PART
1.
As used
in this Annual Report, unless the context otherwise requires, references to
"Seadrill Limited," the "Company," "we," "us," "Group," "our" and words of
similar import refer to Seadrill Limited, its subsidiaries and its other
consolidated entities. Unless otherwise indicated, all references to "USD",
"US$" and "$" in this report are to, and amounts are represented in, U.S.
Dollars.
ITEM
1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
Not
applicable.
ITEM
2. OFFER STATISTICS AND EXPECTED TIMETABLE
Not
applicable.
ITEM
3. KEY INFORMATION
A.
SELECTED FINANCIAL DATA
The
selected statement of operations and cash flow statement data of the Company
with respect to the fiscal years ended December 31, 2009, 2008 and 2007 and the
selected balance sheet data of the Company with respect to the fiscal years
ended December 31, 2009 and 2008 have been derived from the Company's
Consolidated Financial Statements included in Item 18 of this annual report,
prepared in accordance with accounting principles generally accepted in the
United States, or U.S. GAAP.
The
selected statement of operations and cash flow statement data for the fiscal
year ended December 31, 2006 and the period from May 10, 2005 (date of
incorporation) to December 31, 2005 and the selected balance sheet data with
respect to the fiscal years ended December 31, 2007 and 2006 and the period from
May 10, 2005 (date of incorporation) to December 31, 2005 have been derived from
audited consolidated financial statements of the Company not included
herein.
The
following table should be read in conjunction with Item 5. "Operating and
Financial Review and Prospects" and the Company's Consolidated Financial
Statements and Notes thereto, which are included herein. The Company's accounts
are maintained in U.S. Dollars. We refer you to the notes to our consolidated
financial statements for a discussion of the basis on which our consolidated
financial statements are presented.
|
|
Year
ended December 31,
|
|
|
Period
from
May
10, 2005
(inception)
to
December
31,
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
(in
millions of U.S. dollars except common share and per share
data)
|
Statement
of Operations Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
operating revenues
|
|
|
3,254
|
|
|
|
2,106
|
|
|
|
1,552
|
|
|
|
1,155
|
|
|
|
27
|
|
Net
operating income
|
|
|
1,372
|
|
|
|
649
|
|
|
|
489
|
|
|
|
226
|
|
|
|
(15
|
)
|
Net
income (loss)
|
|
|
1,353
|
|
|
|
(123
|
)
|
|
|
515
|
|
|
|
245
|
|
|
|
(8
|
)
|
Earnings
per share, basic
|
|
$
|
3.16
|
|
|
$
|
(0.41
|
)
|
|
$
|
1.28
|
|
|
$
|
0.62
|
|
|
$
|
(0.04
|
)
|
Earnings
per share, diluted
|
|
$
|
3.00
|
|
|
$
|
(0.41
|
)
|
|
$
|
1.20
|
|
|
$
|
0.61
|
|
|
$
|
(0.04
|
)
|
Dividends
declared
|
|
|
199
|
|
|
|
688
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Dividends
declared per share
|
|
$
|
0.50
|
|
|
$
|
1.75
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period from
May
10, 2005
|
|
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
|
|
|
|
(in
millions of U.S. dollars except common share and per share
data)
|
Balance
Sheet Data (at end of period):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
|
460
|
|
|
|
376
|
|
|
|
997
|
|
|
|
210
|
|
|
|
52
|
|
Drilling
units
|
|
|
7,515
|
|
|
|
4,645
|
|
|
|
2,452
|
|
|
|
2,293
|
|
|
|
178
|
|
Newbuildings
|
|
|
1,431
|
|
|
|
3,661
|
|
|
|
3,340
|
|
|
|
2,025
|
|
|
|
439
|
|
Investment
in associated companies
|
|
|
321
|
|
|
|
240
|
|
|
|
176
|
|
|
|
238
|
|
|
|
153
|
|
Goodwill
|
|
|
1,596
|
|
|
|
1,547
|
|
|
|
1,510
|
|
|
|
1,256
|
|
|
|
-
|
|
Total
assets
|
|
|
13,831
|
|
|
|
12,305
|
|
|
|
9,293
|
|
|
|
6,743
|
|
|
|
1,149
|
|
Interest
bearing debt
(including
current portion)
|
|
|
7,396
|
|
|
|
7,437
|
|
|
|
4,601
|
|
|
|
2,815
|
|
|
|
314
|
|
Share
capital
|
|
|
798
|
|
|
|
797
|
|
|
|
797
|
|
|
|
766
|
|
|
|
458
|
|
Shareholders'
equity
|
|
|
4,813
|
|
|
|
3,222
|
|
|
|
3,728
|
|
|
|
2,927
|
|
|
|
802
|
|
Common
shares outstanding, in millions
|
|
|
399.0
|
|
|
|
398.4
|
|
|
|
398.5
|
|
|
|
383.1
|
|
|
|
229.1
|
|
Weighted
average common shares outstanding
|
|
|
398.5
|
|
|
|
398.3
|
|
|
|
392.8
|
|
|
|
352.1
|
|
|
|
190.9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Financial Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
cash provided by operating activities
|
|
|
1,452
|
|
|
|
401
|
|
|
|
486
|
|
|
|
174
|
|
|
|
11
|
|
Net
cash used in investing
Activities
|
|
|
(924
|
)
|
|
|
(3,847
|
)
|
|
|
(1,868
|
)
|
|
|
(3,180
|
)
|
|
|
(256
|
)
|
Net
cash provided by financing activities
|
|
|
(454
|
)
|
|
|
2,826
|
|
|
|
2,168
|
|
|
|
3,162
|
|
|
|
294
|
|
Capital
expenditure
|
|
|
(1,369
|
)
|
|
|
(2,768
|
)
|
|
|
(1,738
|
)
|
|
|
(1,196
|
)
|
|
|
(269
|
)
|
B.
CAPITALIZATION AND INDEBTEDNESS
Not
applicable.
C.
REASONS FOR THE OFFER AND USE OF PROCEEDS
Not
applicable.
D.
RISK FACTORS
Our
assets are primarily engaged in offshore contract drilling for the oil and gas
industry in benign and harsh environments worldwide, including ultra-deepwater
environments. The following summarizes some of the risks that may materially
affect our business, financial condition or results of operations. Unless
otherwise indicated in this Annual Report on Form 20-F for the year ended
December 31, 2009, all information concerning our business and our assets is as
at April 26, 2010.
Risks
Relating to Our Industry
Our
business, financial condition, results of operations and our ability to pay
dividends depend on the level of activity in the offshore oil and gas industry,
which is significantly affected by, among other things, volatile oil and gas
prices and may be materially and adversely affected by a decline
in offshore oil and gas exploration, development and
production.
The
offshore contract drilling industry is cyclical and volatile. Our business
depends on the level of activity in oil and gas exploration, as well as the
identification and development of oil and gas reserves and production in
offshore areas worldwide. The availability of quality drilling prospects,
exploration success, relative production costs, the stage of reservoir
development, political concerns and regulatory requirements all affect
customers' levels of activity and drilling campaigns. Accordingly, oil and gas
prices and market expectations of potential changes in these prices
significantly affect the level of activity and demand for our drilling units and
well services.
Oil and
gas prices are extremely volatile and are affected by numerous factors beyond
our control, including the following:
|
·
|
worldwide
demand for oil and gas;
|
|
·
|
the
cost of exploring for, developing, producing and delivering oil and
gas;
|
|
·
|
expectations
regarding future energy prices;
|
|
·
|
advances
in exploration and development
technology;
|
|
·
|
the
ability of the Organization of Petroleum Exporting Countries, or OPEC, to
set and maintain production levels and
pricing;
|
|
·
|
the
level of production in non-OPEC
countries;
|
|
·
|
government
laws and regulations, including environmental protection laws and
regulations;
|
|
·
|
local
and international political, economic and weather
conditions;
|
|
·
|
domestic
and foreign tax policies;
|
|
·
|
the
development and exploitation of alternative
fuels;
|
|
·
|
the
policies of various governments regarding exploration and development of
their oil and gas reserves;
|
|
·
|
political
and military conflicts in oil-producing and other countries;
and
|
|
·
|
volatility
in the exchange rate of the U.S Dollar against other
currencies.
|
An
over-supply of drilling units may lead to a reduction in dayrates, which are the
amounts earned per day per drilling unit, which may materially impact our
profitability.
In
response to improved market conditions in 2007 and 2008 which were associated
with historically high oil and gas prices, offshore drilling contractors ordered
new drilling units to meet their customers' then increasing demand for services.
In the past significant spikes in oil and gas prices have led to high levels of
rig construction orders. This is often followed by a period of sharp and sudden
declines in oil and gas prices and an oversupply of drilling units, which in
turn results in declines in utilization and dayrates, and an increase in the
number of idle drilling units without long-term contracts.
The worldwide fleet of
dynamically positioned deepwater drilling units currently consists of 65 units.
An additional 69 deepwater units are under construction or on order, which would
bring the expected total fleet to 134 units in 2013 when the last of the
currently ordered units are scheduled to be delivered. The strong growth in
deepwater units is due to the increased focus of oil companies on existing and
new deepwater regions for exploration and production, and the inability to
upgrade or modify the existing mid-water fleet to undertake deepwater drilling
campaigns. At the same time, there are 60 jack-up rigs currently under
construction, while the existing worldwide fleet of jack-up rigs contains 459
units with an average age of approximately 25 years. The growth in newbuilding
jack-up rigs is targeted at oil companies with the need for more advanced and
effective jack-up rigs. However, the majority of the newbuilding jack-up rigs
have been ordered on speculation, i.e. without fixed employment, and not all of
these rigs have secured contracts for future work. This could intensify price
competition as scheduled delivery dates come closer, resulting in a reduction in
dayrates. Lower utilization and dayrates could adversely affect our revenues and
profitability. Prolonged periods of low utilization and dayrates could also have
a material adverse effect on the value of our assets.
The
market value of our current drilling units and those we acquire in the future
may decrease, which could cause us to incur losses if we decide to sell them
following a decline in their market values.
If the
offshore contract drilling industry suffers adverse developments in the future,
the fair market value of our drilling units may decline. The fair market value
of the drilling units we currently own or may acquire in the future may increase
or decrease depending on a number of factors, including:
|
·
|
general
economic and market conditions affecting the offshore contract drilling
industry, including competition from other offshore contract drilling
companies;
|
|
·
|
types,
sizes and ages of drilling units;
|
|
·
|
supply
and demand for drilling units;
|
|
·
|
prevailing
level of drilling services contract
dayrates;
|
|
·
|
governmental
or other regulations; and
|
|
·
|
technological
advances.
|
If we
sell any drilling unit when drilling unit prices have fallen, the sale may be at
a loss. Such loss could materially and adversely affect our business prospects,
financial condition, liquidity, results of operations, and our ability to pay
dividends to our shareholders.
Consolidation
of suppliers may limit our ability to obtain supplies and services when we need
them, at an acceptable cost, or at all.
We rely
on a significant supply of consumables, spare parts and equipment to operate,
maintain, repair and upgrade our fleet of drilling rigs. During the last decade
the number of available suppliers has been reduced, resulting in fewer
alternatives for sourcing key supplies and services. In addition, certain key
equipment used in our business is protected by patents and other intellectual
property of our suppliers. This may limit our ability to obtain supplies and
services at an acceptable cost, at the times we need them, or at all. Cost
increases, delays or unavailability could negatively impact our future
operations and result in higher rig downtime due to delays in the repair and
maintenance of our fleet.
Our
international operations involve additional risks associated with operating
outside the U.S.
We
operate in various regions throughout the world which may expose us to political
and other uncertainties, including risks of:
|
·
|
terrorist
acts, war, civil disturbances and
piracy;
|
|
·
|
seizure,
nationalization or expropriation of property or
equipment;
|
|
·
|
labor
unrest and strikes;
|
|
·
|
foreign
and U.S. monetary policy and foreign currency fluctuations and
devaluations;
|
|
·
|
the
inability to repatriate income or
capital;
|
|
·
|
complications
associated with repairing and replacing equipment in remote
locations;
|
|
·
|
import-export
quotas, wage and price controls, imposition of trade barriers and other
forms of government regulation and economic conditions that are beyond our
control;
|
|
·
|
regulatory
or financial requirements to comply with foreign bureaucratic actions;
and
|
|
·
|
changing
taxation policies.
|
In
addition, international contract drilling operations are subject to the various
laws and regulations in countries in which we operate, including laws and
regulations relating to:
|
·
|
the
equipping and operation of drilling
units;
|
|
·
|
repatriation
of foreign earnings;
|
|
·
|
oil
and gas exploration and
development;
|
|
·
|
taxation
of offshore earnings and the earnings of expatriate
personnel;
|
|
·
|
customs
duties on the importation of drilling rigs and related
equipment;
|
|
·
|
requirements
for local registration or ownership of drilling rigs by nationals of the
country of operations in certain countries;
and
|
|
·
|
the
use and compensation of local employees and suppliers by foreign
contractors.
|
Some
foreign governments favor or effectively require (i) the awarding of drilling
contracts to local contractors or to drilling rigs owned by their own citizens,
(ii) the use of a local agent or (iii) 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, including initiatives by OPEC, may adversely affect our ability to
compete. Failure to comply with applicable laws and regulations, including those
relating to sanctions and export restrictions, may subject us to criminal
sanctions or civil remedies, including fines, denial of export privileges,
injunctions or seizures of assets.
We
may be subject to liability under environmental laws and regulations, which
could have a material adverse effect on our results of operations and financial
condition.
Our
operations are subject to regulations controlling the discharge of materials
into the environment, requiring removal and clean-up of materials that may harm
the environment or otherwise relating to the protection of the environment. For
example, as an operator of mobile drilling units offshore Brazil, the United
States and other countries, we may be liable for damages and costs incurred in
connection with spills of oil and other chemicals and substances related to our
operations, and we may also be subject to significant fines in connection with
spills. Laws and regulations protecting the environment have become more
stringent in recent years, and may in some cases impose strict liability,
rendering a person liable for environmental damage without regard to negligence.
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 application of these
requirements or the adoption of new requirements could have a material adverse
effect on our financial position, results of operations or cash flows. We have
generally been able to obtain some degree of contractual indemnification
pursuant to which our clients agree to protect, hold harmless and indemnify us
against liability for pollution, well and environmental damage; however, there
is no assurance that we can obtain such indemnities in all of our contracts or
that, in the event of extensive pollution and environmental damage, our clients
would have the financial capability to fulfill their contractual obligations to
us. Also, these indemnities may be held to be unenforceable in certain
jurisdictions, as a result of public policy or for other reasons.
Our
ability to operate our drilling units in the U.S. Gulf of Mexico could be
restricted by governmental regulation.
