains |
|
|
|
|
|
|
791 |
|
|
|
1,291 |
|
Gross realized losses |
|
|
(7 |
) |
|
|
(172 |
) |
|
|
(9 |
) |
6. 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
65
gains/losses on future foreign currency expenditures. 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 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 are recorded as a component of Accumulated other comprehensive
gains, 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 year ended December 31, 2010, we settled FOREX contracts with an aggregate notional
value of approximately $332.5 million, of which the entire aggregate amount was designated as an
accounting hedge. During the year ended December 31, 2009, we settled FOREX contracts with an
aggregate notional value of approximately $333.4 million, of which an aggregate notional value of
$112.8 million was designated as an accounting hedge. During the year ended December 31, 2008, we
settled FOREX contracts with an aggregate notional value of approximately $538.8 million, none of
which were designated as accounting hedges.
The following table presents the amounts recognized in our Consolidated Statements of
Operations related to our FOREX contracts designated as hedging instruments for the years ended
December 31, 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain Recognized in Income |
|
|
For the Years Ended December 31, |
Location of Gain (Loss) Recognized in Income |
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Contract drilling expense |
|
$ |
3,307 |
|
|
$ |
8,895 |
|
|
$ |
|
|
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 years ended
December 31, 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Amount of Gain (Loss) Recognized in Income |
|
|
For the Years Ended December 31, |
Location of Gain (Loss) Recognized in Income |
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Foreign currency transaction gain (loss) |
|
$ |
|
|
|
$ |
8,856 |
|
|
$ |
(54,010 |
) |
The amounts presented in the table above for the years ended December 31, 2009 and 2008
include net unrealized gains aggregating $37.3 million and net unrealized losses of approximately
$(37.2) million, respectively, 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 year ended December 31, 2010.
As of December 31, 2010, we had FOREX contracts outstanding in the aggregate notional amount
of $140.3 million, consisting of $35.1 million in Australian dollars, $81.2 million in Brazilian
reais, $9.2 million in British pounds sterling, $3.0 million in Mexican pesos and $11.8 million in
Norwegian kroner. These contracts generally settle monthly through July 2011. As of December 31,
2010, all outstanding derivative contracts had been
designated as cash flow hedges.
66
The following table presents the fair values of our derivative financial instruments at
December 31, 2010.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assets |
|
Liabilities |
|
|
Balance Sheet |
|
|
|
|
|
Balance Sheet |
|
|
|
|
Location |
|
Fair Value |
|
Location |
|
Fair Value |
|
|
|
|
(In |
|
|
|
(In |
|
|
|
|
thousands) |
|
|
|
thousands) |
Derivatives
designated as
hedging
instruments: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid expenses |
|
|
|
|
|
|
|
|
|
|
|
|
and other current |
|
|
|
|
|
|
|
|
|
|
FOREX contracts |
|
assets |
|
$ |
4,327 |
|
|
Accrued liabilities |
|
$ |
(121 |
) |
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: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Prepaid expenses |
|
|
and other current |
|
|
|
|
|
|
|
|
|
|
FOREX contracts |
|
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 years ended December 31, 2010, 2009 and 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of Gain |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized in |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income on |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location of |
|
|
|
|
|
|
|
|
|
|
|
|
|
Derivative |
|
Amount of Gain |
|
|
|
|
|
|
|
|
|
|
|
|
Gain |
|
|
|
|
|
|
|
|
|
|
|
|
|
(Ineffective |
|
Recognized in Income |
|
|
|
|
|
|
|
|
|
|
|
|
Reclassified |
|
|
|
|
|
|
|
|
|
|
|
|
|
Portion and |
|
on Derivative |
Amount of Gain |
|
from AOCG |
|
Amount of Gain |
|
Amount |
|
(Ineffective Portion |
Recognized in AOCG on |
|
into Income |
|
Reclassified from |
|
Excluded from |
|
and Amount Excluded |
Derivative (Effective |
|
(Effective |
|
AOCG into Income |
|
Effectiveness |
|
from Effectiveness |
Portion) |
|
Portion) |
|
(Effective Portion) |
|
Testing) |
|
Testing) |
For the years ended |
|
|
|
For the years ended |
|
|
|
|
|
For the years ended |
December 31, |
|
|
|
December 31, |
|
|
|
|
|
December 31, |
2010 |
|
2009 |
|
2008 |
|
|
|
2010 |
|
2009 |
|
2008 |
|
|
|
|
|
2010 |
|
2009 |
|
2008 |
(In thousands) |
|
|
|
(In thousands) |
|
|
|
|
|
(In thousands) |
$ |
3,591 |
|
|
$ |
9,838 |
|
|
$ |
|
|
|
Contract drilling expense |
|
$ |
1,790 |
|
|
$ |
7,434 |
|
|
$ |
|
|
|
Foreign currency transaction gain |
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
As of December 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 $4.2
million. The net unrealized gains associated with these derivative financial instruments will be
reclassified to contract drilling expense.
7. 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 mortgage-backed securities. We generally
place our excess cash investments in high quality
67
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. One of our two customers in Brazil,
Petróleo Brasileiro S.A. (a Brazilian multinational energy company that is majority-owned by the
Brazilian government), accounted for $180.8 million and
$115.6 million, or 29% and 14%, of the total
consolidated trade accounts receivable balances as of December 31, 2010 and 2009, respectively.
In general, before working for a customer with whom we have not had a prior business
relationship and/or whose financial stability may be uncertain to us, we perform a credit review on
that company. Based on that analysis, we may require that the customer present a letter of credit,
prepay or provide other credit enhancements. Historically, we have not experienced significant
losses on our trade receivables. We record a provision for bad debts on a case-by-case basis when
facts and circumstances indicate that a customer receivable may not be collectible. Our provision
for bad debts was $31.9 million and $41.7 million at December 31, 2010 and 2009, respectively. See
Note 2.
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, an aggregate drilling rate of $560,000 per day, consisting of
$75,000 per day payable 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, payable through the
conveyance of a 27% net profits interest, or NPI, in certain developmental oil-and-gas producing
properties. We began receiving payments from the conveyance of the NPI in July 2010. Based on
current production payout estimates, we expect to collect $49.6 million of the receivable within
the next twelve months. However, payment of such amounts, and the timing of such payments, are
contingent upon such production and upon energy sale prices.
At December 31, 2010, $85.0 million was payable to us from the NPI, of which $49.6 million and
$35.4 million are presented as Accounts receivable and Long-term receivable, respectively, in
our Consolidated Balance Sheets. At December 31, 2009, $70.5 million was payable to us from the
NPI, all of which was presented as Accounts receivable in our Consolidated Balance Sheets. At
December 31, 2010 and 2009, we believe that collectability of the amount owed pursuant to the NPI
arrangement was reasonably assured.