Hurricanes
Ivan, Katrina, Rita, and Ike have caused damage to a number of drilling units
unaffiliated to us in the U.S. Gulf of Mexico. In June 2009, the Minerals
Management Service, or MMS, of the U.S. Department of the Interior issued the
latest guidelines for jack-up drilling rig fitness requirements for the 2009
hurricane season. Also in June 2009, the MMS issued the latest guidelines for
tie-downs on any drilling units and permanent equipment and facilities attached
to an outer continental shelf production platform, and guidelines for moored
drilling rig fitness requirements for the 2009 hurricane season. These
guidelines continued requirements on the offshore oil and gas industry, in an
attempt to improve the stations that house the moored units and increase the
likelihood of survival of jack-up rigs and other offshore drilling units during
a hurricane. The guidelines also provided for enhanced information and data
requirements from oil and gas companies operating properties in the U.S. Gulf of
Mexico. We do not have any jack-up rigs or moored drilling units
operating in the U.S. Gulf of Mexico. However, we currently have operating in
the U.S. Gulf of Mexico one ultra-deepwater semi-submersible drilling rig that
is self propelled and equipped with thrusters and other machinery, which enable
the rig to move between drilling locations and remain in position while drilling
without the need for anchors. Nevertheless, it is possible that the MMS may
issue guidelines for future hurricane seasons and may take other steps which
could increase the cost of operations and implementation of such guidelines, or
reduce the area of operations for our ultra-deepwater drilling
unit.
Public
health threats could have an adverse effect on our operations and our financial
results.
Public
health threats, such as swine flu, bird flu, Severe Acute Respiratory Syndrome
and other highly communicable diseases, outbreaks of which have already occurred
in various parts of the world in which we operate, could adversely impact on our
operations, the operations of our customers and the global economy, including
the worldwide demand for oil and gas, and ultimately on the level of demand for
our services and could adversely affect our financial results.
We
may be subject to litigation that could have an adverse effect on
us.
We are
currently involved in various litigation matters, none of which we expect to
have a material adverse effect on us. We anticipate that we will be involved in
litigation matters from time to time in the future. The operating hazards
inherent in our business expose us to litigation, including personal injury
litigation, environmental litigation, contractual litigation with clients,
intellectual property litigation, tax or securities litigation, and maritime
lawsuits including the possible arrest of our drilling units. We
cannot predict with certainty the outcome or effect of any claim or other
litigation matter. Any future litigation may have an adverse effect on our
business, financial position, results of operations and our ability to pay
dividends, because of potential negative outcomes, the costs associated with
prosecuting or defending such lawsuits, and the diversion of management's
attention to these matters.
Fluctuations
in exchange rates and non-convertibility of currencies could result in losses to
us.
As a
result of our international operations, we are exposed to fluctuations in
foreign exchange rates due to revenues being received and operating expenses
paid in currencies other than U.S. Dollars. Accordingly, we may experience
currency exchange losses in situations where we have not fully hedged our
exposure to a foreign currency, or if revenues are received in currencies that
are not readily convertible. 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. A discussion of our policy
and exposure to exchange rate fluctuations is given in Item 11 "Quantitative and
Qualitative Disclosures about Market Risk".
Our business
involves numerous operating hazards
.
Our
operations are subject to hazards inherent in the drilling industry, such as
blowouts, reservoir damage, loss of production, loss of well control, lost or
stuck drill strings, equipment defects, punch throughs, craterings, fires,
explosions and pollution. Contract drilling and well servicing require the use
of heavy equipment and exposure to hazardous conditions, which may subject us to
liability claims by employees, customers and third parties. These hazards can
cause personal injury or loss of life, severe damage to or destruction of
property and equipment, pollution or environmental damage, claims by third
parties or customers and suspension of operations. Our offshore fleet is also
subject to hazards inherent in marine operations, either while on-site or during
mobilization, such as capsizing, sinking, grounding, collision, damage from
severe weather and marine life infestations. Operations may also be suspended
because of machinery breakdowns, abnormal drilling conditions, and failure of
subcontractors to perform or supply goods or services, or personnel shortages.
We customarily provide contract indemnity to our customers for claims that could
be asserted by us relating to damage to or loss of our equipment, including rigs
and claims that could be asserted by us or our employees relating to personal
injury or loss of life.
Damage to
the environment could also result from our operations, particularly through
spillage of fuel, lubricants or other chemicals and substances used in drilling
operations, or extensive uncontrolled fires. We may also be subject to property,
environmental and other damage claims by oil and gas companies. Our insurance
policies and contractual rights to indemnity may not adequately cover losses,
and we do not have insurance coverage or rights to indemnity for all risks.
Consistent with standard industry practice, our clients generally assume, and
indemnify us against, well control and subsurface risks under dayrate contracts.
These are risks associated with the loss of control of a well, such as blowout
or cratering, the cost to regain control of or re-drill the well and associated
pollution. However, there can be no assurance that these clients will be willing
or financially able to indemnify us against all these risks. We maintain
insurance coverage for property damage, occupational injury and illness, and
general and marine third-party liabilities. We have no insurance coverage for
named storms in the U.S. Gulf of Mexico and war perils worldwide. Furthermore,
pollution and environmental risks generally are not totally
insurable.
We
maintain a portion of deductibles for damage to our offshore drilling equipment
and third-party liabilities. With respect to hull and machinery we generally
maintain a deductible per occurrence up to $1.7 million. However, in the event
of a total loss or a constructive total loss of a drilling unit, such loss is
fully covered by our insurance with no deductible. For general and marine
third-party liabilities we generally maintain up to $250,000 deductible per
occurrence on personal injury liability for crew claims as well as non-crew
claims and per occurrence on third-party property damage.
If a
significant accident or other event occurs and is not fully covered by our
insurance or an enforceable or recoverable indemnity from a client, it could
adversely affect our consolidated statement of financial position, results of
operations or cash flows. The amount of our insurance may be less than the
related impact on enterprise value after a loss. Our insurance coverage will not
in all situations provide sufficient funds to protect us from all liabilities
that could result from our drilling operations. Our coverage includes annual
aggregate policy limits. As a result, we retain the risk through self-insurance
for any losses in excess of these limits. Any such lack of reimbursement may
cause us to incur substantial costs. In addition, we could decide to retain
substantially more risk through self-insurance in the future. Moreover, no
assurance can be made that we will be able to maintain adequate insurance in the
future at rates we consider reasonable or be able to obtain insurance against
certain risks.
As of
April 26, 2010, all of the drilling units that we owned or operated were covered
by existing insurance policies.
Technology
disputes involving our suppliers could impact our operations or increase our
costs.
The
majority of the intellectual property rights relating to our drilling rigs and
related equipment are owned by our suppliers. In the event that one of our
suppliers becomes involved in a dispute over infringement of intellectual
property rights relating to equipment owned by us, we may lose access to repair
services, replacement parts, or could be required to cease use of some
equipment. We could also be required to pay royalties for the use of equipment.
These consequences of technology disputes involving our suppliers could
adversely affect our financial results and operations. We have
provisions in most of our supply contracts to provide indemnity from the
supplier against intellectual property lawsuits. However, we cannot
be assured that our suppliers will be willing or financially able to honor their
indemnity obligations, or that the indemnities will fully protect us from the
adverse consequences of such technology disputes. We also have
provisions in some of our client contracts to require the client to share some
of these risks on a limited basis, but we cannot be assured that these
provisions will fully protect us from the adverse consequences of such
technology disputes.
We
may not be able to keep pace with the continual and rapid technological
developments that characterize the market for our services, and our failure to
do so may result in our loss of market share.
The
market for our services is characterized by continual and rapid technological
developments that have resulted in, and will likely continue to result in,
substantial improvements in equipment functions and performance. As a result,
our future success and profitability will be dependent in part upon our ability
to:
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improve
our existing services and related
equipment;
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address
the increasingly sophisticated needs of our customers;
and
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·
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anticipate
changes in technology and industry standards and respond to technological
developments on a timely basis.
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If we are
not successful in acquiring new equipment or upgrading our existing equipment on
a timely and cost-effective basis in response to technological developments or
changes in standards in our industry, we could lose market share. In addition,
current competitors or new market entrants may develop new technologies,
services or standards that could render some of our services or equipment
obsolete, which could have a material adverse effect on our
operations.
Risks
Relating to Our Company
The
amount of our debt could limit our liquidity and flexibility in obtaining
additional financing and in pursuing other business opportunities.
As of
December 31, 2009, we had $7.4 billion in principal amount of debt, representing
approximately 61% of our total capitalization. Our current indebtedness and
future indebtedness which we may incur could affect our future operations, as a
portion of our cash flow from operations will be dedicated to the payment of
interest and principal on such debt and will not be available for other
purposes. Covenants contained in our debt agreements require us to meet certain
financial tests, which may affect our flexibility in planning for, and reacting
to, changes in our business and may limit our ability to dispose of assets or
place restrictions on the use of proceeds from such dispositions, withstand
current or future economic or industry downturns and compete with others in our
industry for strategic opportunities, and our ability to obtain additional
financing for working capital, capital expenditures, acquisitions, general
corporate and other purposes may be limited. Our ability to meet our debt
service obligations and to fund planned expenditures, including construction
costs for our newbuilding projects, will be dependent upon our future
performance, which will be subject to general economic conditions, industry
cycles and financial, business and other factors affecting our operations, many
of which are beyond our control. Our future cash flows may be insufficient to
meet all of our debt obligations and contractual commitments, and any
insufficiency could negatively impact our business. To the extent that we are
unable to repay our indebtedness as it becomes due or at maturity, we may need
to refinance our debt, raise new debt, sell assets or repay the debt with the
proceeds from equity offerings. Additional indebtedness or equity financing may
not be available to us in the future for the refinancing or repayment of
existing indebtedness, and we may not be able to complete asset sales in a
timely manner sufficient to make such repayments.
If
we are unable to comply with the restrictions and the financial covenants in the
agreements governing our indebtedness, there could be a default under the terms
of these agreements, which could result in an acceleration of repayment of funds
that we have borrowed.
If we are
unable to comply with the restrictions and covenants in the agreements governing
our indebtedness or in current or future debt financing agreements, there could
be a default under the terms of those agreements. Our ability to comply with
these restrictions and covenants, including meeting financial ratios and tests,
is dependent on our future performance and may be affected by events beyond our
control. If a default occurs under these agreements, lenders could terminate
their commitments to lend or accelerate the outstanding loans and declare all
amounts borrowed due and payable. Borrowings under other debt instruments that
contain cross-acceleration or cross-default provisions may also be accelerated
and become due and payable. If any of these events occur, we cannot guarantee
that our assets will be sufficient to repay in full all of our outstanding
indebtedness, and we may be unable to find alternative financing. Even if we
could obtain alternative financing, that financing might not be on terms that
are favorable or acceptable.
We
rely heavily on a small number of customers.
Our
contract drilling business is subject to the risks associated with having a
limited number of customers for our services. As of December 31, 2009, our five
largest customers accounted for approximately 79% of our future contracted
revenues, or order backlog. Our results of operations could be materially
adversely affected if any of our major customers failed to compensate us for our
services, were to terminate our contracts with or without cause, failed to renew
its existing contracts or refused to award new contracts to us and we are unable
to enter into contracts with new customers at comparable dayrates.
Newbuilding projects and surveys are
subject to risks which could cause delays or cost overruns
.
Rig
construction projects are subject to risks of delay or cost overruns inherent in
any large construction project from numerous factors, including shortages of
equipment, materials or skilled labor, unscheduled delays in the delivery of
ordered materials and equipment or shipyard construction, failure of equipment
to meet quality and/or performance standards, financial or operating
difficulties experienced by equipment vendors or the shipyard, unanticipated
actual or purported change orders, inability to obtain required permits or
approvals, unanticipated cost increases between order and delivery, design or
engineering changes and work stoppages and other labor
disputes, adverse weather conditions or any other events of force
majeure. Significant cost overruns or delays could adversely affect our
financial position, results of operations and cash flows. Additionally, failure
to complete a project on time may result in the delay of revenue from that rig.
New drilling rigs may experience start-up difficulties following delivery or
other unexpected operational problems that could result in uncompensated
downtime, which also could adversely affect our financial position, results of
operations and cash flows or the cancellation or termination of drilling
contracts.
Some
of our offshore drilling contracts may be terminated early due to certain
events.
Some of
our customers have the right to terminate their drilling contracts upon the
payment of an early termination fee. However, such payments may not
fully compensate us for the loss of the contract. Under certain circumstances
our contracts may permit a customer to terminate their contract early without
the payment of any termination fee, as a result of non-performance, longer
periods of downtime or impaired performance caused by equipment or operational
issues, or sustained periods of downtime due to force majeure events. Many of
these events are beyond our control. During periods of challenging market
conditions, we may be subject to an increased risk of our clients seeking to
repudiate their contracts, including through claims of non-performance. Our
customers' ability to perform their obligations under their drilling contracts
with us may also be negatively impacted by the prevailing uncertainty
surrounding the development of the world economy and the credit markets. If our
customers cancel some of our contracts, and we are unable to secure new
contracts on a timely basis and on substantially similar terms, or if contracts
are suspended for an extended period of time or if a number of our contracts are
renegotiated, it could adversely affect our consolidated statement of financial
position, results of operations or cash flows.
Our
operating and maintenance costs will not necessarily fluctuate in proportion to
changes in operating revenues.
Our
operating and maintenance costs will not necessarily fluctuate in proportion to
changes in operating revenues. Operating revenues may fluctuate as a function of
changes in supply and demand for contract drilling services, which in turn
affect dayrates, and the operational performance of our fleet of drilling rigs.
However, our operating costs are generally related to the number of units in
operation and the cost level in each country or region where the units are
located. In addition, equipment maintenance costs fluctuate depending upon the
type of activity the unit is performing and the age and condition of the
equipment. In connection with new assignments, we might incur expenses relating
to preparation for operations under a new contract. The expenses may vary based
on the scope and length of such required preparations and the duration of the
firm contractual period over which such expenditures are amortized. In
situations where our rigs incur idle time between assignments, the opportunity
to reduce the size of our crews on those rigs is limited as the crews will be
engaged in preparing the rig for its next contract. In a situation where a rig
faces longer idle periods, reductions in costs may not be immediate as some of
the crew may be required to prepare drilling units for stacking and maintenance
in the stacking period. Should rigs be idle for a longer period, we will seek to
redeploy crew members, who are not required to maintain the rigs, to active rigs
to the extent possible. However, there can be no assurance that we will be
successful in reducing our costs.
The provisions of
the majority of our offshore rig contracts that are term contracts at
fixed
dayrates may not
permit us fully to recoup our costs in the event of a rise in our
expenses.
Most of
the units in our fleet have long-term contracts. The average contract length as
of December 31, 2009, is 36 months for our deepwater units, 25 months for our
tender rigs and ten months for our jack-up rigs, excluding the four jack-up rigs
under construction. The majority of these contracts have dayrates that are fixed
over the contract term. In order to mitigate the effects of inflation on
revenues from term contracts, most of our contracts include escalation
provisions. These provisions allow us to adjust the dayrates based on stipulated
costs increases including wages, insurance and maintenance cost. However,
because these escalations are normally performed on a semi-annual or annual
basis, the timing and amount awarded as a result of such adjustments may differ
from our actual cost increases, which could adversely affect our financial
performance. Shorter term contracts normally do not contain escalations
provisions.
We
may not be able to renew or obtain new and favorable contracts for drilling
units whose contracts are expiring or are terminated, which could adversely
affect our revenues and profitability.
We have
six contracts that expire in 2010, six contracts that expire in 2011 and seven
contracts that expire in 2012. Our ability to renew these contracts or obtain
new contracts will depend on the prevailing market conditions. In cases where we
are not able to obtain new contracts in direct continuation, or where new
contracts are entered into at dayrates substantially below the existing dayrates
or on terms less favorable compared to existing contracts terms, our revenues
and profitability could be adversely affected.
Our
future contracted revenue for our fleet of drilling units may not be ultimately
realized.
As of
December 31, 2009, the future contracted revenue for our fleet of drilling
units, or contract drilling backlog, was approximately $10.4 billion under firm
commitments. We may not be able to perform under these contracts due to events
beyond our control, and our customers may seek to cancel or renegotiate our
contracts for various reasons, including adverse conditions resulting in lower
dayrates. Our inability or the inability of our customers to perform under our
or their contractual obligations may have a material adverse effect on our
financial position, results of operations and cash flows.
Competition
within the oilfield services industry may adversely affect our ability to market
our services.
The
oilfield services industry is highly competitive and fragmented and includes
several large companies that compete in many of the markets we serve, as well as
numerous small companies that compete with us on a local basis. Our larger
competitors' greater resources could allow them to better withstand industry
downturns, compete more effectively on the basis of technology and geographic
scope and retain skilled personnel. We believe the principal competitive factors
in the market areas we serve are price, product and service quality,
availability of crews and equipment and technical proficiency. Our operations
may be adversely affected if our current competitors or new market entrants
introduce new products or services with better features, performance, prices or
other characteristics than our products and services, or expand into service
areas where we operate. Competitive pressures or other factors also may result
in significant price competition, particularly during industry downturns, which
could have a material adverse effect on our results of operations and financial
condition. In addition, competition among oilfield services and equipment
providers is affected by each provider's reputation for safety and
quality.
Uncertainty
relating to the development of the world economy may reduce demand for our
drilling services or result in contract delays or cancellations.
We depend
on our customers' willingness and ability to make operating and capital
expenditures to explore, develop and produce oil and gas, and to purchase
drilling and related equipment. Recent deterioration of the world economy has
caused a decline in oil and gas prices from previous high levels, which in turn
has caused a number of oil and gas producers to adjust future capital budgets.
Limitations on the availability of capital or higher costs of capital for
financing expenditures, or the desire to preserve liquidity, may cause these and
other customers to make additional reductions in future capital budgets and
outlays. Such adjustments could reduce demand for our products and services,
which could adversely affect our results of operations and cash flows. We cannot
assure you that our customers will increase their capital budgets in response to
the recent recovery in crude oil prices, which were approximately $83 per barrel
as of April 26, 2010, after hitting a low of approximately $40 per barrel in
late 2008 and early 2009.
Failure
to obtain or retain highly skilled personnel could adversely affect our
operations.
We
require highly skilled personnel to operate and provide technical services and
support for our business. Competition for skilled and other labor required for
our drilling operations has increased in recent years as the number of rigs
activated or added to worldwide fleets has increased. The recent drop in energy
prices and utilization rate has to some extent reduced the need for people
related to international jack-up rigs. For deepwater operations utilization
rates remain high and the number of deepwater units in operation is growing as a
result of the delivery of units ordered in the period 2005 to 2008. This is
expected to increase the demand for qualified personnel with deepwater
experience in particular. If this expansion continues and is coupled with
improved demand for drilling services in general, shortages of qualified
personnel could develop, creating upward pressure on wages and making it more
difficult to staff and service our rigs. Such developments could adversely
affect our financial results and cashflow.
Our
labor costs and the operating restrictions which apply to us could increase as a
result of collective bargaining negotiations and changes in labor laws and
regulations.
Some of
our employees are represented by collective bargaining agreements. The majority
of these employees work in Brazil, Nigeria, Norway and the U.K. In addition,
some of our contracted labor works under collective bargaining agreements. As
part of the legal obligations in some of these agreements, we are required to
contribute certain amounts to retirement funds and pension plans and have
restricted ability to dismiss employees. In addition, many of these represented
individuals are working under agreements that are subject to salary negotiation.
These negotiations could result in higher personnel costs, other increased costs
or increased operating restrictions that could adversely affect our financial
performance.
The
failure to consummate or integrate acquisitions of other businesses and assets
in a timely and cost-effective manner could have an adverse effect on our
financial condition and results of operations.
Acquisition
of assets or businesses that expand our drilling and well services operations is
an important component of our business strategy. We believe that acquisition
opportunities may arise from time to time, and any such acquisition could be
significant. Any acquisition could involve the payment by us of a substantial
amount of cash, the incurrence of a substantial amount of debt or the issuance
of a substantial amount of equity. Certain acquisition and investment
opportunities may not result in the consummation of a transaction. In
addition, we may not be able to obtain acceptable terms for the required
financing for any such acquisition or investment
that
arises. We cannot predict the effect, if any, that any announcement or
consummation of an acquisition would have on the trading price of our common
stock. Our future acquisitions present a number of risks, including the risk of
incorrect assumptions regarding the future results of acquired operations or
assets or expected cost reductions or other synergies expected to be realized as
a result of acquiring operations or assets, the risk of failing to successfully
and timely integrate the operations or management of any acquired businesses or
assets and the risk of diverting management's attention from existing operations
or other priorities. If we fail to consummate and integrate our acquisitions in
a timely and cost-effective manner, our financial condition and results of
operations will be adversely affected.
In
order to execute our growth strategy, we may require additional capital in the
future, which may not be available to us.
Our
business is capital intensive and, to the extent we do not generate sufficient
cash from operations, we may need to raise additional funds through public or
private debt or equity financings to execute our growth strategy and to fund
capital expenditures. Adequate sources of capital funding may not be available
when needed or may not be available on favorable terms. If we raise additional
funds by issuing additional equity securities, dilution to the holdings of
existing equity holders may result. If funding is insufficient at any time in
the future, we may be unable to fund maintenance requirements and acquisitions,
take advantage of business opportunities or respond to competitive pressures,
any of which could adversely impact our financial condition and results of
operations.
Interest
rate fluctuations could affect our profitability, earnings and cash
flow.
In order
to finance our growth we have incurred significant amounts of debt. With the
exception of our convertible bonds, the large majority of our debt
arrangements have floating interest rates. As such, significant movements in
interest rates could have an adverse effect on our profitability, earnings and
cash flow. In order to manage our exposure to interest rate fluctuations, we use
interest rate swaps to effectively fix some of our floating rate debt
obligations. The principal amount covered by interest rate swaps is evaluated
continuously and determined based on our debt level, our expectations regarding
future interest rates and our overall financial risk exposure. As of December
31, 2009, our total net floating rate debt amounted to $5.0 billion and we had
entered into interest rate swaps in order to effectively fix the interest rate
for a principal amount of $4.1billion.
A
change in tax laws of any country in which we operate could result in a higher
tax expense or a higher effective tax rate on our worldwide
earnings.
We
conduct our operations through various subsidiaries in countries throughout the
world. Tax laws and regulations are highly complex and subject to
interpretation. Consequently, we are subject to changing tax laws, treaties and
regulations in and between countries in which we operate, including treaties
between the United States and other nations. Our income tax expense is based
upon our interpretation of the tax laws in effect in various countries at the
time that the expense was incurred. A change in these tax laws, treaties or
regulations, including those in and involving the United States, or in the
interpretation thereof, or in the valuation of our deferred tax assets, which is
beyond our control could result in a materially higher tax expense or a higher
effective tax rate on our worldwide earnings.
A
loss of a major tax dispute or a successful tax challenge to our operating
structure, intercompany pricing policies or the taxable presence of our
subsidiaries in certain countries could result in a higher tax rate on our
worldwide earnings, which could result in a significant negative impact on our
earnings and cash flows from operations.
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 our operational structure, intercompany pricing policies or the
taxable presence of our subsidiaries in certain countries; or if the terms of
certain income tax treaties are interpreted in a manner that is adverse to our
structure; 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.
While
we believe that we are not currently a PFIC and do not anticipate becoming a
PFIC, United States tax authorities could treat us as a "passive foreign
investment company," which could have adverse United States federal income tax
consequences to United States holders.
A foreign
corporation will be treated as a "passive foreign investment company," or PFIC,
for United States federal income tax purposes if either (1) at least 75 percent
of its gross income for any taxable year consists of certain types of "passive
income" or (2) at least 50 percent of the average value of the corporation's
assets produce or are held for the production of those types of "passive
income." For purposes of these tests, "passive income" includes
dividends, interest, and gains from the sale or exchange of investment property
and rents and royalties other than rents and royalties which are received from
unrelated parties in connection with the active conduct of a trade or business
but does not include income derived from the performance of
services.
If
the IRS were to find that we are or have been a PFIC for any taxable year, our
United States shareholders will face adverse United States tax
consequences.
Under the
PFIC rules, unless those shareholders make an election available under the Code
(which election could itself have adverse consequences for such shareholders, as
discussed below under "Tax Considerations – United States Federal Income
Taxation of U.S. Holders"), such shareholders would be liable to pay United
States federal income tax at the then prevailing income tax rates on ordinary
income plus interest upon excess distributions and upon any gain from the
disposition of our common shares, as if the excess distribution or gain had been
recognized ratably over the shareholder's holding period of our common
shares. See "Tax Considerations— United States Federal Income
Taxation of U.S. Holders" for a more comprehensive discussion of the United
States federal income tax consequences to United States shareholders if we are
treated as a PFIC.
Risks
Relating to Our Common Shares
There
is no assurance that an active and liquid trading market for our common shares
will be sustained in the United States.
Our
common shares were listed on the NYSE on April 15, 2010 under the symbol "SDRL".
Our common shares have been listed on the Oslo Stock Exchange since November
2005, also under the symbol "SDRL". There is no assurance that an
active and liquid trading market for our common shares will be sustained in the
United States.
Our
common share price may be highly volatile.
The
market price of our common shares has historically fluctuated over a wide range
and may continue to fluctuate significantly in response to many factors, such as
actual or anticipated fluctuations in our operating results, changes in
financial estimates by securities analysts, economic and regulatory trends,
general market conditions, rumors and other factors, many of which are beyond
our control. Over the last year the stock market has experienced extreme price
and volume fluctuations. Such volatility could adversely affect the market price
of our common shares and impact a potential sale price if holders of our common
shares decide to sell their shares.
Because
we are a foreign corporation, you may not have the same rights that a
shareholder in a U.S. corporation may have.
We are a
Bermuda exempted company. Our Memorandum of Association and Bye-laws and The
Companies Act, 1981 of Bermuda, or the Companies Act, govern our affairs. The
Companies Act does not as clearly establish your rights and the fiduciary
responsibilities of our directors as do statutes and judicial precedent in some
U.S. jurisdictions. Therefore, it may be more difficult to protect your
interests as a shareholder in relation to the actions of management, directors
or controlling shareholders, than it would be for shareholders of U.S.
corporations. There is a statutory remedy under Section 111 of the Companies Act
which provides that a shareholder may seek redress in the courts as long as such
shareholder can establish that our affairs are being conducted, or have been
conducted, in a manner oppressive or prejudicial to the interests of some part
of the shareholders, including such shareholder.
We
are incorporated in Bermuda and it may not be possible for our investors to
enforce U.S. judgments against us.
We are
incorporated in Bermuda and substantially all of our assets are located outside
the U.S. In addition, all of our directors and all but one of our executive
officers are non-residents of the U.S., and all or a substantial portion of the
assets of these non-residents are located outside the U.S. As a result, it may
be difficult or impossible for U.S. investors to serve process within the U.S.
upon us or our directors and executive officers, or to enforce a judgment
against us for civil liabilities in U.S. courts. In addition, you should not
assume that courts in the countries in which we are incorporated or where our
assets are located (1) would enforce judgments of U.S. courts obtained in
actions against us based upon the civil liability provisions of applicable U.S.
federal and state securities laws or (2) would enforce, in original actions,
liabilities against us based on those laws.
We
are subject to certain anti-takeover provisions in our constitutional
documents.
Several
provisions of our bye-laws may have anti-takeover effects. These provisions are
intended to avoid costly takeover battles, lessen our vulnerability to a hostile
change of control and enhance the ability of our board of directors to maximize
shareholder value in connection with any unsolicited offer to acquire us.
However, these anti-takeover provisions could also discourage, delay or prevent
the merger, amalgamation or acquisition of our company by means of a tender
offer, a proxy contest or otherwise, that a shareholder may consider to be in
its best interest. For more detailed information reference is made to Item 10
"Additional Information" of this Annual Report.
We
depend on directors who are associated with affiliated companies which may
create conflicts of interest.
Our
principal shareholder Hemen Holding Ltd., which we refer to as Hemen, is
controlled by trusts established by John Fredriksen, our President and Chairman,
for the benefit of his immediate family. Hemen also has significant
shareholdings in two companies affiliated with us, Frontline Ltd. (NYSE: FRO),
or Frontline, and Ship Finance International Limited (NYSE: SFL), or Ship
Finance. In addition, Hemen owns approximately 6.6% of our
majority-owned subsidiary Seawell Limited, or Seawell. One of our
directors, Kate Blankenship is also a director of Frontline, Ship Finance and
Seawell and another of our directors, Kathrine Fredriksen, the daughter of
John
Fredriksen, is also a director of Frontline. Mr. Fredriksen, Mrs. Blankenship
and Ms. Fredriksen owe fiduciary duties to each of Seadrill, Frontline and Ship
Finance and may have conflicts of interest in matters involving or affecting us
and our customers. In addition they may have conflicts of interest when faced
with decisions that could have different implications for Frontline or Ship
Finance than they do for us. We cannot assure you that any of these conflicts of
interest will be resolved in our favor.
Investor
confidence may be adversely impacted if we are unable to comply with Section 404
of the Sarbanes-Oxley Act of 2002.
We will
become subject to Section 404 of the Sarbanes-Oxley Act of 2002, which will
require us to include in our annual report on Form 20-F our management's report
on, and assessment of, the effectiveness of our internal controls over financial
reporting. In addition, our independent registered public accounting firm will
be required to attest to and report on management's assessment of the
effectiveness of our internal controls over financial reporting, which
requirement we expect will first apply to our annual report on Form 20-F for the
year ended December 31, 2010. If we fail to maintain the adequacy of
our internal controls over financial reporting, we will not be in compliance
with all of the requirements imposed by Section 404. Any failure to comply with
Section 404 could result in an adverse perception of the Company in the
financial marketplace.
If
we enter into drilling contracts with countries or government-controlled
entities that are subject to restrictions imposed by the U.S. government, our
reputation and the market for our common stock could be adversely
affected.
From time
to time, we may enter into drilling contracts with countries or
government-controlled entities that are subject to sanctions and embargoes
imposed by the U.S. government and/or identified by the U.S. government as state
sponsors of terrorism. Although these sanctions and embargoes do not prevent us
from entering into drilling contracts with these countries or
government-controlled entities, potential investors could view such drilling
contracts negatively, which could adversely affect our reputation and the market
for our common stock. In addition, certain institutional investors may have
investment policies or restrictions that prevent them from holding securities of
companies that have contracts with countries identified by the U.S. government
as state sponsors of terrorism. The determination by these investors not to
invest in or to divest our common shares may adversely affect the price at which
our common shares trade. Investor perception of the value of our common stock
may be adversely affected by the consequences of war, the effects of terrorism,
civil unrest and governmental actions in these and surrounding
countries.
ITEM
4. INFORMATION ON THE COMPANY
A.