Fair Values
The amounts reported in our Consolidated Balance Sheets for cash and cash equivalents,
marketable securities, accounts receivable, forward exchange contracts, long term receivables, and
accounts payable approximate fair value. Fair values and related carrying values of our debt
instruments are shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
|
Fair Value |
|
Carrying Value |
|
Fair Value |
|
Carrying Value |
|
|
|
|
|
|
(In millions) |
|
|
|
|
Zero Coupon Debentures |
|
$ |
|
|
|
$ |
|
|
|
$ |
5.1 |
|
|
$ |
4.2 |
|
4.875% Senior Notes |
|
|
270.0 |
|
|
|
249.7 |
|
|
|
257.5 |
|
|
|
249.7 |
|
5.15% Senior Notes |
|
|
271.1 |
|
|
|
249.7 |
|
|
|
263.3 |
|
|
|
249.7 |
|
5.70% Senior Notes |
|
|
493.1 |
|
|
|
496.8 |
|
|
|
490.4 |
|
|
|
496.7 |
|
5.875% Senior Notes |
|
|
550.9 |
|
|
|
499.4 |
|
|
|
530.6 |
|
|
|
499.3 |
|
We have estimated the fair value amounts by using appropriate valuation methodologies and
information available to management as of December 31, 2010 and 2009, respectively. Considerable
judgment is required in developing these estimates, and accordingly, no assurance can be given that
the estimated values are indicative of
68
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 December 31, 2010 and 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 December 31, 2010 and
2009, respectively. |
|
|
|
|
Long-term receivable The carrying amount approximates fair value based on the
nature of the instrument. |
|
|
|
|
Long-term debt The fair value of our 5.70% Senior Notes due 2039, or 5.70% Senior
Notes, 5.875% Senior Notes due 2019, or 5.875% Senior Notes, 4.875% Senior Notes due
July 1, 2015, or 4.875% Senior Notes, and 5.15% Senior Notes due September 1, 2014, or
5.15% Senior Notes, was based on the quoted closing market price on December 31, 2010
and 2009, respectively, from brokers of these instruments. The fair value of our Zero
Coupon Debentures was based on the closing market price of our common stock on December
31, 2009, 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 December 31, 2010
consisted of cash held in money market funds of $442.2 million and
investments in U.S. Treasury Bills of $600.0 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, corporate bonds purchased
in a private placement offering and over-the-counter FOREX
contracts. Our residential mortgage-backed securities are valued
using a model-derived valuation technique based on the quoted
closing market prices received from a financial institution. Our
private placement bonds are valued based on the mid-point of the
bid/ask spread for the bond obtained from a financial institution
and then corroborated with quoted closing market prices from other
financial institutions available on Bloomberg and also with market
prices of comparable bonds which are publicly traded. 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. |
69
Assets and liabilities measured at fair value on a recurring basis are summarized below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2010 |
|
|
Fair Value Measurements Using |
|
Assets at Fair |
|
|
Level 1 |
|
Level 2 |
|
Level 3 |
|
Value |
|
|
(In thousands) |
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term investments |
|
$ |
1,042,224 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1,042,224 |
|
FOREX contracts |
|
|
|
|
|
|
4,327 |
|
|
|
|
|
|
|
4,327 |
|
Corporate bonds |
|
|
|
|
|
|
11,760 |
|
|
|
|
|
|
|
11,760 |
|
Mortgage-backed securities |
|
|
|
|
|
|
606 |
|
|
|
|
|
|
|
606 |
|
|
|
|
|
|
|
Total assets |
|
$ |
1,042,224 |
|
|
$ |
16,693 |
|
|
$ |
|
|
|
$ |
1,058,917 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
FOREX contracts |
|
$ |
|
|
|
$ |
(121 |
) |
|
$ |
|
|
|
$ |
(121 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
) |
|
|
|
|
|
|
8. Drilling and Other Property and Equipment
Cost and accumulated depreciation of drilling and other property and equipment are summarized
as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
(In thousands) |
Drilling rigs and equipment |
|
$ |
7,163,196 |
|
|
$ |
6,950,303 |
|
Land and buildings |
|
|
56,536 |
|
|
|
44,640 |
|
Office equipment and other |
|
|
44,689 |
|
|
|
38,203 |
|
|
|
|
|
Cost |
|
|
7,264,421 |
|
|
|
7,033,146 |
|
Less accumulated depreciation |
|
|
(2,980,629 |
) |
|
|
(2,601,094 |
) |
|
|
|
|
Drilling and other property and equipment, net |
|
$ |
4,283,792 |
|
|
$ |
4,432,052 |
|
|
|
|
|
During 2010, we sold the Ocean Shield and certain equipment for a net purchase price of
$185.3 million and recorded a net gain on sale of approximately $32.8 million.
70
9. Long-Term Debt
Long-term debt consists of the following:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
(In thousands) |
5.70% Senior Notes (due 2039) |
|
$ |
496,773 |
|
|
$ |
496,730 |
|
5.875% Senior Notes (due 2019) |
|
|
499,351 |
|
|
|
499,292 |
|
4.875% Senior Notes (due 2015) |
|
|
249,724 |
|
|
|
249,671 |
|
5.15% Senior Notes (due 2014) |
|
|
249,745 |
|
|
|
249,682 |
|
Zero Coupon Debentures (due 2020) |
|
|
|
|
|
|
4,179 |
|
|
|
|
|
|
|
|
1,495,593 |
|
|
|
1,499,554 |
|
Less: Current maturities |
|
|
|
|
|
|
4,179 |
|
|
|
|
|
Total |
|
$ |
1,495,593 |
|
|
$ |
1,495,375 |
|
|
|
|
|
The aggregate maturities of long-term debt for each of the five years subsequent to December
31, 2010, are as follows:
|
|
|
|
|
(Dollars in thousands) |
|
2011 |
|
$ |
|
|
2012 |
|
|
|
|
2013 |
|
|
|
|
2014 |
|
|
249,745 |
|
2015 |
|
|
249,724 |
|
Thereafter |
|
|
996,124 |
|
|
|
|
|
|
|
|
1,495,593 |
|
Less: Current maturities |
|
|
|
|
|
|
|
|
Total |
|
$ |
1,495,593 |
|
|
|
|
|
$285 Million Revolving Credit Facility
In November 2006, we entered into 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 December 31, 2010, the applicable margin on LIBOR loans
would have been 0.24%. As of December 31, 2010, there were no loans outstanding under the Credit
Facility. See Note 11 for a discussion of letters of credit issued under the Credit Facility.
71
5.70% Senior Notes
On October 8, 2009, we issued $500.0 million aggregate principal amount of our 5.70% Senior
Notes for general corporate purposes. The 5.70% Senior Notes were issued at an offering price of
99.344% of the principal and resulted in net proceeds to us of approximately $496.7 million. We
incurred issuance costs of $4.8 million related to this transaction.
These notes bear interest at 5.70% per year, payable semiannually in arrears on April 15 and
October 15 of each year, and mature on October 15, 2039. The 5.70% Senior Notes are unsecured and
unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equal in right of payment to
its existing and future unsecured and unsubordinated indebtedness, and will be effectively
subordinated to all existing and future obligations of our subsidiaries. We have the right to
redeem all or a portion of these notes for cash at any time or from time to time, on at least 15
days but not more than 60 days prior written notice, at the redemption price specified in the
governing indenture plus accrued and unpaid interest to the date of redemption.
5.875% Senior Notes
On May 4, 2009, we issued $500.0 million aggregate principal amount of our 5.875% Senior Notes
for general corporate purposes. The 5.875% Senior Notes were issued at an offering price of
99.851% of the principal and resulted in net proceeds to us of approximately $499.3 million. We
incurred issuance costs of $4.0 million related to this transaction.
These notes bear interest at 5.875% per year, payable semiannually in arrears on May 1 and
November 1 of each year, and mature on May 1, 2019. The 5.875% Senior Notes are unsecured and
unsubordinated obligations of Diamond Offshore Drilling, Inc. and rank equal in right of payment to
its existing and future unsecured and unsubordinated indebtedness, and will be effectively
subordinated to all existing and future obligations of our subsidiaries. We have the right to
redeem all or a portion of these notes for cash at any time or from time to time, on at least 15
days but not more than 60 days prior written notice, at the redemption price specified in the
governing indenture plus accrued and unpaid interest to the date of redemption.
4.875% Senior Notes
Our 4.875% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at
4.875% per year, payable semiannually in arrears on January 1 and July 1 of each year, and mature
on July 1, 2015. Our 4.875% Senior Notes are unsecured and unsubordinated obligations of Diamond
Offshore Drilling, Inc. and rank equal in right of payment to its existing and future unsecured and
unsubordinated indebtedness, and will be effectively subordinated to all existing and future
obligations of our subsidiaries. We have the right to redeem all or a portion of the 4.875% Senior
Notes for cash at any time or from time to time, on at least 15 days but not more than 60 days
prior written notice, at the redemption price specified in the governing indenture plus accrued and
unpaid interest to the date of redemption.
5.15% Senior Notes
Our 5.15% Senior Notes, in the aggregate principal amount of $250.0 million, bear interest at
5.15% per year, payable semiannually in arrears on March 1 and September 1 of each year, and mature
on September 1, 2014. The 5.15% Senior Notes are unsecured and unsubordinated obligations of
Diamond Offshore Drilling, Inc. and rank equal in right of payment to its existing and future
unsecured and unsubordinated indebtedness, and will be effectively subordinated to all existing and
future obligations of our subsidiaries. We have the right to redeem all or a portion of the 5.15%
Senior Notes for cash at any time or from time to time, on at least 15 days but not more than 60
days prior written notice, at the redemption price specified in the governing indenture plus
accrued and unpaid interest to the date of redemption.
Zero Coupon Debentures
On June 6, 2000, we issued Zero Coupon Debentures at a price of $499.60 per $1,000 principal
amount at maturity, representing a yield to maturity of 3.50% per year, with a maturity date of
June 6, 2020.