HISTORY AND DEVELOPMENT OF THE COMPANY
The
Company
We were
incorporated under the laws of Bermuda on May 10 ,2005, and our shares of common
stock have been listed on the Oslo Stock Exchange under the symbol "SDRL" since
November 2005. Our principal executive offices are located at Par-la-Ville
Place, 4th Floor, 14 Par-la-Ville Road, Hamilton, HM 08, Bermuda and our
telephone number is +1 (441) 295-6935.
We are an
offshore drilling contractor providing worldwide offshore drilling services to
the oil and gas industry. Our primary business is the ownership and operation of
jack-up rigs, tender rigs, semi-submersible rigs and drillships, which operate
in shallow, mid and deepwater areas as well as benign and harsh environments. A
description of our different types of drilling units is given in Item 4.B
"Business Overview". We operate through subsidiaries located
throughout the world, including in Bermuda, Norway, the Cayman Islands, the
British Virgin Islands, Cyprus, Nigeria, Liberia, Hungary, Singapore, Brazil,
Hong Kong, Panama, the United Kingdom, Denmark, Malaysia, Brunei and the United
States. We own and operate a fleet of 36 offshore drilling units,
including eight units under construction, which consist of 10 jack-up rigs, 10
semi-submersible rigs, four drillships and 12 tender rigs. The units under
construction consist of two semi-submersible rigs, one drillship, one tender rig
and four jack-up rigs, including one jack-up rig for which we have a purchase
option that we intend to exercise. Four of the above units were sold
to and leased back from wholly-owned subsidiaries of Ship Finance, a related
party, and these subsidiaries are fully consolidated in our financial statements
as variable interest entities, or VIEs, in which we hold the primary interest
(see Note 33 to the Consolidated Financial Statements). In addition we operate
five tender rigs in association with Varia Perdana Sdn Bhd, or Varia Perdana, a
Malaysian company in which we have a 49% ownership interest. We have a
contractual right not to take delivery of one of the four newbuilding jack-up
rigs currently under construction. If we exercise this right we will forfeit the
installment paid to date on the newbuilding.
We own a
73.8% interest in the well services company Seawell. Seawell
provides
services in
platform drilling,
facility engineering, modular rig, well intervention and oilfield technologies,
and drilling and well services and has approximately 2,600 employees
.
Seawell currently operates
on nearly 50 installations in the North Sea and has offices in Stavanger and
Bergen in Norway, Aberdeen and Newcastle in the United Kingdom, Houston in the
United States, Esbjerg in Denmark, Rio de Janeiro in Brazil and Kuala Lumpur in
Malaysia.
We also
hold investments in several other companies in our industry that we consider to
be strategic investments, including
- 9.4%
equity interest in Pride International Inc. (NYSE: PDE), or Pride, a United
States offshore drilling company,
- 23.6%
equity interest in SapuraCrest Bhd, or SapuraCrest, a Malaysian oil services
company, and
-
40.0% equity interest in Scorpion Offshore Limited, or Scorpion, a Bermuda
jack-up rig company. In April 2010 we acquired 1.3 million shares in
Scorpion, which increased our shareholding from 38.6% to 40.0%. This
acquisition triggered an obligation to make a mandatory cash offer for
Scorpion's remaining shares or reduce our shareholding below
40%. On April 12, 2010, we announced that we plan to make a
cash offer for the remaining shares in
Scorpion.
|
We
consider strategic investments to be investments in companies that own and/or
operate offshore drilling rigs with similar characteristics to our own fleet of
rigs and that provide us with additional exposure to market segments in which we
operate or a new market segment. Further, we view investments as
strategic that potentially advance the development of our Company in accordance
with our business strategy, particularly relating to consolidation in the
offshore drilling rig industry.
Development
of the Company
We were
established in May 2005 as a Bermuda company. On May 11, 2005 we entered into a
Purchase and Subscription Agreement with three affiliated companies: Greenwich
Holdings Limited, or Greenwich, Seatankers Management Co Limited, or Seatankers,
and Hemen. Pursuant to agreements we acquired an offshore drilling
fleet of three jack-up rigs and two floating production, storage and offloading
vessels, or FPSOs, from Greenwich for an aggregate consideration of $310
million, and contracts for the construction of two new jack-up rigs from
Seatankers for a total consideration of $67 million. In addition, Hemen
subscribed for 84,994,000 of our shares at a subscription price of $2.03 per
share and acquired all of Greenwich's and a part of Seatankers' claim for the
purchase price for the assets referred to above. Greenwich, Seatankers and Hemen
are controlled by trusts established by Mr. John Fredriksen, our President and
Chairman, for the benefit of his immediate family. As a result of the related
party nature of this transaction, the acquisition of these assets was accounted
for as a transfer of assets under common control and recorded by Seadrill at the
historical carrying values in the financial statements of Greenwich and
Seatankers.
Subsequent
to the above initial acquisitions, we have entered into further contracts for
newbuildings and acquired other companies engaged in offshore drilling and
related industries. As a result, our operations have expanded considerably and
we now have approximately 7,600 skilled employees and an active fleet of 28
units, consisting of six jack-up rigs, eight semi-submersible rigs, three
drillships and 11 tender rigs.
Acquisitions,
Disposals and Other Transactions
Acquisitions
and other transactions
In the
year ended December 31, 2007, we acquired the following drilling units and
entities involved in offshore drilling:
·
|
In
January 2007, we took delivery of the new jack-up rig
West Prospero
from
Keppel FELS Limited in Singapore for a total cost of $208 million
and subsequently
sold the unit to an affiliated company that is a subsidiary of Ship
Finance, and leased the rig back.
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·
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In
May 2007, we entered into an agreement with the Jurong Shipyard in
Singapore for the construction of a new semi-submersible rig,
West Orion,
which we
expect to be delivered in the second quarter of 2010 for a total cost of
$675 million.
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·
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In
June 2007, we entered into an agreement with Keppel FELS Limited in
Singapore for the construction of a new tender rig,
West Vencedor,
which we
expect to be delivered in the first quarter of 2010 for a total cost of
$201 million.
|
·
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In
July 2007, we entered into a contract with the Samsung Shipyard in South
Korea for the construction of a new drillship,
West Gemini
, which we
expect to be delivered in the second quarter of 2010 for a total cost of
$716 million.
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·
|
In
September 2007, we took delivery of the new jack-up rig
West Atlas
from Keppel
FELS Limited in Singapore for a total cost of $155 million
.
|
·
|
In
September 2007, we established Seawell as a company providing drilling and
well services. Our ownership interest in Seawell is currently
approximately 73.8%. Seawell has entered into an agreement with the
Norwegian Stock Broker Association, which provides an over-the-counter
("OTC") market for its shares.
|
In the
year ended December 31, 2008, we acquired the following drilling units and
entities involved in offshore drilling:
·
|
In
the first quarter of 2008, the new semi-submersible rig
West Phoenix
was
delivered from the Samsung Shipyard in South Korea and the new
semi-submersible rig
West Sirius
was
delivered from the Jurong Shipyard in Singapore, at total costs of $804
million and $561 million, respectively. Also in the first
quarter of 2008, the new jack-up rig
West Triton
was
delivered from the PPL Shipyard in Singapore at a total cost of $155
million.
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·
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In
January 2008, Seawell acquired Noble Corporation's North Sea platform
drilling division, a labor contract well services business, for an
aggregate purchase price of $54 million. This purchase included labor
contracts to service the drilling operations on 11 platforms in the UK
sector of the North Sea.
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·
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In
February 2008, we entered into a construction contract with Malaysia
Marine and Heavy Engineering Sdn Bnd for the construction of a new tender
rig
T12,
which we
expect to be delivered in the first quarter of 2010 for a total cost of
$123 million.
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·
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In
February 2008, Seawell entered into an agreement for the construction of a
new modular well service unit. The unit is expected to be delivered in
the second half 2010 and will be primarily marketed for operations on
platforms on the UK and Norwegian continental
shelves.
|
·
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In
March 2008, we acquired all of the outstanding shares in Peak Well
Solutions AS, a company which specializes in the production, manufacturing
and installation of equipment for drilling rigs, for the aggregate
purchase price of $85 million.
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·
|
In
April 2008, we announced that we had acquired beneficial ownership of
200,000 of the issued shares of Pride and had forward purchase contracts
for a further 16,300,000 shares, totaling 9.5% of the issued share
capital. Pride is one of the largest offshore drilling contractors listed
on the NYSE. The aggregate purchase price of the investment in Pride was
approximately $558 million. In August 2009, Pride spun off its
mat-supported jack-up rigs into a new company, Seahawk Drilling Inc, which
is listed on Nasdaq. In that connection we received a dividend in the form
of shares in Seahawk Drilling Inc, corresponding to a 9.5% equity interest
which we currently hold.
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·
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In
April 2008, we acquired 8,100,000 shares of Scorpion Offshore Limited, or
Scorpion, at a price of NOK80 per share, which increased our shareholding
in Scorpion to 36% of Scorpion's outstanding shares, which is above the
33.3% threshold for making a mandatory tender offer for the remaining
shares under the rules of the Oslo Stock Exchange. We conducted the
mandatory tender offer at the offering price of NOK80 per share, which
offer expired in June 2008. As a result of the tender offer, we registered
acceptances for a further 1.1% of Scorpion's shares. As of January 20,
2010, we held a 39.6% equity interest in Scorpion, for which we paid an
aggregate amount of $343 million. Scorpion is a drilling contractor listed
on the Oslo Stock Exchange, with six recently completed newbuilding
jack-up rigs and one additional newbuilding jack-up rig under
construction. Under the Oslo Stock Exchange's mandatory offer rules, if we
increase our equity interest in Scorpion to 40% or more, we will be
required to make another tender offer for Scorpion's shares. Currently, we
do not expect to trigger any further mandatory offerings or compulsory
acquisitions. Please see "
Subsequent Events
" and
"
Summary of Oslo Stock
Exchange Mandatory Offer Rules'
below:
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·
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In
May 2008, Seawell acquired Tecwel AS, a company which provides logging
services to the oil industry worldwide, for an aggregate purchase price of
$34 million.
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In
June 2008, we entered into agreements with Keppel FELS Limited in
Singapore and the PPL Shipyard in Singapore for the construction of two
new jack-up rigs each, all of which are scheduled for delivery in the
second half of 2010. In January 2009 the terms of the
agreements with the PPL Shipyard and Keppel FELS Limited were amended to
include the option on our part not to take delivery of the second rig
scheduled for delivery from each yard, while the PPL Shipyard had the
option to terminate the construction contract for the second rig scheduled
for delivery by them. In October 2009, the PPL Shipyard exercised its
option to terminate the construction of one rig. The total cost of the
three rigs currently remaining to be delivered is $658
million.
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·
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In
June 2008, we entered into agreement with Keppel FELS Limited in Singapore
for the construction of one new tender rig,
West Berani III,
with
delivery expected in the first quarter of 2011 at a total cost of $119
million.
Also in June
2008, we entered into agreement with the Jurong Shipyard in Singapore for
the construction of one new semi-submersible drilling rig,
West Capricorn,
with
delivery expected in fourth quarters of 2011 at a total cost of $771
million.
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In
the second quarter of 2008, we took delivery of the new tender rig
T11
from Malaysia
Marine and Heavy Engineering Sdn Bnd at a total cost of $96 million, and
the new jack-up rig
West
Ariel
from Keppel FELS Limited in Singapore at a total cost of $177
million.
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In
September 2008, following a series of transactions beginning in 2006, we
acquired 22.7% of the total outstanding shares of SapuraCrest for a total
purchase price of $124 million. SapuraCrest owns 51% of each of Varia
Perdana and Tioman.
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In
the third quarter of 2008, we took delivery of the new drillship
West Polaris
from
Samsung Heavy Industries in South Korea for a total cost of $695 million,
and sold the unit to a subsidiary of Ship Finance, an
affiliated company, and leased the rig
back.
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In
the fourth quarter of 2008, we took delivery of the new semi-submersible
rig
West Hercules
from the DSME Shipyard in South Korea and the new semi-submersible rig
West Taurus
from
the Jurong Shipyard in Singapore, at total costs of $630 million and $531
million, respectively. These two rigs were sold to Ship Finance, an
affiliated company, and leased back. Also in the fourth quarter of 2008,
we took delivery of the new drillship
West Capella
from
Samsung Heavy Industries in South Korea at a total cost of $640
million.
|
In
the year ended December 31, 2009 we acquired the following drilling units and
investments in entities involved in offshore drilling:
·
|
In
the first quarter of 2009, we took delivery of the new semi-submersible
rig
West Aquarius
from the DSME Shipyard in South Korea and the new semi-submersible rig
West Eminence
from the Samsung Shipyard in South Korea, at total costs of $630 million
and $707 million, respectively
.
|
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In
March 2009, we acquired an 81% interest in a bond issued by Petromena AS
in the amount of NOK2.00 billion, at a cost of $183 million. The bond was
secured by construction contracts for two new deepwater rigs scheduled for
delivery later in 2009. Both rigs have subsequently been sold and as at
December 31, 2009, we have received a partial repayment of the bond
amounting to $101 million, including premium and accrued interest. Based
on the achieved sales price of the rigs and the priority of the bonds, we
expect to receive payments that equal 100% of the principal bond amount
plus a 7% early redemption fee and accrued interests including penalty
interests.
|
The total
cost shown for the above drilling units consists of the accumulated historic
cost paid to the shipyards, including amounts paid by entities prior to their
acquisition by us. The cost shown includes capitalized interest and other
ancillary costs.
Disposals
In
February 2007, we sold our two FPSOs
Crystal Ocean
and
Crystal Sea
for $90 million
and $80 million, respectively, recording gains totaling $124
million.
In July
2007, we entered into an agreement to sell the jack-up rig
West Titania
for a total
consideration of $134 million. The jack-up rig was delivered to its new owner in
the second quarter of 2008 and a gain on sale of $80 million was
recorded.
In
October 2007, we entered into an agreement to sell our entire holding of shares
in Apexindo to third parties for a net consideration of approximately $220
million. The gain from the disposal was recorded in the first quarter of 2008
and amounted to approximately $150 million.
In July
2009, we exercised our option to repurchase the jack-up rig
West Ceres
from Rig Finance
Ltd., a subsidiary of Ship Finance, an affiliated party, at the option price of
$135.5 million. In July 2009, we sold the jack-up rig
West Ceres
to a third party
for $175 million, recording a gain on sale of $21 million.
On
November 30, 2009 our jack-up rig
West Atlas
was confirmed a
constructive total loss following the damage caused by a blow-out and later fire
on the Montara production platform in Australia where the rig was working for
PTTEPA. The compensation from our insurers amounting to $200 million was
received in December 2009. We have a contractual obligation to PTTEPA for
removing the
West Atlas
wreck from the Montara field. Our insurance coverage provides for reimbursement
of the costs related to such removal operations which are expected to be
completed during 2010.
Subsequent
Events
·
|
In
the first quarter of 2010 we took delivery of the new tender rigs
West Vencedor
and
T12
from the Keppel
FELS shipyard in Singapore and Malaysia Marine and Heavy Engineering Sdn
Bnd, at total costs of $209 million and $123 million,
respectively.
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·
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In
April 2010 we announced that we have acquired a purchase option from the
Jurong shipyard in Singapore for a high specification, harsh environment
jack-up rig of the CJ70 design. We have announced our intention to
exercise this option and the rig is expected to be delivered in the first
quarter of 2011 at an acquisition cost of $356 million, excluding
capitalized interest and ancillary
costs.
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In
April 2010 we took delivery of the new semi-submersible rig
West Orion
from the
Jurong shipyard in Singapore. The rig will reported under newbuildings
until it commences operations in Brazil in July
2010.
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·
|
In
April 2010, Seadrill Limited successfully completed a private placement of
a total of 12.5 million shares, representing 3.1% of the issued capital,
to a price of NOK151.50 per share. Gross proceeds amounted to
NOK1,894 million (approximately US$322
million).
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·
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In
April 2010 we acquired 1.3 million shares in Scorpion at a price of
NOK36.00 per share, which increased our shareholding from 38.6% to 40.0%.
The acquisition triggered an obligation on us to make a mandatory cash
offer for Scorpion's remaining shares or to reduce our shareholding below
40%. We have announced that we will make a mandatory cash offer for the
remaining shares in Scorpion. Please see "
Summary of Oslo Stock Exchange
Mandatory Offer Rules
"
below:
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·
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On
April 30, 2010, the Company received a partial payment of the Petromena
bond amounting to $165 million.
|
Summary
of Oslo Stock Exchange Mandatory Offer Rules
|
·
|
Generally,
under the rules of the Oslo Stock Exchange, a shareholder who acts in its
own name or in concert with others, and who acquires shares representing
more than 1/3 of the votes of an Oslo Stock Exchange listed company is
obligated to make an offer for the Company's remaining shares. The
obligation to make a mandatory offer is triggered again if the shareholder
subsequent to the initial mandatory offer acquires further shares in the
Company and through such acquisition becomes the owner of shares
representing either 40% or more or 50% or more of the votes in the
Company.
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·
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Before
January 1 2008 the threshold of ownership required to trigger the initial
mandatory offer requirement was
40%.
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·
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There
are various procedural and substantive rules, including a best price rule
that relates to the price that the offeror must pay for the
shares.
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·
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There
is also a procedure for certain Oslo Stock Exchange companies to obtain
exemptions from the rules.
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B.
BUSINESS OVERVIEW
We are an
offshore drilling contractor providing global offshore drilling services to the
oil and gas industry. We have a versatile fleet of drilling units that is
outfitted to operate in shallow water, mid-water and deepwater areas, in benign
and harsh environments. Our customers are national, international and
independent oil companies. The various types of drilling units in our fleet are
as follows:
Semi-submersible
drilling rigs
Semi-submersible
drilling rigs consist of an upper working and living quarters deck resting on
vertical columns connected to lower hull pontoons. Such rigs operate in a
"semi-submerged" floating position, in which the lower hull is below the
waterline and the upper deck protrudes above the surface. The rig is situated
over a wellhead location and remains stable for drilling in the semi-submerged
floating position, due in part to its wave transparency characteristics at the
water line.
There are
two types of semi-submersible rigs, moored and dynamically positioned. Moored
semi-submersible rigs are positioned over the wellhead location with anchors,
while the dynamically positioned semi-submersible rigs are positioned over the
wellhead location by a computer-controlled thruster system. Semi-submersible
rigs generally operate with crews of 65 to 100 people.
Drillships
Our
drillships are self-propelled ships equipped for drilling in deep waters, and
are positioned over the well through a computer-controlled thruster system
similar to that used on semi-submersible rigs. Drillships are suitable for
drilling in remote locations because of their mobility and large load-carrying
capacity. Depending on region, drillships operate with crews of 65 to 100
people.
Jack-Up
Rigs
Jack-up
rigs are mobile, self-elevating drilling platforms equipped with legs that are
lowered to the ocean floor. A jack-up rig is towed to the drill site with its
hull riding in the sea as a vessel and its legs raised. At the drill site, the
legs are lowered until they penetrate the sea bed and the hull is elevated until
it is above the surface of the water. After completion of the drilling
operations, the hull is lowered until it rests on the water, the legs are raised
and the rig can be relocated to another drill site. Jack-ups are generally
suitable for water depths of 400 feet or less and operate with crews of 40 to 60
people.
Tender
Rigs
Self-erecting
tender rigs conduct production drilling from fixed or floating platforms. During
drilling operations, the tender rig, is moored next to the platform rig. The
modularized drilling package is lifted from the unit onto the platform prior to
commencement of operations. The tender rig contains living quarters, helicopter
deck, storage for drilling supplies, power machinery for running the drilling
equipment and well completion equipment. There are two types of tender rigs,
barge type and semi-submersible (semi-tender) type. Tender barges and
semi-tenders are equipped with similar equipment but the semi-tender's
semi-submersible hull structure allows the unit to operate in rougher weather
conditions. Self-erecting tender rigs allow for drilling operations to be
performed from platforms without the need for permanently installed drilling
packages. Self-erecting tender rigs generally operate with crews of 60 to 85
people.
Seawell
Limited
In
addition to owning and operating offshore drilling units, we provide well
services through Seawell, our majority owned subsidiary. Seawell
provides platform drilling, facility engineering, modular rig, well intervention
and oilfield technologies. Seawell currently operates on nearly 50 installations
in the North Sea and has offices in Stavanger and Bergen in Norway, Aberdeen and
Newcastle in the United Kingdom, Houston in the United States, Esbjerg in
Denmark, Rio de Janeiro in Brazil and Kuala Lumpur in Malaysia.
We report
our business in the following three operating segments:
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Mobile
units: We offer services encompassing drilling, completion and maintenance
of offshore wells. The drilling contracts relate to semi-submersible rigs,
jack-up rigs and drillships.
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·
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Tender
Rigs: We operate self-erecting tender rigs and semi-submersible tender
rigs, which are used for production drilling and well maintenance in
Southeast Asia and West Africa.
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·
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Well
Services: We provide services using platform drilling, facility
engineering, modular rig, well intervention and oilfield
technologies.
|
Information
regarding our revenues, segment operating profit or loss and total assets
attributable to each operating segment for the last three fiscal years is
presented in Note 3 to our consolidated financial statements included in this
Annual Report. Information regarding our operating revenues and identifiable
assets attributable to each of our geographic areas of operations for the last
three fiscal years is also presented in Note 3 to our consolidated financial
statements included in this Annual Report. For information about revenues,
operating income, assets and other information relating to our business, our
segments and the geographic areas in which we operate, see also Item 5
"Operating and Financial Review and Prospects".
Our
Business Strategy
Our
primary objective is to profitably grow our business to increase long-term
distributable cash flow per share to our shareholders.
Our
business strategy is to focus our company on modern state-of-the-art offshore
drilling units with our main focus on deepwater operations. We believe we have
one of the most modern fleets in the industry and believe that by combining
quality assets and experienced and skilled employees we will be able to provide
our customers with safe and effective operations, and establish, develop and
maintain a position as a preferred provider of offshore drilling services for
our customers. We believe that a combination of quality assets and highly
skilled employees will facilitate the procurement of term contracts and premium
dayrates. We have grown our company significantly since its incorporation in
2005 and have strong ambitions to continue the growth. We believe that the
combination of term contracts and quality assets will provide us with the
opportunity to obtain debt financing for such growth, and allow us to increase
the return on our invested equity.
The key
elements in our strategy are as follows:
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·
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commitment
to provide customers with safe and effective
operations;
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|
·
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combine
state-of-the-art mobile drilling units with experienced and skilled
employees;
|
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·
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growth
through targeted alliances, purchase of newbuildings, mergers and
acquisitions;
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·
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develop
our strong position in deepwater and harsh
environments;
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·
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develop
our strong position in the tender rig market and pursue further growth in
conventional waters as well as deepwater areas; and
|
|
·
|
offer
a diversified range of well
services.
|
We
believe that consolidation in the offshore drilling rig industry would improve
the pricing and earnings visibility for our services. Such consolidation
activities may be in the form of transactions for specific offshore drilling
units or companies. We actively look for growth opportunities and intend to take
part in the future consolidation of our industry if we determine that potential
transactions are in the best interest of our shareholders.
Market
Overview
Our
customers include oil super-majors and major integrated oil and gas companies,
state-owned national oil companies and independent oil and gas companies. Our
customers have experienced higher oil prices and significantly increased
revenues over the last decade. The increase has been related to higher demand
for oil and limited increase in available oil production to offset the growth in
demand. Over the same period the depletion rate for existing oil production has
risen and replacement rates for oil reserves have fallen for most oil producers,
highlighting the shortfall in exploration and production spending to meet future
demand. In response to this development, oil
producers,
particularly super-majors, majors and national oil companies, have devoted more
of their activities to identifying replacements for existing production in new
geographical areas at increasing water depths. This has translated into an
increased focus on frontier deepwater and ultra-deepwater areas, not only in
existing offshore regions such as Brazil, U.S. Gulf of Mexico, Europe and West
Africa but also expanding to India, Southeast Asia, China, East Africa, Mexican
Gulf of Mexico, Australasia and the Mediterranean.
Mobile
units
Developments
in the oil and gas industry discussed above have caused a strong increase in
demand for offshore drilling services, resulting in materially increased
dayrates for drilling units.
For
dynamically positioned deepwater units, dayrates increased from $290,000 in May
2005 at the inception of our Company to more than $600,000 in September 2008
just prior to the financial downturn in world markets. The increase in dayrates
made it attractive for existing drilling contractors as well as new market
participants to order new units to meet mounting demand. As a result, the
worldwide fleet of dynamically positioned deepwater drilling units is expected
to increase from 29 units in 2005 to 134 units in 2013, if all of the new units
ordered between 2005 and 2008 are delivered. Most of these newbuildings were
ordered on speculation, meaning that no drilling contract in place at the time
the construction contract was entered into. As a result of favorable market
developments, the majority of these units have secured term contracts on
attractive terms. However, due to the sudden and immediate deterioration of
overall market conditions in October 2008, there remain a significant number of
units under construction that have not yet secured employment. Although the
majority of these units will not be delivered before the end of 2010 or later,
some of the owners of these units have limited or no operating experience in
deepwater drilling, and there is a risk that they could be willing to accept
contract conditions that deviate from prevailing market terms, in order to
secure employment for their units and the financing necessary to take delivery
of their newbuilds. This could adversely affect dayrates for deepwater drilling
units in the short-term. Since October 2008, the number of new contracts entered
into for dynamically positioned deepwater units has been limited. The
most recent fixture was reported at approximately $450,000 per day. However,
dayrate levels are typically dependant on country of operation, length of
contract and overall contract terms
Since
2005 we have taken delivery of nine dynamically positioned ultra-deepwater units
and have a further two ultra-deepwater units under construction. We believe the
long-term prospects for deepwater drilling are positive given the expected
growth in oil consumption from developing nations, limited or negative growth in
oil reserves, and high depletion rates of mature oil fields. We believe that
these factors will continue to provide incentives for the exploration and
development of deepwater fields, particularly in view of recent geologic
successes in Brazil, US Gulf of Mexico, West Africa and elsewhere, along with
improving access to promising offshore areas and new, more efficient
technologies.
For
jack-up rigs, dayrates increased from $90,000 from May 2005 to more than
$200,000 per day in September 2008 as a consequence of a significant undersupply
of available jack-ups in a period when oil and gas prices were increasing
rapidly, thereby making extremely lucrative the drilling of new and previous oil
and gas discoveries with a tie-back to the existing infrastructure. In response
to this development, approximately 145 new jack-ups have been ordered bringing
the total worldwide fleet of jack-ups up to 519, assuming all the ordered units
are delivered. The majority of these newbuildings were ordered on speculation
and the majority of the 61 jack-up rigs remaining to be delivered have at
present not secured initial employment. In a period of considerable uncertainty
relating to the development of the world economy and the direction of oil and
gas prices, this could intensify price competition as scheduled delivery dates
come closer, possibly impacting adversely on dayrates for jack-up rigs. Since
October 2008, the utilization rate has been significantly reduced for the
jack-up fleet bringing dayrates down sharply as well. As of April 2010, we
believe market dayrates for new jack-up rigs are approximately $120,000 per day,
depending on country of operation, length of contract and overall contract
terms, and below $100,000 per day for older jack-up rigs. We believe
that the industry will require more modern and more effective jack-ups, as
approximately 70% of the current worldwide jack-up fleet is more than 20 years
old. We expect operators to gradually replace older and incumbent drilling units
with new, more modern and efficient rigs due to wells becoming increasingly
technically challenging and consequently demanding with respect to rig
equipment. This replacement could however take longer than previously
anticipated, given the uncertainty surrounding the global economy.
Tender
rigs
From May
2005 to September 2008 dayrates increased for barge-type tender rigs from
$45,000 to $130,000 and for semi-submersible tender rigs from $70,000 to more
than $200,000. The increase was due to a significant undersupply of available
tender rigs and reduced competition from jack-ups due to the overall increase in
offshore drilling activity. The tender rig market is a specialized niche, with
the world fleet consisting of 29 units, including four units under construction.
We are the largest operator in this segment with our fleet of 17 units,
including the five units we operate in association with Varia Perdana and the
unit we have under construction. Tender rigs are primarily used for development
drilling based on term contracts, and this has historically made this market
segment more resilient to the volatility in activity levels seen in the shallow
water market and experienced by benign environment jack-ups. Nevertheless, the
sharp drop in shallow water activity in 2008 and 2009 had an adverse impact on
the tender rig market. The short-term effect is that tender rigs that have come
off contracts since October 2008 have been warm stacked, as oil companies have
postponed drilling activity in response to lower oil and gas prices.
Accordingly, there were no tender rig fixtures in 2009. The most recent fixture
in 2010 was at approximately $90,000 per day. We believe the market uncertainty
is diminishing in response to more stable oil prices, and the long-term outlook
for
tender
rigs remains favorable, due to their versatility and lower construction costs
compared to jack-up rigs. In addition, in recent years a combination of tender
rigs and floating platforms, such as mini tension-leg platforms and spar
platforms has been used in the development of deepwater oilfields, which has
increased the market for tender rigs. Based on this we expect the market to
continue to offer opportunities to build additional order backlog and earnings
visibility.
Well
services
Seawell
is mainly involved in oil production activities in existing mature fields. The
level of activity is therefore related to the development and level of the oil
price. We believe that when oil prices are above $70 per barrel, oil companies
will focus on maintaining their production from mature fields. Based on current
market conditions, demand for drilling and well services is expected to remain
high over the next few years. However, the activity level in 2010 will depend on
the outcome of ongoing tendering activities, employment of the modular rig we
have under construction, and our success in expanding our main products and
services into new regions. We have also in response to the oil price
developments in 2008 and the beginning of 2009 experienced pressure on pricing
from our customers. This has resulted in lower contract rates, which in turn has
causes us to emphasize our focus on cost control and utilization of synergies in
order to maintain and grow profit levels.
The above
overview of the various offshore drilling sectors is based on previous market
developments and current market conditions. Future markets conditions and
developments cannot be predicted and may well differ from our current
expectations.