We had the right to redeem the Zero Coupon Debentures, in whole or in part, for a price equal
to the issuance
price plus accrued original issue discount through the date of redemption. On May 28, 2010, we
redeemed the then
72
outstanding $4.2 million accreted value, or $6.0 million in aggregate principal
amount at maturity, of our Zero Coupon Debentures at a redemption price of $706.28 per $1,000
principal amount at maturity for cash. At December 31, 2010, there were no Zero Coupon Debentures
outstanding.
10. Other Comprehensive Income (Loss)
The components of our other comprehensive income (loss) and the associated income tax
effects allocated to such components are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2010 |
|
|
Before Tax |
|
Tax Effect |
|
Net-of-Tax |
|
|
(In thousands) |
FOREX contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain |
|
$ |
3,591 |
|
|
$ |
(1,257 |
) |
|
$ |
2,334 |
|
Reclassification adjustment for gain included in net income |
|
|
(1,790 |
) |
|
|
626 |
|
|
|
(1,164 |
) |
|
|
|
|
|
Net unrealized gain on FOREX contracts |
|
|
1,801 |
|
|
|
(631 |
) |
|
|
1,170 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain |
|
|
528 |
|
|
|
(185 |
) |
|
|
343 |
|
Reclassification adjustment for gain included in net income |
|
|
36 |
|
|
|
(13 |
) |
|
|
23 |
|
|
|
|
|
|
Net unrealized loss on marketable securities |
|
|
564 |
|
|
|
(198 |
) |
|
|
366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income |
|
$ |
2,365 |
|
|
$ |
(829 |
) |
|
$ |
1,536 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2009 |
|
|
Before Tax |
|
Tax Effect |
|
Net-of-Tax |
|
|
(In thousands) |
FOREX contracts: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain |
|
$ |
9,838 |
|
|
$ |
(3,443 |
) |
|
$ |
6,395 |
|
Reclassification adjustment for gain included in net income |
|
|
(7,434 |
) |
|
|
2,602 |
|
|
|
(4,832 |
) |
|
|
|
|
|
Net unrealized gain on FOREX contracts |
|
|
2,404 |
|
|
|
(841 |
) |
|
|
1,563 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments in marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain |
|
|
63 |
|
|
|
(22 |
) |
|
|
41 |
|
Reclassification adjustment for gain included in net income |
|
|
(783 |
) |
|
|
274 |
|
|
|
(509 |
) |
|
|
|
|
|
Net unrealized gain on marketable securities |
|
|
(720 |
) |
|
|
252 |
|
|
|
(468 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income |
|
$ |
1,684 |
|
|
$ |
(589 |
) |
|
$ |
1,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, 2008 |
|
|
Before Tax |
|
Tax Effect |
|
Net-of-Tax |
|
|
(In thousands) |
Investments in marketable securities: |
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized holding gain |
|
$ |
780 |
|
|
$ |
(273 |
) |
|
$ |
507 |
|
Reclassification adjustment for gain included in net income |
|
|
(18 |
) |
|
|
6 |
|
|
|
(12 |
) |
|
|
|
|
|
Net unrealized loss on marketable securities |
|
|
762 |
|
|
|
(267 |
) |
|
|
495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other comprehensive income |
|
$ |
762 |
|
|
$ |
(267 |
) |
|
$ |
495 |
|
|
|
|
|
|
73
The components of our accumulated other comprehensive income (loss) included in our
Consolidated Balance Sheets are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized Gain (Loss) on |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Other |
|
|
FOREX |
|
Marketable |
|
Comprehensive |
|
|
Contracts |
|
Securities |
|
Income (Loss) |
|
|
(In thousands) |
Balance at January 1, 2009 |
|
$ |
|
|
|
$ |
510 |
|
|
$ |
510 |
|
Other comprehensive gain |
|
|
1,563 |
|
|
|
(468 |
) |
|
|
1,095 |
|
|
|
|
|
|
Balance at December 31, 2009 |
|
|
1,563 |
|
|
|
42 |
|
|
|
1,605 |
|
Other comprehensive gain |
|
|
1,170 |
|
|
|
366 |
|
|
|
1,536 |
|
|
|
|
|
|
Balance at December 31, 2010 |
|
$ |
2,733 |
|
|
$ |
408 |
|
|
$ |
3,141 |
|
|
|
|
|
|
11. Commitments and Contingencies
Various claims have been filed against us in the ordinary course of business, including claims
by offshore workers alleging personal injuries. 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.
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 deductibles for marine liability coverage, including personal
injury claims, which primarily result from Jones Act liability in the Gulf of Mexico, are currently
$10.0 million per the first occurrence, with no aggregate deductible, and vary in amounts ranging
between $5.0 million and, if aggregate claims exceed certain thresholds, up to $100.0 million for
each subsequent occurrence, depending on the nature, severity and frequency of claims which might
arise during the policy year. The Jones Act is a federal law that permits seamen to seek
compensation for certain injuries during the course of their employment on a vessel and governs the
liability of vessel operators and marine employers for the work-related injury or death of an
employee. We engage outside consultants to assist us in estimating our aggregate reserve for
personal injury claims based on our historical losses and utilizing various actuarial models. We
allocate a portion of the aggregate reserve to Accrued liabilities based on an estimate of claims
expected to be paid within the next twelve months with the residual recorded as Other
liabilities. At December 31, 2010, our estimated liability for personal injury claims was $35.0
million, of which $11.1 million and $23.9 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,
74
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. On December 30, 2010, we entered into a turnkey contract with Hyundai
Heavy Industries Co., Ltd., or Hyundai, for the construction of a new
dynamically positioned, ultra-deepwater drillship
with delivery scheduled for late in the second quarter of 2013. The contracted price of the new
drillship is payable in two installments. The first
installment in the amount of $154.4 million was paid in
January 2011. The total cost, including commissioning, spares
and project management, is expected to be approximately $590.0
million. At December 31, 2010, we
had accrued the first installment of $154.4 million and recorded the related noncurrent asset in an
equal amount in Accrued liabilities and Other assets, respectively, in our Consolidated Balance
Sheets. At December 31, 2010, we had no other purchase obligations for major rig upgrades or any
other significant obligations, except for those related to our direct rig operations, which arise
during the normal course of business.
In January 2011, we entered into a turnkey contract with Hyundai for the construction of a
second ultra-deepwater drillship. See Note 18.
Operating Leases. We lease office and yard facilities, housing, equipment and vehicles under
operating leases, which expire at various times through the year 2013. Total rent expense amounted
to $8.0 million, $6.0 million and $5.7 million for the years ended December 31, 2010, 2009 and
2008, respectively. Future minimum rental payments under leases are approximately $1.9 million,
$1.1 million and $0.3 million for the years ending December 31, 2011, 2012 and 2013, respectively.
There are no minimum future rental payments under leases after 2013.
Letters of Credit and Other. We were contingently liable as of December 31, 2010 in the
amount of $101.6 million under certain performance, bid, supersedeas, tax appeal and custom bonds
and letters of credit, including $21.9 million in letters of credit issued under our Credit
Facility. At December 31, 2010, three of our outstanding bonds, totaling $47.7 million, had been
purchased from a related party in a previous year after obtaining competitive quotes. Agreements
relating to approximately $47.7 million of performance bonds can require collateral at any time.
As of December 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.
12. Related-Party Transactions
Transactions with Loews. We are party to a services agreement with Loews, or the Services
Agreement, pursuant to which Loews performs certain administrative and technical services on our
behalf. Such services include personnel, internal auditing, accounting, and cash management
services, in addition to advice and assistance with respect to preparation of tax returns and
obtaining insurance. Under the Services Agreement, we are required to reimburse Loews for (i)
allocated personnel costs (such as salaries, employee benefits and payroll taxes) of the Loews
personnel actually providing such services and (ii) all out-of-pocket expenses related to the
provision of such services. The Services Agreement may be terminated at our option upon 30 days
notice to Loews and at the option of Loews upon six months notice to us. In addition, we have
agreed to indemnify Loews for all claims and damages arising from the provision of services by
Loews under the Services Agreement unless due to the gross negligence or willful misconduct of
Loews. We were charged $1.3 million, $1.1 million and $0.5 million by Loews for these support
functions during the years ended December 31, 2010, 2009 and 2008, respectively.
In addition, since 2006 we have purchased performance and appeal bonds in support of our
drilling operations offshore Mexico and workers compensation claims, respectively, from affiliates
of a majority-owned subsidiary of Loews after obtaining competitive quotes. At December 31, 2010,
three such performance bonds totaling $47.7 million were outstanding. Premiums and fees associated
with bonds purchased from affiliates totaled $58,000, $213,000 and $74,000 in 2010, 2009 and 2008,
respectively.