Customers
Our
customers are oil and gas exploration and production companies, including major
integrated oil companies, independent oil and gas producers and government-owned
oil and gas companies. In the year ended December 31, 2009 our five largest
customers have been:
|
-
|
Statoil
ASA, or Statoil, accounting for approximately 17% of
revenues;
|
|
-
|
Total
S.A. Group, or Total, accounting for approximately 13% of
revenues;
|
|
-
|
Exxon
Mobil Corp, or Exxon, accounting for approximately 12% of
revenues;
|
|
-
|
Royal
Dutch Shell, or Shell, accounting for approximately 10% of revenues;
and
|
|
-
|
Petròleo
Brasileiro S.A., or Petrobras, accounting for approximately 10% of
revenues.
|
No other
customers have accounted for more than ten percent of our revenues in any period
since inception. In the year ended December 31, 2008, our two largest customers
were Statoil and Shell, who provided approximately 32% and 7% of our contract
revenues, respectively. Statoil and Shell were also our largest customers in the
year ended December 31, 2007, providing approximately 33% and 13% of our
contract revenues, respectively. The loss of any of these significant customers
could have a material adverse effect on our results of operations if they were
not replaced by other customers.
Most of
our drilling units are contracted to customers for periods between one and five
years ahead, and our forward contracted revenue, or backlog, at December 31,
2009 totaled approximately $10.4 billion, with $8.6 billion of this amount
attributable to our semi-submersible rigs and drillships. We expect
approximately $3.1 billion of this backlog to be realized in 2010. Backlog for
our drilling fleet is calculated as the contract dayrate multiplied by the
number of days remaining on the contract, assuming full utilization. Backlog
excludes revenues for mobilization and demobilization, contract preparation and
customer reimbursables. The amount of actual revenues earned and the actual
periods during which revenues are earned will be different from the backlog
projections due to various factors. Downtime, caused by unscheduled repairs,
maintenance, weather and other operating factors, may result in lower applicable
dayrates than the full contractual operating dayrate.
The
following table shows the percentage of rig days committed by year as of
December 31 2009. The percentage of rig days committed is calculated as the
ratio of total days committed under firm contracts to total available days in
the period. Total available days for our units under construction are based on
their expected delivery dates.
|
|
Year ending December 31,
|
|
%
of rig-days committed
|
|
2010
|
|
|
2011
|
|
|
2012
|
|
|
|
|
|
|
|
|
|
|
|
Jack-up
rigs
|
|
|
62
|
%
|
|
|
7
|
%
|
|
|
0
|
%
|
Semi-submersible
rigs
|
|
|
100
|
%
|
|
|
94
|
%
|
|
|
55
|
%
|
Drillships
|
|
|
88
|
%
|
|
|
75
|
%
|
|
|
70
|
%
|
Tender
rigs
|
|
|
84
|
%
|
|
|
69
|
%
|
|
|
40
|
%
|
Competition
The
offshore drilling industry is highly competitive, with market participants
ranging from large multinational companies to small locally-owned
companies.
The
demand for offshore drilling services is driven by oil and gas companies'
exploration and development drilling programs. These drilling programs are
affected by oil and gas companies' expectations regarding oil and gas prices,
anticipated production levels, worldwide demand for oil and gas products and
many other factors. The availability of quality drilling prospects, exploration
success, availability of qualified rigs and operating personnel, relative
production costs, availability and lead time requirements for drilling and
production equipment, the stage of reservoir development and political and
regulatory environments also affect our customers' drilling programs. Oil and
gas prices are volatile, which has historically led to significant fluctuations
in expenditures by our customers for drilling services. Variations in market
conditions during cycles impact us in different ways, depending primarily on the
length of drilling contracts in different regions. For example, contracts in
shallow waters for jack-up rig activities are shorter term, so a deterioration
or improvement in market conditions for such units tends to quickly impact
revenues and cash flows from those operations. On the other hand, contracts in
deepwater for semi-submersible rigs and drillships tend to be longer term, so a
change in market conditions tends to have a delayed impact. Accordingly,
short-term changes in these markets may have a minimal short-term impact on
revenues and cash flows, unless the timing of contract renewals coincides with
short-term movements in the market.
Offshore
drilling contracts are generally awarded on a competitive bid basis. In
determining which qualified drilling contractor is awarded a contract, the key
factors are pricing, rig availability and sustainability, rig location,
condition of equipment, operating integrity, safety performance record, crew
experience, reputation, industry standing and client relations.
Competition
for offshore drilling rigs is generally on a global basis, as rigs are highly
mobile. However, the cost associated with mobilizing rigs between regions is
sometimes substantial, as entering a new region could necessitate upgrades of
the unit and its equipment to specific regional requirements. In particular, for
rigs to operate in harsh environments, such as offshore Norway and Canada, as
opposed to benign environments, such as the Gulf of Mexico, West Africa, Brazil,
the Mediterranean and Southeast Asia, more demanding weather conditions would
require more costly investment in the outfitting and maintenance of the drilling
units.
We
believe that the market for drilling contracts will continue to be highly
competitive for the foreseeable future.
Risk
of Loss and Insurance
Our
operations are subject to hazards inherent in the drilling of oil and gas wells,
including blowouts and well fires, which could cause personal injury, suspend
drilling operations, or seriously damage or destroy the equipment involved.
Offshore drilling contractors such as us are also subject to hazards particular
to marine operations, including capsizing, grounding, collision and loss or
damage from severe weather. Our marine insurance package policy provides
insurance coverage for physical damage to our rigs, liability due to
control-of-well events and loss of hire insurance.
We
maintain a portion of deductibles for damage to our offshore drilling equipment.
With respect to hull and machinery, we currently have a deductible per
occurrence of up to $1.7 million. However, a total loss or a constructive total
loss of a drilling unit is covered by our insurance with no deductible. For
general and marine third-party liabilities we generally maintain a deductible of
up to $250,000 per occurrence on personal injury liability for crew claims,
non-crew claims and third-party property damage. Furthermore, we purchase
insurance to cover the loss of hire on our fleet due to physical damage.
However, we have a deductible period up to 60 days after the occurrence of
physical damage. Thereafter our insurance policies are limited to between 100
days and 290 days. If the repair period for any physical damage exceeds the
number of days permitted under our loss of hire policy, we will be responsible
for the costs in such period.
Environmental
and Other Regulations in the Offshore Drilling Industry
Our
offshore drilling operations include activities that are subject to numerous
international, federal, state and local laws and regulations, including the
International Convention for the Prevention of Pollution from Ships, or MARPOL,
the International Convention on Civil Liability for Bunker Oil Pollution Damage,
or Bunker Convention, the U.S. Oil Pollution Act, or OPA, the Comprehensive
Environmental Response, Compensation and Liability Act, or CERCLA, the U.S.
Outer Continental Shelf Lands Act, and Brazil's National Environmental Policy
Law (6938/81), Environmental Crimes Law (9605/98) and Law 9966/2000 relating to
pollution in Brazilian waters. These laws govern the discharge of materials into
the environment or otherwise relate to environmental protection. In certain
circumstances, these laws may impose strict liability, rendering us liable for
environmental and natural resource damages without regard to negligence or fault
on our part.
For
example, the United Nations' International Maritime Organization, or IMO,
adopted MARPOL and Annex VI to MARPOL to regulate the discharge of harmful air
emissions from ships, which include rigs and drillships. Rigs and drillships
must comply with MARPOL limits on sulfur oxide and nitrogen oxide emissions,
chlorofluorocarbons, and the discharge of other air pollutants, except that the
MARPOL limits do not apply to emissions that are directly related to drilling,
production, or processing activities.
Our
drilling units are subject not only to MARPOL regulation of air emissions, but
also to the Bunker Convention's strict liability for pollution damage caused by
discharges of bunker fuel in ratifying states. We believe that all of our
drilling units are currently compliant in all material respects with these
regulations. In October 2008, IMO's Maritime Environment Protection Committee,
or MEPC, adopted
amendments
to the Annex VI regulations that will require a progressive reduction of sulfur
oxide levels in heavy bunker fuels and create more stringent nitrogen oxide
emissions standards for marine engines in the future. We may incur costs to
comply with these revised standards.
Furthermore,
any drillships we may operate in the waters of the U.S.,
including the U.S. territorial sea and the 200 nautical mile
exclusive economic zone around the U.S., would have to comply with OPA and
CERCLA regulations, as described above, that impose liability (unless the spill
results solely from the act or omission of a third party, an act of God or an
act of war) for all containment and clean-up costs and other damages arising
from discharges of oil or other hazardous substances, other than discharges
related to drilling.
The
Minerals Management Service of the U.S. Department of the Interior ("MMS")
periodically issues guidelines for jack-up rig fitness requirements in the U.S.
Gulf of Mexico and may take other steps that could increase the cost of
operations or reduce the area of operations for our jack-up rigs, thus reducing
their marketability. Implementation of MMS guidelines or regulations may subject
us to increased costs or limit the operational capabilities of our rigs and
could materially and adversely affect our operations and financial condition.
Please read "Risk Factors — Our ability to operate our drilling units in the
U.S. Gulf of Mexico could be restricted by government regulation" in Item 3.D of
this Annual Report.
Numerous
governmental agencies issue such regulations to implement and enforce the laws
of the applicable jurisdiction, which often involve lengthy permitting
procedures, impose difficult and costly compliance measures, particularly in
ecologically sensitive areas, and subject operators to substantial
administrative, civil and criminal penalties or may result in injunctive relief
for failure to comply. Some of these laws contain criminal sanctions in addition
to civil penalties. Changes in environmental laws and regulations occur
frequently, and any changes that result in more stringent and costly compliance
or limit contract drilling opportunities could adversely affect our financial
results. While we believe that we are in substantial compliance with the current
laws and regulations, there is no assurance that compliance can be maintained in
the future.
In
addition to the MARPOL, OPA, and CERCLA requirements described above, our
international operations in the offshore drilling segment are subject to various
laws and regulations in countries in which we operate, including laws and
regulations relating to the importation of and operation of drilling units and
equipment, currency conversions and repatriation, oil and gas exploration and
development, environmental protection, taxation of offshore earnings and
earnings of expatriate personnel, the use of local employees and suppliers by
foreign contractors and duties on the importation and exportation of drilling
units and other equipment. New environmental or safety laws and regulations
could be enacted, which could adversely affect our ability to operate in certain
jurisdictions. Governments in some countries have become increasingly active in
regulating and controlling the ownership of concessions and companies holding
concessions, the exploration for oil and gas and other aspects of the oil and
gas industries in their countries. In some areas of the world, this governmental
activity has adversely affected the amount of exploration and development work
done by major oil and gas companies and may continue to do so. Operations in
less developed countries can be subject to legal systems that are not as mature
or predictable as those in more developed countries, which can lead to greater
uncertainty in legal matters and proceedings.
Implementation
of new environmental laws or regulations that may apply to ultra-deepwater
drilling units may subject us to increased costs or limit the operational
capabilities of our drilling units and could materially and adversely affect our
operations and financial condition. A discussion of risks relating to
environmental regulations can be found in Item 3.D "Risk Factors" of this Annual
Report.
C.
ORGANIZATIONAL STRUCTURE
We were
incorporated on May 10, 2005, under the laws of Bermuda. We are engaged, with
our subsidiaries and consolidated companies, in the ownership and operation of a
diversified fleet of offshore drilling units and in the provision of well
services. Our operations are split into three reporting segments – mobile units
(world-wide), tender rigs (mainly in south-east Asia and Africa) and well
services (mainly in the North Sea).
Overall
responsibility for the management of Seadrill Limited and its subsidiaries rests
with the Board of Directors. The Board has organized the provision of management
services through two subsidiaries incorporated in Norway, Seadrill Management
AS, or Seadrill Management, and Seawell Management AS, or Seawell Management.
The Board has defined the scope and terms of the services to be provided by
these two companies and has provided authority for them to run day to day
operations. The Board must be consulted on all matters of material importance
and/or of an unusual nature, and for such matters will provide specific
authorization to personnel in Seadrill Management and/or Seawell Management to
act on the Company's behalf.
A full
list of our significant management, operating and rig-owning subsidiaries is
shown in Exhibit 8.1.
D.
PROPERTY, PLANT AND EQUIPMENT
We own a
substantially modern fleet of drilling units. The following table sets forth the
units that we own or have contracted for delivery as of April 26,
2010:
|
Year
|
Water
depth
|
Drilling
depth
|
Current
location
|
Month
of
|
Unit
|
built
|
(feet)
|
(feet)
|
|
contract
expiry
|
|
|
|
|
|
|
Jack-up
rigs
|
|
|
|
|
|
West
Larissa
|
1984
|
300
|
21,000
|
Vietnam
|
December
2010
|
West
Janus
|
1985
|
330
|
21,000
|
Malaysia
|
August
2011
|
West
Epsilon
|
1993
|
400
|
30,000
|
Norway
|
January
2015
|
West
Prospero(SF)
|
2007
|
400
|
30,000
|
Red
Sea
|
July
2010
|
West
Triton
|
2008
|
375
|
30,000
|
South
East Asia
|
September
2010
|
West
Ariel
|
2008
|
400
|
30,000
|
Vietnam
|
October
2010
|
West
Callisto (NB)
|
2010
|
400
|
30,000
|
|
April
2011
|
West
Juno (NB)
|
2010
|
400
|
30,000
|
|
|
West
Leda (NB)
|
2010
|
375
|
30,000
|
|
November
2010
|
CJ70
(NB)
(1)
|
2011
|
450
|
40,000
|
|
August
2016
|
|
|
|
|
|
|
Tender
rigs
|
|
|
|
|
|
T4
|
1981
|
410
|
20,000
|
Thailand
|
July
2013
|
T8
|
1982
|
410
|
20,000
|
Malaysia
(warm stacked *)
|
|
T7
|
1983
|
410
|
20,000
|
Thailand
|
October
2011
|
West
Pelaut
|
1994
|
6,500
|
30,000
|
Brunei
|
March
2012
|
West
Menang
|
1999
|
6,500
|
30,000
|
Namibia
(warm stacked *)
|
December
2010
|
West
Alliance
|
2001
|
6,500
|
30,000
|
Malaysia
|
January
2015
|
West
Setia
|
2005
|
6,500
|
30,000
|
Angola
|
August
2012
|
West
Berani
|
2006
|
6,500
|
30,000
|
Indonesia
|
December
2011
|
T11
|
2008
|
6,500
|
30,000
|
Thailand
|
May
2013
|
T12
|
2010
|
6,500
|
30,000
|
Thailand
|
April
2011
|
West
Vencedor
|
2010
|
6,500
|
30,000
|
Angola
|
April
2015
|
West
Jaya (NB)
|
2011
|
6,500
|
30,000
|
|
|
|
|
|
|
|
|
Semi-submersible
rigs
|
|
|
|
|
|
West
Alpha
|
1986
|
2,000
|
23,000
|
Norway
|
June
2012
|
West
Venture
|
2000
|
6,000
|
30,000
|
Norway
|
August
2015
|
West
Phoenix
|
2008
|
10,000
|
30,000
|
Norway
|
January
2012
|
West
Hercules (SF)
|
2008
|
10,000
|
35,000
|
China
|
November
2011
|
West
Sirius
|
2008
|
10,000
|
35,000
|
Gulf
of Mexico
|
July
2014
|
West
Taurus (SF)
|
2008
|
10,000
|
35,000
|
Brazil
|
February
2015
|
West
Eminence
|
2009
|
10,000
|
30,000
|
Brazil
|
July
2015
|
West
Aquarius
|
2009
|
10,000
|
35,000
|
Indonesia
|
February
2013
|
West
Orion (NB)
|
2010
|
10,000
|
35,000
|
In
transit to Brazil
|
July
2016
|
West
Capricorn (NB)
|
2011
|
10,000
|
35,000
|
|
|
|
|
|
|
|
|
Drillships
|
|
|
|
|
|
West
Navigator
|
2000
|
7,500
|
35,000
|
Norway
|
December
2012
|
West
Polaris (SF)
|
2008
|
10,000
|
35,000
|
Brazil
|
October
2012
|
West
Capella
|
2008
|
10,000
|
35,000
|
Nigeria
|
April
2014
|
West
Gemini (NB)
|
2010
|
10,000
|
35,000
|
|
September
2012
|
NB –
Newbuilding.