75
Transactions with Other Related Parties. We hire marine vessels and helicopter transportation
services at the prevailing market rate from subsidiaries of SEACOR Holdings Inc. The Chairman of
the Board of Directors, President and Chief Executive Officer of SEACOR Holdings Inc. is also a
member of our Board of Directors. For the years ended December 31, 2010, 2009 and 2008, we paid
$3.1 million, $3.6 million and $0.5 million, respectively, for the hire of such vessels and such
services.
During the years ended December 31, 2010, 2009 and 2008 we made payments of $1.0 million, $2.1
million and $2.0 million, respectively, to Ernst & Young LLP for tax and other consulting services.
The wife of our President and Chief Executive Officer is an audit partner at this firm.
13. Income Taxes
Our income tax expense is a function of the mix between our domestic and international pre-tax
earnings or losses, as well as the mix of international tax jurisdictions in which we operate.
Certain of our international rigs are owned and operated, directly or indirectly, by Diamond
Offshore International Limited, or DOIL, a Cayman Islands subsidiary which we wholly own. It is
our intention to indefinitely reinvest future earnings of DOIL to finance foreign activities except
for the earnings of Diamond East Asia Limited, or DEAL, a wholly-owned subsidiary of DOIL. It is
our intention to repatriate the earnings of DEAL and, accordingly, U.S. income taxes are provided
on its earnings.
Although we do not intend to repatriate the earnings of DOIL, these foreign earnings could
become subject to U.S. federal tax if remitted, or if deemed remitted as a dividend; however, it is
not practicable to estimate this potential tax liability.
We have certain other foreign subsidiaries for which U.S. taxes have been provided to the
extent a U.S. tax liability could arise upon remittance of earnings from these foreign
subsidiaries. As of December 31, 2010, we provided $15.0 million for U.S. taxes attributable to
undistributed earnings of the foreign subsidiaries. On actual remittance, certain countries may
impose withholding taxes that, subject to certain limitations, are then available for use as tax
credits against a U.S. tax liability, if any.
The components of income tax expense (benefit) are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Federal current |
|
$ |
183,825 |
|
|
$ |
255,753 |
|
|
$ |
346,796 |
|
State current |
|
|
191 |
|
|
|
131 |
|
|
|
(282 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign current |
|
|
203,459 |
|
|
|
150,804 |
|
|
|
128,581 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current |
|
|
387,475 |
|
|
|
406,688 |
|
|
|
475,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal deferred |
|
|
8,287 |
|
|
|
80,258 |
|
|
|
52,624 |
|
Foreign deferred |
|
|
(15,203 |
) |
|
|
5,266 |
|
|
|
8,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total deferred |
|
|
(6,916 |
) |
|
|
85,524 |
|
|
|
61,404 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
380,559 |
|
|
$ |
492,212 |
|
|
$ |
536,499 |
|
|
|
|
|
|
76
The difference between actual income tax expense and the tax provision computed by applying the
statutory federal income tax rate to income before taxes is attributable to the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Income before income tax expense: |
|
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
$ |
755,982 |
|
|
$ |
1,250,094 |
|
|
$ |
1,375,857 |
|
Foreign |
|
|
580,034 |
|
|
|
618,337 |
|
|
|
471,189 |
|
|
|
|
|
|
Worldwide |
|
$ |
1,336,016 |
|
|
$ |
1,868,431 |
|
|
$ |
1,847,046 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expected income tax expense at federal statutory rate |
|
$ |
467,606 |
|
|
$ |
653,951 |
|
|
$ |
646,466 |
|
Foreign earnings of foreign subsidiaries (not taxed
at the statutory federal income tax rate) net of
related foreign taxes |
|
|
(191,789 |
) |
|
|
(184,783 |
) |
|
|
(131,132 |
) |
Foreign earnings of foreign subsidiaries for which
U.S. federal income taxes have been provided |
|
|
29,736 |
|
|
|
62,025 |
|
|
|
8,641 |
|
Foreign taxes of domestic and foreign subsidiaries
for which U.S. federal income taxes have also been
provided |
|
|
119,009 |
|
|
|
111,381 |
|
|
|
99,587 |
|
Foreign tax credits |
|
|
(89,809 |
) |
|
|
(167,756 |
) |
|
|
(68,914 |
) |
Reduction of deferred tax liability related to a
goodwill deduction resulting from a prior period
stock acquisition |
|
|
(8,850 |
) |
|
|
(8,850 |
) |
|
|
(8,850 |
) |
Domestic production activities deduction |
|
|
|
|
|
|
(6,271 |
) |
|
|
(13,390 |
) |
Uncertain tax positions |
|
|
30,950 |
|
|
|
8,003 |
|
|
|
4,446 |
|
Revision of estimated tax balance |
|
|
(11,563 |
) |
|
|
446 |
|
|
|
(2,022 |
) |
Amortization of deferred charges associated with
intercompany rig sales to other tax jurisdictions |
|
|
30,442 |
|
|
|
14,167 |
|
|
|
(1,480 |
) |
Long-term capital gain on dividend distribution |
|
|
|
|
|
|
2,450 |
|
|
|
|
|
Net expense in connection with resolutions of tax
issues and adjustments relating to prior years |
|
|
4,217 |
|
|
|
6,470 |
|
|
|
2,814 |
|
Other |
|
|
610 |
|
|
|
979 |
|
|
|
333 |
|
|
|
|
|
|
Income tax expense |
|
$ |
380,559 |
|
|
$ |
492,212 |
|
|
$ |
536,499 |
|
|
|
|
|
|
77
Significant components of our deferred income tax assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
|
(In thousands) |
Deferred tax assets: |
|
|
|
|
|
|
|
|
Net operating loss carryforwards, or NOLs |
|
$ |
34,824 |
|
|
$ |
30,947 |
|
Goodwill |
|
|
1,049 |
|
|
|
4,198 |
|
Workers compensation and other current accruals (1) |
|
|
17,178 |
|
|
|
15,000 |
|
Disputed receivables reserved |
|
|
2,521 |
|
|
|
873 |
|
Deferred compensation |
|
|
7,478 |
|
|
|
4,377 |
|
Foreign contribution taxes |
|
|
3,100 |
|
|
|
|
|
Foreign tax credits |
|
|
186 |
|
|
|
107 |
|
Nonqualified stock options and SARs |
|
|
6,048 |
|
|
|
4,150 |
|
Other |
|
|
3,133 |
|
|
|
3,253 |
|
|
|
|
|
Total deferred tax assets |
|
|
75,517 |
|
|
|
62,905 |
|
Valuation allowance for foreign tax credits |
|
|
(186 |
) |
|
|
(107 |
) |
Valuation allowance for NOLs |
|
|
(31,916 |
) |
|
|
(30,868 |
) |
|
|
|
|
Net deferred tax assets |
|
|
43,415 |
|
|
|
31,930 |
|
|
|
|
|
Deferred tax liabilities: |
|
|
|
|
|
|
|
|
Depreciation |
|
|
(558,346 |
) |
|
|
(551,437 |
) |
Unbilled revenue |
|
|
(347 |
) |
|
|
(8,141 |
) |
Mobilization |
|
|
(2,181 |
) |
|
|
(11,095 |
) |
Undistributed earnings of foreign subsidiaries |
|
|
(15,023 |
) |
|
|
(24 |
) |
Other |
|
|
(219 |
) |
|
|
(22 |
) |
|
|
|
|
Total deferred tax liabilities |
|
|
(576,116 |
) |
|
|
(570,719 |
) |
|
|
|
|
Net deferred tax liability |
|
$ |
(532,701 |
) |
|
$ |
(538,789 |
) |
|
|
|
|
|
|
|
(1) |
|
$9.6 million and $7.2 million reflected in Prepaid expenses and other current assets
in our Consolidated Balance Sheets at December 31, 2010 and 2009, respectively. See Note
2. |
We record a valuation allowance to derecognize a portion of our deferred tax assets,
which we do not expect to be ultimately realized. A summary of changes in the valuation allowance
is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Valuation allowance as of January 1 |
|
$ |
30,975 |
|
|
$ |
29,087 |
|
|
$ |
40,468 |
|
Establishment of valuation allowances: |
|
|
|
|
|
|
|
|
|
|
|
|
Foreign tax credits |
|
|
79 |
|
|
|
107 |
|
|
|
|
|
Net operating losses |
|
|
13,381 |
|
|
|
2,025 |
|
|
|
|
|
Releases of valuation allowances in various jurisdictions |
|
|
(12,333 |
) |
|
|
(244 |
) |
|
|
(11,381 |
) |
|
|
|
|
|
|
|
Valuation allowance as of December 31 |
|
$ |
32,102 |
|
|
$ |
30,975 |
|
|
$ |
29,087 |
|
|
|
|
|
|
|
|
Our income tax returns are subject to review and examination in the various jurisdictions
in which we operate and we are currently contesting various tax assessments. We accrue for income
tax contingencies, or uncertain tax positions, that we believe are more likely than not exposures.