SF –
Unit owned by subsidiary of Ship Finance (see Note 33 to Consolidated Financial
Statements).
(1) –
We have an option to purchase this jack-up rig and have announced that we intend
to exercise that option.
* - Warm
stacked means that the unit is not operating, but is being maintained in a state
of readiness for future operations.
In
addition to the drilling units listed above, as at December 31, 2009 we have
buildings, plant and equipment with a net book value of $115 million, including
an office building in Bergen, a modular rig under construction for Seawell, and
office equipment. Our offices in Stavanger in Norway, Singapore,
Houston in the United States, Rio de Janeiro in Brazil and Aberdeen in the
United Kingdom are leased and aggregate office rental costs were $13.7 million
in 2009, and are expected to be approximately $20.0 million in
2010.
We do not
have any material intellectual property rights
ITEM 4A
.
UNRESOLVED STAFF
COMMENTS
Not
applicable.
ITEM
5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
The
following should be read in conjunction with Item 3.A "Selected Financial Data",
Item 4 "Information on the Company" and our Consolidated Financial Statements
and Notes thereto included herein.
Overview
We were
established in May 2005 with an operating fleet of five units. Since then,
through investment in newbuildings and the acquisition of other companies, we
have expanded our operations and now have approximately 7,600 skilled employees
and an operating fleet of 28 drilling units. In addition, we have construction
contracts for eight new units, including an option to purchase a jack-up rig
which we intend to exercise, and we operate a further five units in association
with Varia Perdana. A full fleet list is provided in Item 4.D "Information on
the Company – Property, Plant and Equipment".
In
addition to owning and operating offshore drilling units, we provide drilling
and well services through Seawell, our majority owned subsidiary.
We have
also made investments in other companies that are viewed as strategic
investments, including Pride (9.4%), SapuraCrest (23.6%), Varia Perdana (49%)
and Scorpion (40.0%). In compliance with the rules of the Oslo Stock Exchange,
we have announced that we will make a mandatory cash offer for the remaining
shares in Scorpion.
Fleet
Development
The
following table summarizes the development of our active fleet of drilling
units, based on the dates when the units began operations:
Unit
type
|
Mobile
units segment
|
Tender
rigs
|
Total
units
|
FPSOs
|
Jack-up
rigs
|
Drillships
|
Semi-submersible
rigs
|
At
December 31, 2005
|
2
|
3
|
-
|
-
|
-
|
5
|
additions
in 2006
|
|
+2
|
+1
|
+2
|
+7
|
+12
|
At
December 31, 2006
|
2
|
5
|
1
|
2
|
7
|
17
|
additions
in 2007
|
|
+2
|
|
|
+1
|
+3
|
disposals
in 2007
|
-2
|
|
|
|
|
-2
|
At
December 31, 2007
|
-
|
7
|
1
|
2
|
8
|
18
|
additions
in 2008
|
|
+2
|
+1
|
+2
|
+1
|
+6
|
disposals
in 2008
|
|
-1
|
|
|
|
-1
|
At
December 31, 2008
|
-
|
8
|
2
|
4
|
9
|
23
|
additions
in 2009
|
|
|
+1
|
+4
|
|
+5
|
disposals
in 2009
|
|
-2
|
|
|
|
-2
|
At
December 31, 2009
|
-
|
6
|
3
|
8
|
9
|
26
|
The
following rigs under construction are scheduled to be delivered after December
31, 2009:
|
·
|
In
2010: three jack-up rigs, two tender rigs, one semi-submersible rig and
one drillship.
|
|
·
|
In
2011: one tender rig, one semi-submersible rig and one jack-up
rig.
|
Factors
Affecting our Results of Operations
The
principal factors which have affected our results since 2005 and are expected to
affect our future results of operations and financial position
include:
|
·
|
the
number and operating availability of our drilling
units;
|
|
·
|
the
daily operating revenues earned under our term
contracts;
|
|
·
|
the
daily operating expenses of our drilling
units;
|
|
·
|
administrative
expenses;
|
|
·
|
interest
and other financial items; and
|
Revenues
Our
revenues are derived primarily from the operation of our drilling units on
short, medium and long-term contracts at fixed daily rates. Revenues from well
services are derived from drilling on our client's fixed installations and from
carrying out a wide range of engineering and down-hole services.
In
general, each of our drilling units is contracted for a period of time to an oil
and gas company to provide offshore drilling services at an agreed daily rate. A
unit will be stacked if it has no contract in place. Daily rates can vary from
$50,000 per day to over $600,000 per day, depending on the type of drilling unit
and its capabilities, operating expenses, taxes and other factors. An important
factor determining the revenue is the technical utilization of the drilling rig.
To the extent that our operations are interrupted due to equipment breakdown or
operational failures, we do not generally receive dayrate compensation for the
period of the interruption.
The terms
and conditions of the contracts allow for compensation when factors influencing
the drilling operation are outside our control, for example, weather, and also
in some cases for compensation when we perform planned maintenance activities.
In many of our contracts we are entitled to cost escalation to compensate for
industry specific cost increases as reflected in publicly available cost
indices.
In
addition to contracted day-rate revenue, customers may pay mobilization and
demobilization fees for units before and after their drilling assignments, and
may also pay reimbursement of costs incurred by the Company at their request for
supplies, personnel and other services.
The
following table summarizes our average daily revenues and economic utilization
percentage by rig type for the periods under review:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average
daily revenues
|
|
|
Economic
utilization
|
|
|
Average
daily revenues
|
|
|
Economic
utilization
|
|
|
Average
daily revenues
|
|
|
Economic
utilization
|
|
|
|
$
|
|
|
|
%
|
|
|
$
|
|
|
|
%
|
|
|
$
|
|
|
|
%
|
|
Jack-up
rigs
|
|
|
130,000
|
|
|
|
70
|
|
|
|
196,000
|
|
|
|
92
|
|
|
|
172,000
|
|
|
|
85
|
|
Semi-submersible
rigs
|
|
|
445,000
|
|
|
|
92
|
|
|
|
345,000
|
|
|
|
93
|
|
|
|
247,000
|
|
|
|
99
|
|
Drillships
|
|
|
497,000
|
|
|
|
94
|
|
|
|
251,000
|
|
|
|
66
|
|
|
|
206,000
|
|
|
|
83
|
|
Tender
rigs
|
|
|
115,000
|
|
|
|
93
|
|
|
|
95,000
|
|
|
|
98
|
|
|
|
78,000
|
|
|
|
99
|
|
Note:
Average daily revenues are the weighted average revenues for each type of unit,
based on the actual days available for each unit of that
type. Economic utilization is calculated as the total days worked
divided by the total days in the period.
Expenses
Our
expenses consist primarily of rig operating expenses, reimbursable expenses,
depreciation and amortization, administration expenses, interest and other
financial expenses and tax expenses.
Rig
operating expenses are related to the drilling units we have in operation and
include the remuneration of offshore crews and onshore rig supervision staff, as
well as expenses for repairs and maintenance. Reimbursable expenses are incurred
at the request of customers, and include provision of supplies, personnel and
other services. Depreciation and amortization costs are based on the historical
cost of our drilling units and other equipment. Administration expenses include
the costs of offices in various locations, as well as the remuneration and other
compensation of the directors and employees engaged in the management and
administration of the Company.
Our
interest expenses depend on the overall level of debt and prevailing interest
rates. However, these expenses may be reduced as a consequence of capitalization
of interest expenses for drilling units under construction. Other financial
items include income from associated companies and may reflect various
mark-to-market adjustments to the value of our interest rate and forward
currency swaps and other derivative financial instruments
.
Tax
expenses reflect payable and deferred tax related to our rig owning and
operating activities and may vary significantly depending on jurisdictions and
contractual arrangements. In most cases the tax is based on net income or deemed
income based on gross turnover.
Critical
Accounting Estimates
The
preparation of our consolidated financial statements requires us to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses and related disclosures about contingent
assets and liabilities. We base these estimates and assumptions on historical
experience and on various other information and assumptions that we believe to
be reasonable under the circumstances. Our critical accounting
estimates are important to the portrayal of both our financial condition and
results of operations and require us to make difficult, subjective or complex
assumptions or estimates about matters that are
uncertain. Significant accounting policies are discussed in our Notes
to Consolidated Financial Statements – Note 2: Accounting policies. We believe
that the following are the critical accounting estimates used in the preparation
of our consolidated financial statements. In addition, there are other items
within our consolidated financial statements that require
estimation.
Drilling
Units
Rigs,
vessels and equipment are recorded at historical cost less accumulated
depreciation. The cost of these assets less estimated residual value is
depreciated on a straight-line basis over their estimated remaining economic
useful lives. The estimated economic useful life of the Company's mobile units
and tender rigs, when new, is 30 years.
Significant
investments are capitalized and depreciated in accordance with the nature of the
investment. Significant investments that are deemed to increase an asset's value
for its remaining useful life are capitalized and depreciated over the remaining
life of the asset.
We
determine the carrying value of these assets based on policies that incorporate
our estimates, assumptions and judgments relative to the carrying value,
remaining useful lives and residual values. The assumptions and judgments we use
in determining the estimated useful lives of our drilling units reflect both
historical experience and expectations regarding future operations, utilization
and performance. The use of different estimates, assumptions and judgments in
establishing estimated useful lives would probably result in materially
different net book values of our drilling units and results of
operations.
The
useful lives of rigs and related equipment are difficult to estimate due to a
variety of factors, including technological advances that impact the methods or
cost of oil and gas exploration and development, changes in market or economic
conditions and changes in laws or regulations affecting the drilling industry.
We evaluate the remaining useful lives of our drilling units when certain events
occur which directly impact our assessment of their remaining useful lives and
include changes in operating condition, functional capability and market and
economic factors.
The
carrying values of our long-lived assets are reviewed for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may no longer be appropriate. We assess recoverability of the carrying value of
the asset by estimating the undiscounted future net cash flows expected to
result from the asset, including eventual disposition. If the undiscounted
future net cash flows are less than the carrying value of the asset, an
impairment loss is recorded equal to the difference between the asset's carrying
value and fair value. In general, impairment analyses are based on expected
costs, utilization and dayrates for the estimated remaining useful lives of the
asset or group of assets being assessed. An impairment loss is recorded in the
period in which it is determined that the aggregate carrying amount is not
recoverable. Asset impairment evaluations are, by nature, highly subjective.
They involve expectations about future cash flows generated by our assets, and
reflect management's assumptions and judgments regarding future industry
conditions and their effect on future utilization levels, dayrates and costs.
The use of different estimates and assumptions could result in materially
different carrying values of our assets and could materially affect our results
of operations.
Income
Taxes
We are a
Bermuda company and currently we are not required to pay taxes in Bermuda on
ordinary income or capital gains. We have received written assurance from the
Minister of Finance in Bermuda that we will be exempt from taxation until March
2016. Certain subsidiaries operate in other jurisdictions where taxes are
imposed. Consequently income taxes have been recorded in these jurisdictions
when appropriate. Our income tax expense is based on our income, statutory tax
rates and tax planning opportunities available to us in the various
jurisdictions in which we operate. We provide for income taxes based on the tax
laws and rates in effect in the countries in which operations are conducted and
income is earned. The income tax rates and methods of computing taxable income
vary substantially between jurisdictions. Our income tax expense is expected to
fluctuate from year to year as our operations are conducted in different taxing
jurisdictions and the amount of pre-tax income fluctuates.
The
determination and evaluation of our annual group income tax provision involves
the interpretation of tax laws in various jurisdictions in which we operate and
requires significant judgment and the use of estimates and assumptions regarding
significant future events, such as the amount, timing and character of income,
deductions and tax credits. There are certain transactions for which the
ultimate tax determination is unclear due to uncertainty in the ordinary course
of business. We recognize tax liabilities based on our assessment of whether our
tax positions are sustainable and on estimates of taxes that will ultimately be
due. Changes in tax laws, regulations, agreements, treaties, foreign currency
exchange restrictions or our levels of operations or profitability in each
jurisdiction may impact our tax liability in any given year. While our annual
tax provision is based on the information available to us at the time, a number
of years may elapse before the ultimate tax liabilities in certain tax
jurisdictions are determined. Current income tax expense reflects an estimate of
our income tax liability for the current year, withholding taxes, changes in
prior year tax estimates as returns are filed, or from tax audit adjustments.
Our deferred tax expense or benefit represents the change in the balance of
deferred tax assets or liabilities as
reflected
on the balance sheet. Valuation allowances are determined to reduce deferred tax
assets when it is more likely than not that some portion or all of the deferred
tax assets will not be realized. To determine the amount of deferred tax assets
and liabilities, as well as of the valuation allowances, we must make estimates
and certain assumptions regarding future taxable income, including where our
drilling units are expected to be deployed, as well as other assumptions related
to our future tax position. A change in such estimates and assumptions, along
with any changes in tax laws, could require us to adjust the deferred tax
assets, liabilities, or valuation allowances.
Contingencies
We
establish reserves for estimated loss contingencies when we believe a loss is
probable and the amount of the loss can be reasonably estimated. Our contingent
liability reserves relate primarily to litigation, indemnities and potential
income and other tax assessments (see also "Income Taxes" above). Revisions to
contingent liability reserves are reflected in income in the period in which
different facts or information become known or circumstances change that affect
our previous assumptions with respect to the likelihood or amount of loss.
Reserves for contingent liabilities are based upon our assumptions and estimates
regarding the probable outcome of the matter and include our costs to defend any
action. In situations where we expect insurance proceeds to offset contingent
liabilities, we record a receivable for all probable recoveries until the net
loss is zero. We recognize contingent gains when the contingency is resolved and
the gain has been realized. Should the outcome differ from our assumptions and
estimates or other events result in a material adjustment to the accrued
estimated contingencies, revisions to the estimated contingency amounts would be
required and would be recognized in the period when the new information becomes
known.
Goodwill
We
allocate the cost of acquired businesses to the identifiable tangible and
intangible assets and liabilities acquired, with any remaining amount being
capitalized as goodwill. We perform an annual test of goodwill impairment as of
December 31 for each reporting segment or a component of an operating segment
that constitutes a business for which financial information is available and is
regularly reviewed by management., based on a discounted cash flow model. When
testing for impairment we use expected future cash flows using contract dayrates
during the contract periods. For periods after expiry of the contract periods,
dayrates are projected based on estimates regarding future market conditions,
including zero escalation of dayrates. The estimated future cash flows are
calculated based on remaining asset lives and are discounted using a weighted
average cost of capital. We had no impairment of goodwill for the years ended
December 31, 2009, 2008 and 2007, as the net present value of the estimated
future cash flows supports the book value of goodwill. We have also performed
sensitivity analyses using different scenarios regarding future cash flows,
remaining asset lives and discount rates showing acceptable tolerance to changes
in underlying assumptions in the impairment model before changes in assumptions
would result in impairment. The use of different estimates and assumptions could
result in materially different carrying value of goodwill and could materially
affect our results of operations.