A reconciliation of the beginning and ending amount of unrecognized tax benefits, excluding
interest and penalties, is as follows:
78
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long term |
|
|
|
|
|
Net Liability |
|
|
Tax |
|
Long term Tax |
|
for Uncertain Tax |
|
|
Receivable |
|
Payable |
|
Positions |
|
|
|
|
|
|
(In thousands) |
|
|
|
|
Balance at January 1, 2008 |
|
$ |
3,427 |
|
|
$ |
(23,756 |
) |
|
$ |
(20,329 |
) |
Reduction based on tax positions related to a prior year |
|
|
|
|
|
|
307 |
|
|
|
307 |
|
Additions based on tax positions related to the current year |
|
|
2,418 |
|
|
|
(7,941 |
) |
|
|
(5,523 |
) |
Reductions as a result of a lapse of the applicable statute
of limitations |
|
|
(311 |
) |
|
|
2,159 |
|
|
|
1,848 |
|
|
|
|
|
|
|
|
Balance at December 31, 2008 |
|
$ |
5,534 |
|
|
$ |
(29,231 |
) |
|
$ |
(23,697 |
) |
Additions based on tax positions related to a prior year |
|
|
|
|
|
|
(4,557 |
) |
|
|
(4,557 |
) |
Additions based on tax positions related to the current year |
|
|
2,441 |
|
|
|
(6,781 |
) |
|
|
(4,340 |
) |
Reductions as a result of a lapse of the applicable statute
of limitations |
|
|
(1,504 |
) |
|
|
7,090 |
|
|
|
5,586 |
|
|
|
|
|
|
|
|
Balance at December 31, 2009 |
|
$ |
6,471 |
|
|
$ |
(33,479 |
) |
|
$ |
(27,008 |
) |
Additions based on tax positions related to a prior year |
|
|
|
|
|
|
(15,764 |
) |
|
|
(15,764 |
) |
Additions based on tax positions related to the current year |
|
|
565 |
|
|
|
(3,729 |
) |
|
|
(3,164 |
) |
|
|
|
|
|
|
|
Balance at December 31, 2010 |
|
$ |
7,036 |
|
|
$ |
(52,972 |
) |
|
$ |
(45,936 |
) |
|
|
|
|
|
|
|
At December 31, 2010, all $45.9 million of the net unrecognized tax benefits would affect
the effective tax rate if recognized.
We record interest related to accrued unrecognized tax positions in interest expense and
recognize penalties associated with uncertain tax positions in our tax expense. During the year
ended December 31, 2009, we recorded a net reduction to interest expense of $3.4 million. During
the years ended December 31, 2008 and 2010, we recognized $0.8 million and $4.8 million of interest
expense related to uncertain tax positions, respectively. Penalty related tax expense for
uncertain tax positions during the years ended December 31, 2010, 2009 and 2008 was $12.0 million,
$4.7 million and $1.1 million, respectively. Accruals for the payment of interest and penalties in
our Consolidated Balance Sheets at December 31, 2010 and 2009 were $34.2 million and $17.4 million,
respectively.
In several of the international locations in which we operate, certain of our wholly-owned
subsidiaries enter into agreements with other of our wholly-owned subsidiaries to provide
specialized services and equipment in support of our foreign operations. We apply a transfer
pricing methodology to determine the amount to be charged for providing the services and equipment.
In most cases, there are alternative transfer pricing methodologies that could be applied to these
transactions and, if applied, could result in different chargeable amounts. Taxing authorities in
the various foreign locations in which we operate could apply one of the alternative transfer
pricing methodologies that could result in an increase to our income tax liabilities with respect
to tax returns that remain subject to examination. During 2011, certain income tax returns will no
longer be subject to examination due to a lapse in the applicable statute of limitations. As a
result, we anticipate that the amount of unrecognized tax benefits attributable to transfer pricing
methodology will decrease by approximately $6.8 million through December 31, 2011.
We file income tax returns in the U.S. federal jurisdiction, various state jurisdictions and
various foreign jurisdictions. Tax years that remain subject to examination by these jurisdictions
include years 2002 to 2009. We are currently under audit in several of these jurisdictions,
including an audit by the Internal Revenue Service for the year 2008. We do not anticipate that any
adjustments resulting from the tax audits will have a material impact on our consolidated results
of operations, financial position and cash flows.
The Brazilian tax authorities have audited our income tax returns for the years 2000, 2004 and
2005 and are currently auditing our income tax return for the year 2007. The tax auditors have
issued an assessment for tax year
79
2000 of approximately $1.5 million, including interest and
penalty. We have appealed the tax assessment and are awaiting the outcome of the appeal. In
December 2009, we received an assessment of approximately $26.0 million for the years 2004 and
2005, including interest and penalties. We contested the tax assessment in January 2010 and are
awaiting the outcome of the appeal. As required by GAAP, only the portion of the tax benefit that
has a greater than 50% likelihood of being realized upon settlement is to be recognized.
Consequently, we have accrued approximately $14.9 million of expense attributable to the portion of
the tax assessment we determined to be an uncertain tax position, of which approximately $3.5
million is interest related and approximately $4 million is penalty related. We do not anticipate
that any adjustments resulting from the tax audit of any of these years will have a material impact
on our consolidated results of operations, financial position and
cash flows.
The Mexican tax authorities have audited our income tax returns for the year 2004 and are
currently auditing our income tax returns for the year 2006. The tax auditors have issued
assessments for tax year 2004 of approximately $22.9 million, including interest and penalty. We
have appealed the tax assessments and are awaiting the outcome of the appeals. We do not anticipate
that any adjustments resulting from the tax audit of any of these years will have a material impact
on our consolidated results of operations, financial position and cash flows.
As of December 31, 2010, we had recorded a deferred tax asset of $34.8 million for the benefit
of NOL carryforwards related to our international operations. Approximately $14.8 million of this
deferred tax asset relates to NOL carryforwards that have an indefinite life. The remaining $20.0
million relates to NOL carryforwards of our Mexican entities. Unless utilized, the tax benefits of
these Mexican NOL carryforwards will expire between 2014 and 2020 as follows:
|
|
|
|
|
|
|
Tax Benefit of |
|
|
|
NOL |
|
|
|
Carryforwards |
|
Year Expiring |
|
(In millions) |
|
2014 |
|
$ |
1.2 |
|
2015 |
|
|
4.6 |
|
2016 |
|
|
7.8 |
|
2017 |
|
|
6.3 |
|
2018 |
|
|
|
|
2019 |
|
|
|
|
2020 |
|
|
0.1 |
|
|
|
|
|
Total |
|
$ |
20.0 |
|
|
|
|
|
As of December 31, 2010, a valuation allowance of $31.9 million has been recorded for our NOLs
as only $2.9 million of the deferred tax asset is more likely than not to be realized.
14. Employee Benefit Plans
Defined Contribution Plans
We maintain defined contribution retirement plans for our U.S., U.K. and third-country
national, or TCN, employees. The plan for our U.S. employees, or the 401k Plan, is designed to
qualify under Section 401(k) of the Internal Revenue Code of 1986, as amended, or the Code. Under
the 401k Plan, each participant may elect to defer taxation on a portion of his or her eligible
earnings, as defined by the 401k Plan, by directing his or her employer to withhold a percentage of
such earnings. A participating employee may also elect to make after-tax contributions to the 401k
Plan. During the years ended December 31, 2010, 2009 and 2008, we contributed 4%, 5% and 5%,
respectively, of participants defined compensation and in each year matched 100% of the first 6%
of each employees compensation contributed to the 401k Plan. Participants are fully vested
immediately upon enrollment in the 401k Plan. For the years ended December 31, 2010, 2009 and
2008, our provision for contributions was $23.8 million, $26.0 million and $23.8 million,
respectively.
The defined contribution retirement plan for our U.K. employees provides that we make annual
contributions in an amount equal to the employees contributions, generally up to a maximum of
5.25% of the employees defined compensation per year for employees working in the U.K. sector of
the North Sea and up to a maximum of 9% of the employees defined compensation per year for U.K.
nationals working in the Norwegian sector of the North Sea. Our provision for contributions was
$1.2 million, $1.4 million and $1.7 million for the years ended December 31, 2010, 2009 and 2008,
respectively.
80
The defined contribution retirement plan for our TCN employees, or International Savings Plan,
is similar to the 401k Plan. During the years ended December 31, 2010, 2009 and 2008, we
contributed 4%, 5% and 5%, respectively, of participants defined compensation and in each
year matched 100% of the first 6% of each employees
compensation contributed to the International Savings Plan. Our provision for contributions was $2.8 million, $2.5 million and $2.3 million for the
years ended December 31, 2010, 2009 and 2008, respectively.
Deferred Compensation and Supplemental Executive Retirement Plan
Our Amended and Restated Diamond Offshore Management Company Supplemental Executive Retirement
Plan, or Supplemental Plan, provides benefits to a select group of our management or other highly
compensated employees to compensate such employees for any portion of our base salary contribution
and/or matching contribution under the 401k Plan that could not be contributed to that plan because
of limitations within the Code. Our provision for contributions to the Supplemental Plan for the
years ended December 31, 2010, 2009 and 2008 was approximately $238,000, $241,000 and $222,000,
respectively.
15. Casualty Loss
In
September 2008, one of our jack-up rigs, the Ocean Tower, sustained significant damage
during a hurricane, which included the loss of its derrick, drill floor and drill floor equipment.
During 2008, we wrote off the approximately $2.6 million in net book value of the Ocean Towers
derrick, drill floor and drill floor equipment and accrued $3.7 million in estimated salvage costs
for the recovery of equipment from the ocean floor. The aggregate of these items is reflected in
Casualty loss in our Consolidated Statements of Operations for the year ended December 31, 2008.
We sold the Ocean Tower in 2009 and recognized a $6.7 million gain on disposition, net of
broker commission, which was reported as (Gain) on disposition of assets in our Consolidated
Statements of Operations for the year ended December 31, 2009.
16. 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:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
High-Specification Floaters |
|
$ |
1,414,697 |
|
|
$ |
1,380,771 |
|
|
$ |
1,322,125 |
|
Intermediate Semisubmersibles |
|
|
1,546,837 |
|
|
|
1,698,584 |
|
|
|
1,629,358 |
|
Jack-ups |
|
|
267,983 |
|
|
|
457,224 |
|
|
|
524,934 |
|
Other |
|
|
219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contract drilling revenues |
|
|
3,229,736 |
|
|
|
3,536,579 |
|
|
|
3,476,417 |
|
Revenues related to reimbursable expenses |
|
|
93,238 |
|
|
|
94,705 |
|
|
|
67,640 |
|
|
|
|
|
|
Total revenues |
|
$ |
3,322,974 |
|
|
$ |
3,631,284 |
|
|
$ |
3,544,057 |
|
|
|
|
|
|
81
Geographic Areas
Our drilling rigs are highly mobile and may be moved to other markets throughout the world in
response to market conditions or customer needs. At December 31, 2010, our drilling rigs were
located offshore thirteen countries in addition to the United States. Revenues by geographic area
are presented by attributing revenues to the individual country or areas where the services were
performed.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
United States |
|
$ |
635,545 |
|
|
$ |
1,232,940 |
|
|
$ |
1,443,200 |
|
International: |
|
|
|
|
|
|
|
|
|
|
|
|
South America |
|
|
1,308,641 |
|
|
|
716,448 |
|
|
|
583,876 |
|
Australia/Asia/Middle East |
|
|
641,372 |
|
|
|
717,658 |
|
|
|
557,138 |
|
Europe/Africa/Mediterranean |
|
|
601,122 |
|
|
|
641,180 |
|
|
|
634,033 |
|
Mexico |
|
|
136,294 |
|
|
|
323,058 |
|
|
|
325,810 |
|
|
|
|
|
|
|
|
|
2,687,429 |
|
|
|
2,398,344 |
|
|
|
2,100,857 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
$ |
3,322,974 |
|
|
$ |
3,631,284 |
|
|
$ |
3,544,057 |
|
|
|
|
|
|
An individual international country may, from time to time, comprise a material
percentage of our total contract drilling revenues from unaffiliated customers. For the years
ended December 31, 2010, 2009 and 2008, individual countries that comprised 5% or more of our total
contract drilling revenues from unaffiliated customers are listed below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
|
|
2010 |
|
2009 |
|
2008 |
Brazil |
|
|
36.8 |
% |
|
|
18.2 |
% |
|
|
13.0 |
% |
Australia |
|
|
10.0 |
% |
|
|
10.8 |
% |
|
|
9.6 |
% |
Mexico |
|
|
4.1 |
% |
|
|
8.9 |
% |
|
|
9.2 |
% |
United Kingdom |
|
|
5.6 |
% |
|
|
6.7 |
% |
|
|
8.3 |
% |
Angola |
|
|
6.1 |
% |
|
|
1.8 |
% |
|
|
|
|
The following table presents our long-lived tangible assets by geographic location as of
December 31, 2010, 2009 and 2008. A substantial portion of our assets is mobile, and therefore
asset locations at the end of the period are not necessarily indicative of the geographic
distribution of the earnings generated by such assets during the periods. In circumstances where
our drilling rigs were in transit at the end of a calendar year, they have been presented in the
tables below within the geographic area in which they are expected to operate.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
|
|
2010 |
|
2009 |
|
2008 |
|
|
(In thousands) |
Drilling and other property and equipment, net: |
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
638,529 |
|
|
$ |
2,176,993 |
|
|
$ |
1,739,938 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International: |
|
|
|
|
|
|
|
|
|
|
|
|
Australia/Asia/Middle East |
|
|
417,121 |
|
|
|
1,015,273 |
|
|
|
511,946 |
|
South America |
|
|
2,290,412 |
|
|
|
874,644 |
|
|
|
816,638 |
|
Europe/Africa/Mediterranean |
|
|
897,998 |
|
|
|
262,037 |
|
|
|
246,301 |
|
Mexico |
|
|
39,732 |
|
|
|
103,105 |
|
|
|
99,550 |
|
|
|
|
|
|
|
|
|
3,645,263 |
|
|
|
2,255,059 |
|
|
|
1,674,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
4,283,792 |
|
|
$ |
4,432,052 |
|
|
$ |
3,414,373 |
|
|
|
|
|
|
82
The following table presents countries where we had a material concentration of operating
assets as of December 31, 2010, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, |
|
|
2010 |
|
2009 |
|
2008 |
United States |
|
|
14.9 |
% |
|
|
49.1 |
% |
|
|
51.0 |
% |
Brazil |
|
|
52.7 |
% |
|
|
19.7 |
% |
|
|
18.8 |
% |
Singapore |
|
|
1.9 |
% |
|
|
11.5 |
% |
|
|
|
|
Republic of Congo |
|
|
9.3 |
% |
|
|
|
|
|
|
|
|
Egypt |
|
|
6.3 |
% |
|
|
0.9 |
% |
|
|
1.2 |
% |
Malaysia |
|
|
0.2 |
% |
|
|
4.0 |
% |
|
|
9.8 |
% |
Argentina |
|
|
|
|
|
|
|
|
|
|
5.1 |
% |
As of December 31, 2010, 2009 and 2008, no other countries had more than a 5%
concentration of our operating assets.
Major Customers
Our customer base includes major and independent oil and gas companies and government-owned
oil companies. Revenues from our major customers for the years ended December 31, 2010, 2009 and
2008 that contributed more than 10% of our total revenues are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended December 31, |
Customer |
|
2010 |
|
2009 |
|
2008 |
Petróleo Brasileiro S.A. |
|
|
23.7 |
% |
|
|
15.0 |
% |
|
|
13.1 |
% |
OGX Petróleo e Gás Ltda. |
|
|
14.1 |
% |
|
|
1.4 |
% |
|
|
|
|
83
17. Unaudited Quarterly Financial Data
Unaudited summarized financial data by quarter for the years ended December 31, 2010 and 2009
is shown below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
Quarter |
|
Quarter |
|
Quarter |
|
Quarter |
|
|
(In thousands, except per share data) |
2010 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
859,681 |
|
|
$ |
822,603 |
|
|
$ |
799,724 |
|
|
$ |
840,966 |
|
Operating income (a) |
|
|
426,677 |
|
|
|
345,807 |
|
|
|
317,180 |
|
|
|
335,710 |
|
Income before income tax expense |
|
|
406,012 |
|
|
|
320,926 |
|
|
|
298,566 |
|
|
|
310,512 |
|
Net income (b) |
|
|
290,853 |
|
|
|
224,393 |
|
|
|
198,524 |
|
|
|
241,687 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.09 |
|
|
$ |
1.61 |
|
|
$ |
1.43 |
|
|
$ |
1.74 |
|
Diluted |
|
$ |
2.09 |
|
|
$ |
1.61 |
|
|
$ |
1.43 |
|
|
$ |
1.74 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues |
|
$ |
885,720 |
|
|
$ |
946,407 |
|
|
$ |
908,375 |
|
|
$ |
890,782 |
|
Operating income (c) |
|
|
456,936 |
|
|
|
517,619 |
|
|
|
479,460 |
|
|
|
449,198 |
|
Income before income tax expense |
|
|
453,337 |
|
|
|
520,838 |
|
|
|
475,285 |
|
|
|
418,971 |
|
Net income (d) |
|
|
348,581 |
|
|
|
387,440 |
|
|
|
364,134 |
|
|
|
276,064 |
|
Net income per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
2.51 |
|
|
$ |
2.79 |
|
|
$ |
2.62 |
|
|
$ |
1.99 |
|
Diluted |
|
$ |
2.51 |
|
|
$ |
2.79 |
|
|
$ |
2.62 |
|
|
$ |
1.98 |
|
|
|
|
(a) |
|
Results for the fourth quarter of 2010 include a $3.9 million recovery of bad
debt reserves recorded in previous years. |
|
(b) |
|
Results for the fourth quarter of 2010 reflect a reduction in income tax
expense, partially attributable to recording the full year tax effect of the Tax
Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010 that was
passed in mid-December 2010. |
|
(c) |
|
In December 2009, we recorded a $10.7 million provision for bad debts to
reserve a portion of the uncollected balance of receivables related to our operations
in Egypt and recovered $0.9 million associated with the reserve for bad debts
recorded in 2008. See Note 2. |
|
|
|
In addition, our results for the fourth quarter of 2009 include a $6.7 million gain on
the sale of the Ocean Tower, which was presented as Assets held for sale in our
Consolidated Balance Sheets at December 31, 2008. See Note 15. |
|
(d) |
|
Results for the fourth quarter of 2009 reflect increased tax expense that
arose from (i) a change in mix of domestic and international earnings during the year
from that which was previously expected, (ii) impact of foreign exchange differences
on foreign tax credits and (iii) an assessment from the Brazilian tax authorities for
the years 2004 and 2005. See Note 13. |
18. Subsequent Event
In January 2011, we entered into a turnkey contract with Hyundai for the construction of a
second dynamically positioned, ultra-deepwater drillship with delivery scheduled for the fourth quarter of 2013. The total
cost, including commissioning, spares and project management, is expected to be approximately
$590.0 million.
84
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Not applicable.
Item 9A. Controls and Procedures
Disclosure 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 December 31, 2010.
Based on their participation in that evaluation, our CEO and CFO concluded that our disclosure
controls and procedures were effective as of December 31, 2010.
Internal Control Over Financial Reporting
Managements Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over
financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for Diamond Offshore
Drilling, Inc. Our internal control system was designed to provide reasonable assurance to our
management and Board of Directors regarding the preparation and fair presentation of published
financial statements.
There are inherent limitations to the effectiveness of any control system, however well
designed, including the possibility of human error and the possible circumvention or overriding of
controls. Further, the design of a control system must reflect the fact that there are resource
constraints, and the benefits of controls must be considered relative to their costs. Management
must make judgments with respect to the relative cost and expected benefits of any specific control
measure. The design of a control system also is based in part upon assumptions and judgments made
by management about the likelihood of future events, and there can be no assurance that a control
will be effective under all potential future conditions. As a result, even an effective system of
internal controls can provide no more than reasonable assurance with respect to the fair
presentation of financial statements and the processes under which they were prepared.
Our management assessed the effectiveness of our internal control over financial reporting as
of December 31, 2010. In making this assessment, our management used the criteria set forth by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control
Integrated Framework. Based on managements assessment our management believes that, as of December
31, 2010, our internal control over financial reporting was effective based on those criteria to
provide reasonable assurance regarding the reliability of financial reporting and the preparation
of financial statements for external purposes in accordance with U.S. generally accepted accounting
principles.
Deloitte & Touche LLP, the registered public accounting firm that audited our financial
statements included in this Annual Report on Form 10-K, has issued an attestation report on the
effectiveness of our internal control over financial reporting. The attestation report of Deloitte
& Touche LLP is included at the beginning of Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting identified in
connection with the foregoing evaluation that occurred during our fourth fiscal quarter of 2010
that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
85
Item 9B. Other Information.
Not applicable.
PART III
Reference is made to the information responsive to Items 10, 11, 12, 13 and 14 of this Part
III contained in our definitive proxy statement for our 2011 Annual Meeting of Stockholders, which
is incorporated herein by reference.
Item 10. Directors, Executive Officers and Corporate Governance.
Item 11. Executive Compensation.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters.
Item 13. Certain Relationships and Related Transactions, and Director Independence.
Item 14. Principal Accountant Fees and Services.
PART IV
Item 15. Exhibits and Financial Statement Schedules.
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
|
|
|
|
|
|
|
Page |
|
(1) Financial Statements |
|
|
|
|
|
|
|
|
|
|
|
|
|
51 |
|
|
|
|
|
53 |
|
|
|
|
|
54 |
|
|
|
|
|
55 |
|
|
|
|
|
56 |
|
|
|
|
|
57 |
|
|
|
|
|
58 |
|
|
|
|
|
|
|
|
(2) Exhibit Index |
|
|
88 |
|
See the Exhibit Index for a list of those exhibits filed herewith, which Exhibit Index also
includes and identifies management contracts or compensatory plans or arrangements required to be
filed as exhibits to this Form 10-K by Item 601 of Regulation S-K.
86
SIGNATURES
|
|
Pursuant to the requirements of Section 13 or 15(d) 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, on February 25, 2011. |
|
|
|
|
|
|
DIAMOND OFFSHORE DRILLING, INC.
|
|
|
By: |
/s/ GARY T. KRENEK
|
|
|
|
Gary T. Krenek |
|
|
|
Senior Vice President and Chief Financial Officer |
|
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the registrant and in the capacities and on the
dates indicated.
|
|
|
|
|
Signature |
|
Title |
|
Date |
|
|
|
|
|
/s/ LAWRENCE R. DICKERSON*
|
|
President, Chief Executive Officer and
|
|
February 25, 2011 |
Lawrence R. Dickerson
|
|
Director (Principal Executive Officer) |
|
|
|
|
|
|
|
|
|
Senior Vice President and
|
|
February 25, 2011 |
Gary T. Krenek
|
|
Chief Financial Officer
(Principal Financial Officer) |
|
|
|
|
|
|
|
/s/ BETH G. GORDON*
Beth G. Gordon
|
|
Controller (Principal Accounting Officer)
|
|
February 25, 2011 |
|
|
|
|
|
/s/ JAMES S. TISCH*
James S. Tisch
|
|
Chairman of the Board
|
|
February 25, 2011 |
|
|
|
|
|
/s/ JOHN R. BOLTON*
John R. Bolton
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
/s/ CHARLES L. FABRIKANT*
Charles L. Fabrikant
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
/s/ PAUL G. GAFFNEY II*
Paul G. Gaffney II
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
/s/ EDWARD GREBOW*
Edward Grebow
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
/s/ HERBERT C. HOFMANN*
Herbert C. Hofmann
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
/s/ ARTHUR L. REBELL*
Arthur L. Rebell
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
/s/ RAYMOND S. TROUBH*
Raymond S. Troubh
|
|
Director
|
|
February 25, 2011 |
|
|
|
|
|
|
|
|
|
*By: |
/s/ WILLIAM C. LONG
|
|
|
|
William C. Long |
|
|
|
Attorney-in-fact |
|
|
87
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). |
|
|
|
4.1
|
|
Indenture, dated as of February 4, 1997, between Diamond Offshore Drilling, Inc. and
The Bank of New York Mellon (formerly known as The Bank of New York) (as successor to
The Chase Manhattan Bank), as Trustee (incorporated by reference to Exhibit 4.1 to
our Annual Report on Form 10-K for the fiscal year ended December 31, 2001) (SEC File
No. 1-13926). |
|
|
|
4.2
|
|
Fourth Supplemental Indenture, dated as of August 27, 2004, between Diamond Offshore
Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New
York) (as successor to JPMorgan Chase Bank), as Trustee (incorporated by reference to
Exhibit 4.2 to our Current Report on Form 8-K filed September 1, 2004) (SEC File No.
1-13926). |
|
|
|
4.3
|
|
Fifth Supplemental Indenture, dated as of June 14, 2005, between Diamond Offshore
Drilling, Inc. and The Bank of New York Mellon (formerly known as The Bank of New
York) (as successor to JPMorgan Chase Bank, National Association), as Trustee
(incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K filed
June 16, 2005) (SEC File No. 1-13926). |
|
|
|
4.4
|
|
Sixth Supplemental Indenture, dated as of May 4, 2009, between Diamond Offshore
Drilling, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference
to Exhibit 4.2 to our Current Report on Form 8-K filed May 4, 2009). |
|
|
|
4.5
|
|
Seventh Supplemental Indenture, dated as of October 8, 2009, between Diamond Offshore
Drilling, Inc. and The Bank of New York Mellon, as Trustee (incorporated by reference
to Exhibit 4.2 to our Current Report on Form 8-K filed October 8, 2009). |
|
|
|
10.1
|
|
Registration Rights Agreement (the Registration Rights Agreement) dated October 16,
1995 between Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to
Exhibit 10.1 to our Annual Report on Form 10-K for the fiscal year ended December 31,
2001) (SEC File No. 1-13926). |
|
|
|
10.2
|
|
Amendment to the Registration Rights Agreement, dated September 16, 1997, between
Loews and Diamond Offshore Drilling, Inc. (incorporated by reference to Exhibit 10.2
to our Annual Report on Form 10-K for the fiscal year ended December 31, 1997) (SEC
File No. 1-13926). |
|
|
|
10.3
|
|
Services Agreement, dated October 16, 1995, between Loews and Diamond Offshore
Drilling, Inc. (incorporated by reference to Exhibit 10.3 to our Annual Report on
Form 10-K for the fiscal year ended December 31, 2001) (SEC File No. 1-13926). |
|
|
|
10.4+
|
|
Amended and Restated Diamond Offshore Management Company Supplemental Executive
Retirement Plan effective as of January 1, 2007 (incorporated by reference to Exhibit
10.4 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2006). |
|
|
|
10.5+
|
|
Diamond Offshore Management Bonus Program, as amended and restated, and dated as of
December 31, 1997 (incorporated by reference to Exhibit 10.6 to our Annual Report on
Form 10-K for the fiscal year ended December 31, 1997) (SEC File No. 1-13926). |
|
|
|
10.6+
|
|
Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan,
as amended (incorporated by reference to Exhibit 10.6 to our Annual Report on Form
10-K for the fiscal year ended December 31, 2007). |
|
|
|
10.7+
|
|
Form of Stock Option Certificate for grants to executive officers, other employees
and consultants pursuant to the Second Amended and Restated Diamond Offshore
Drilling, Inc. 2000 Stock Option Plan |
88
|
|
|
Exhibit No. |
|
Description |
|
|
(incorporated by reference to Exhibit 10.1 to
our Current Report on Form 8-K filed October 1, 2004) (SEC File No. 1-13926). |
|
|
|
10.8+
|
|
Form of Stock Option Certificate for grants to non-employee directors pursuant to the
Second Amended and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan
(incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed
October 1, 2004) (SEC File No. 1-13926). |
|
|
|
10.9+
|
|
Diamond Offshore Drilling, Inc. Incentive Compensation Plan for Executive Officers
(amended and restated as of December 18, 2009) (incorporated by reference to Exhibit
10.9 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2009). |
|
|
|
10.10+
|
|
Form of Award Certificate for stock appreciation right grants to the Companys
executive officers, other employees and consultants pursuant to the Second Amended
and Restated Diamond Offshore Drilling, Inc. 2000 Stock Option Plan (incorporated by
reference to Exhibit 10.1 to our Current Report on Form 8-K filed April 28, 2006). |
|
|
|
10.11+
|
|
Form of Award Certificate for stock appreciation right grants to non-employee
directors pursuant to the Second Amended and Restated Diamond Offshore Drilling, Inc.
2000 Stock Option Plan (incorporated by reference to Exhibit 10.1 to our Quarterly
Report on Form 10-Q for the quarterly period ended March 31, 2007). |
|
|
|
10.12
|
|
5-Year Revolving Credit Agreement, dated as of November 2, 2006, among Diamond
Offshore Drilling, Inc., JPMorgan Chase Bank, N.A., as administrative agent, The Bank
of Tokyo-Mitsubishi UFJ, Ltd. Houston Agency, Fortis Capital Corp., HSBC Bank USA,
National Association, Wells Fargo Bank, N.A. and Bayerische Hypo-Und Vereinsbank AG,
Munich Branch, as co-syndication agents, and the lenders named therein (incorporated
by reference to Exhibit 10.1 to our Current Report on Form 8-K filed November 3,
2006). |
|
|
|
10.13+
|
|
Employment Agreement between Diamond Offshore Management Company and Lawrence R.
Dickerson dated as of December 15, 2006 (incorporated by reference to Exhibit 10.1 to
our Current Report on Form 8-K filed December 21, 2006). |
|
|
|
10.14+
|
|
Employment Agreement between Diamond Offshore Management Company and Gary T. Krenek
dated as of December 15, 2006 (incorporated by reference to Exhibit 10.2 to our
Current Report on Form 8-K filed December 21, 2006). |
|
|
|
10.15+
|
|
Employment Agreement between Diamond Offshore Management Company and John M. Vecchio
dated as of December 15, 2006 (incorporated by reference to Exhibit 10.15 to our
Annual Report on Form 10-K for the fiscal year ended December 31, 2006). |
|
|
|
10.16+
|
|
Employment Agreement between Diamond Offshore Management Company and William C. Long
dated as of December 15, 2006 (incorporated by reference to Exhibit 10.16 to our
Annual Report on Form 10-K for the fiscal year ended December 31, 2006). |
|
|
|
10.17+
|
|
Employment Agreement between Diamond Offshore Management Company and Lyndol L. Dew
dated as of December 15, 2006 (incorporated by reference to Exhibit 10.17 to our
Annual Report on Form 10-K for the fiscal year ended December 31, 2006). |
|
|
|
10.18+
|
|
Employment Agreement between Diamond Offshore Management Company and Beth G. Gordon
dated as of January 3, 2007 (incorporated by reference to Exhibit 10.19 to our Annual
Report on Form 10-K for the fiscal year ended December 31, 2006). |
|
|
|
10.19+
|
|
Amendment to Employment Agreement, dated June 16, 2008, between Diamond Offshore
Management Company and Lawrence R. Dickerson (incorporated by reference to Exhibit
10.1 to our Quarterly Report on Form 10-Q for the quarterly period ended September
30, 2008). |
|
|
|
12.1*
|
|
Statement re Computation of Ratios. |
|
|
|
21.1*
|
|
List of Subsidiaries of Diamond Offshore Drilling, Inc. |
89
|
|
|
Exhibit No. |
|
Description |
23.1*
|
|
Consent of Deloitte & Touche LLP. |
|
|
|
24.1*
|
|
Powers of Attorney. |
|
|
|
31.1*
|
|
Rule 13a-14(a) Certification of the Chief Executive Officer. |
|
|
|
31.2*
|
|
Rule 13a-14(a) Certification of the Chief Financial Officer. |
|
|
|
32.1*
|
|
Section 1350 Certification of the Chief Executive Officer and Chief Financial Officer. |
|
|
|
101.INS**
|
|
XBRL Instance Document. |
|
|
|
101.SCH**
|
|
XBRL Taxonomy Extension Schema Document. |
|
|
|
101.CAL**
|
|
XBRL Taxonomy Calculation Linkbase Document. |
|
|
|
101.LAB**
|
|
XBRL Taxonomy Label Linkbase Document. |
|
|
|
101.PRE**
|
|
XBRL Presentation Linkbase Document. |
|
|
|
101.DEF**
|
|
XBRL Taxonomy Extension Definition. |
|
|
|
* |
|
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. |
|
+ |
|
Management contracts or compensatory plans or arrangements. |
90