Defined
benefit pension plans
The
Company has several defined benefit plans which provide retirement, death and
termination benefits. The Company's net obligation is calculated separately for
each plan by estimating the amount of the future benefit that employees have
earned in return for their cumulative service. Pension and postretirement costs
and obligations are actuarially determined and are affected by assumptions
including expected return on plan assets, discount rates, compensation increases
and employee turnover. The use of different estimates and assumptions could
result in materially different carrying value pension obligations and could
materially affect our results of operations.
The
projected future benefit obligation is discounted to its present value, and the
fair value of any plan assets is deducted. The discount rate is the market yield
at the balance sheet date on government bonds in the currency and based on terms
consistent with the post-employment benefit obligations. The retirement benefits
are generally a function of years of employment and amount of compensation. The
plans are primarily funded through payments to insurance companies. The Company
records its pension costs in the period during which the services are rendered
by the employees. Actuarial gains and losses are recognized in the statement of
operations when the net cumulative unrecognized actuarial gains or losses for
each individual plan at the end of the previous reporting year exceed 10 percent
of the higher of the present value of the defined benefit obligation and the
fair value of plan assets at that date. These gains and losses are recognized
over the expected remaining working lives of the employees participating in the
plans. Otherwise, recognition of actuarial gains and losses is included in other
comprehensive income. Those amounts will be subsequently recognized
as a component of net periodic pension cost on the same basis as the amounts
recognized in accumulated other comprehensive income.
Impairment
of marketable securities and equity method investees
We
analyze our available-for-sale securities and equity method investees for
impairment during each reporting period to evaluate whether an event or change
in circumstances has occurred in that period which may have a significant
adverse effect on the fair value of the investment. We record an impairment
charge for other-than-temporary declines in fair value when the fair value is
not anticipated to recover above cost within a reasonable period after the
measurement date, unless there are mitigating factors that indicate impairment
may not be required. If an impairment charge is recorded, subsequent recoveries
in fair value are not reflected in earnings until sale of the securities held as
available for sale or of the equity method investee are sold. The evaluation of
whether a decline in fair value is other-than-temporary requires a high degree
of judgment and the use of different assumptions could materially affect our
results of operations.
Recent
accounting pronouncements
In
December 2007, the Financial Accounting Standards Board ('FASB') issued
Statements No. 141(R), Business Combinations, ("FAS 141(R)", (codified in ASC
805), and No. 160 Noncontrolling Interests in Consolidated Financial Statements,
("FAS 160"), (codified in ASC 810). Together these statements can affect the way
companies account for future business combinations and noncontrolling interests.
ASC 805 requires, amongst other changes, recognition of subsequent changes in
the fair value of contingent consideration in the Statement of Operations rather
than against Goodwill, and transaction costs to be recognized immediately in the
Statement of Operations. ASC 810-10-65-1 clarifies the classification of
noncontrolling interests in consolidated balance sheets and the accounting for
and reporting of transactions between the reporting entity and holders of such
noncontrolling interests. In particular the noncontrolling interest in
subsidiaries should be presented in the consolidated balance sheet within
equity, but separate from the parent's equity. Similarly the amount of net
income attributable to the parent and to the minority interest be clearly
identified and presented on the consolidated statement of
income. Both these Statements are effective for transactions
completed in fiscal years beginning after December 15, 2008. Adoption of these
Statements by the Company in the financial statements beginning January 1, 2009
did not have a material effect on the Company's consolidated financial
statements except that noncontrolling interests is classified as a component of
equity.
In April
2009, the FASB issued FSP FAS 107-1 and APB 28-1 (codified in ASC 825), Guidance
on Interim Fair Value Disclosures, which expands the fair value disclosures
required for all financial instruments within the scope of this topic to interim
periods for publicly traded entities. Entities must disclose the method(s) and
significant assumptions used to estimate the fair value of financial instruments
in financial statements on an interim basis and to highlight any changes in the
methods and significant assumptions from prior periods. The guidance is
effective for interim and annual periods ending after June 15, 2009 and adoption
of this FSP did not have a material effect on our consolidated
financial statements.
In April
2009, the FASB issued FSP FAS 115-2 (codified in ASC 320) which provides
additional guidance to highlight and expand on the factors that should be
considered in estimating fair value when there has been a significant decrease
in market activity for a financial asset. The guidance is effective
for interim and annual periods ending after June 15, 2009. Adoption of this FSP
did not have a material effect t on our consolidated financial
statements.
In May
2009, the FASB issued Statement No. 165 Subsequent Events, ('FAS 165'),
(codified in ASC 855). This Statement provides guidance on management's
assessment of subsequent events. The guidance clarifies that management must
evaluate, as of each reporting period, events or transactions that occur after
the balance sheet date "through the date that the financial statements are
issued or are available to be issued." Management must perform its assessment
for both interim and annual financial reporting periods. The new guidance is
effective prospectively for interim and annual periods ending after June 15,
2009. Adoption of the Statement did not have a material effect on the Company's
consolidated financial statements. In February 2010 the FASB amended the
subsequent events guidance issued in May 2009 to remove the requirement for SEC
filers to disclose a date through which subsequent events have been evaluated in
both issued and revised financial statements. The amendment is effective upon
issuance. The adoption of this guidance did not have a material effect on our
consolidated financial condition or results of operations.
In June
2009, the FASB issued Statement No. 168, Statement on Codification and Hierarchy
of Generally Accepted Accounting Principles, ('FAS 168'), (codified in ASC 105).
The standard is a replacement for FAS 162. The GAAP hierarchy will be modified
to include only two levels of GAAP; authoritative and non-authoritative. The
standard is effective for financial statements issued for interim and annual
periods ending after September 15, 2009. The adoption of this Standard did not
have a material effect on the Company's consolidated financial
statements.
In June
2009, the FASB issued Statement No. 167, Amendments to FASB Interpretation No.
46(R) (FAS 167) (codified in ASC 810). The amended guidance requires companies
to qualitatively assess the determination of the primary beneficiary of a
variable-interest entities ("VIEs") based on whether the entity (1) has the
power to direct the activities of the VIE that most significantly impact the
entity's economic performance and (2) has the obligation to absorb losses of the
entity that could potentially be significant to the VIE or the right to receive
benefits from the entity that could potentially be significant to the VIE. It
also requires additional disclosures for any enterprise that holds a variable
interest in a VIE. The new accounting and disclosure requirements become
effective for the Company from January 1, 2010. The Company is currently
assessing the impact of this amendment on its consolidated financial
statements.
In
January 2010, the FASB issued ASC 820 Improving Disclosures about Fair Value
Measurements. The new disclosures and clarifications of existing disclosures are
effective for interim and annual reporting periods beginning after December 15,
2009, except for the disclosures about purchases, sales, issuances, and
settlements in the roll forward of activity in Level 3 fair value measurements.
Those disclosures are effective for fiscal years beginning after December 15,
2010, and for interim periods within those fiscal years. The Company is
currently assessing the impact of this amendment on its consolidated financial
statements.
Seasonality
In
general seasonal factors do not have a significant direct effect on our business
as most of our drilling units are contracted for periods of at least 12 months.
However, we have operations in certain parts of the world where weather
conditions during parts of the year could adversely impact the operational
utilization of the rigs and our ability to relocate rigs between drilling
locations, and limit contract opportunities in the short term. Such adverse
weather could include the hurricane season for our operations in the Gulf of
Mexico, the winter season in offshore Norway, and the monsoon season in
Southeast Asia.
Inflation
Most of
our contracts for drilling and well services include provision for rates to be
adjusted annually in line with inflation. Accordingly, we do not consider
inflation to be a significant risk to profitability in the current and
foreseeable economic environment, although it will have a moderate effect on
operating and administration costs.
A.
RESULTS OF OPERATIONS
Fiscal
Year Ended December 31, 2009, compared to Fiscal Year Ended December 31,
2008.
The
following table sets forth the Company's operating results for 2009 and
2008.
|
|
Year
ended December 31, 2009
|
|
|
Year
ended December 31, 2008
|
|
In
US$ millions
|
|
Mobile
units
|
|
|
Tender
rigs
|
|
|
Well
services
|
|
|
Total
|
|
|
Mobile
units
|
|
|
Tender
rigs
|
|
|
Well
services
|
|
|
Total
|
|
Total
operating revenues
|
|
|
2,251
|
|
|
|
392
|
|
|
|
610
|
|
|
|
3,253
|
|
|
|
1,144
|
|
|
|
342
|
|
|
|
620
|
|
|
|
2,106
|
|
Gain
on sale of assets
|
|
|
71
|
|
|
|
|
|
|
|
|
|
|
|
71
|
|
|
|
80
|
|
|
|
-
|
|
|
|
-
|
|
|
|
80
|
|
Total
operating expenses
|
|
|
1,181
|
|
|
|
219
|
|
|
|
552
|
|
|
|
1,952
|
|
|
|
756
|
|
|
|
216
|
|
|
|
565
|
|
|
|
1,537
|
|
Operating
income
|
|
|
1,141
|
|
|
|
173
|
|
|
|
58
|
|
|
|
1,372
|
|
|
|
468
|
|
|
|
126
|
|
|
|
55
|
|
|
|
649
|
|
Interest
expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(228
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(130
|
)
|
Other
financial items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
329
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(619
|
)
|
Income
before taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,473
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100
|
)
|
Income
taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(120
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
Gain
on issuance of shares by subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,353
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(123
|
)
|
Total
operating revenues
In
US $millions
|
2009
|
|
2008
|
|
Increase
|
|
|
|
|
|
|
|
|
Mobile
units
|
2,251
|
|
1,144
|
|
+97
|
%
|
Tender
rigs
|
392
|
|
342
|
|
+15
|
%
|
Well
services
|
610
|
|
620
|
|
-2
|
%
|
Total
operating revenues
|
3,253
|
|
2,106
|
|
+54
|
%
|
Total
operating revenues increased from $2.11 billion in 2008 to $3.25 billion in
2009. Total operating revenues are predominantly contract revenues with
additional, relatively small amounts of reimbursables and other
revenue.
Total
operating revenues in the mobile unit segment increased by $1.11 billion from
2008 to 2009. The number of drilling units in the mobile units segment increased
from 14 at December 31, 2008 to 17 at December 31, 2009. Four new
semi-submersible rigs were delivered and started operation during the period
(
West Phoenix, West Aquarius,
West Taurus
and
West
Eminence
) along with one ultra-deepwater drillship (
West Capella
). The jack-up
rig
West Ceres
was sold
and the jack-up rig
West
Atlas
was destroyed in a fire. Although the new units were delivered over
the course of the year and some did not contribute fully to operating revenues
during the year, the additional revenue generated by the new units, net of the
rigs disposed of, amounted to $759 million. Average economic utilization of the
fleet decreased from 92% in 2008 to 82% in 2009. The decrease is related to
several of our jack-up units being stacked in the period as well as the
generally lower economic utilization associated with start- up for some of our
new units. Average dayrates increased from $230,000 in 2008 to $330,000 in 2009.
The increase in average dayrates is related to the increase in our
semi-submersible rig fleet, which achieve higher dayrates than our jack-up
units.
In the
tender rig operating segment, operating revenues increased by 15% from 2008 to
2009. The increase was mainly related to increased dayrates, which increased by
approximately $20,000 per day to an average of $115,000 per day in 2009. The
delivery of the
tender
rig
T11,
which began
operations in the second quarter of 2008, also contributed to the increase.
These dayrate increases were partly offset by a decline in economic utilization
from 98% in 2008 to 93% in 2009.
Total
operating revenues for well services decreased from $620 million in 2008 to $610
million in 2009. A significant portion of well services activity takes place in
Norway and operating revenues in Norwegian Kroner increased from NOK2.6 billion
in 2008 to NOK2.8 billion in 2009. The Norwegian content represented
approximately 73 percent of total revenues and revenues are generally fairly
stable.
Gain
on sale of assets
In 2009
there were gains on the disposals of the jack-up rigs
West Ceres
($21 million) and
West Atlas
($58
million), the former being sold and the latter being a total insured loss
following a fire. Also in 2009 there was a $4 million gain on the sale of our
interest in the Chestnut field and a loss of $12 million due to the PPL shipyard
exercising its purchase option on the jack-up rig
West Elara
. In 2008, the
jack-up rig
West Titania
was sold and a gain of $80 million was recorded. All of these units were
in the mobile units operating segment.
Total
operating expenses
In
US$ millions
|
|
2009
|
|
|
2008
|
|
|
Increase
|
|
|
|
|
|
|
|
|
|
|
|
Mobile
units
|
|
|
1,181
|
|
|
|
756
|
|
|
|
+56
|
%
|
Tender
rigs
|
|
|
219
|
|
|
|
216
|
|
|
|
+1
|
%
|
Well
services
|
|
|
552
|
|
|
|
565
|
|
|
|
-2
|
%
|
Total
operating expenses
|
|
|
1,952
|
|
|
|
1,537
|
|
|
|
+27
|
%
|
Total
operating expenses increased from $1.54 billion in 2008 to $1.95 billion in
2009, with the increase mainly in the mobile units segment. Total
operating expenses consist of rig operating expenses, depreciation, reimbursable
expenses and general and administrative expenses. Total general and
administrative expenses increased to $149 million in 2009 compared to $126
million in of 2008. Reimbursable expenses in each segment were closely in line
with reimbursable revenues.
Total
operating expenses for the mobile units operating segment increased by $425
million from 2008 to 2009. Vessel and rig operating expenses increased by $257
million, mainly due to the new units which came into
operation. Depreciation and amortization increased from $173 million
in 2008 to $333 million in 2009. Of the $160 million increase, $102 million was
related to newbuildings delivered in 2009, while the remaining $58 million was
largely related to newbuildings delivered during 2008 for which we expensed a
full year of depreciation in 2009 compared to reduced periods in 2008. General
and administrative expenses increased from $92 million in 2008 to $106 million
in 2009. The increase is related to our expansion which has made it necessary to
increase corporate staff numbers and establish new offices in different
regions.
Total
operating expenses in the tender rig segment increased slightly from 2008 to
2009. The increase is primarily related to the delivery of the tender rig
T11
in the second quarter of
2008.
Total
operating expenses decreased marginally in the well services segment from $565
million in 2008 to $552 million in 2009. Within this amount, operating expenses
decreased from $425 million in 2008 to $394 million in 2009, reflecting a
similar reduction in operating revenues, leaving the operating margin at
approximately the same level. Reimbursable expenses increased from $104 million
in 2008 to $119 million in 2009. Reimbursable expenses are closely linked to
reimbursable revenues and amounts can fluctuate from period to period. However
we normally earn a margin of approximately 5% on reimbursables within the well
services segment.
Interest
expense
Interest
expense increased from $130 million in 2008 to $228 million in 2009, as a result
of less interest being capitalized in 2009. Interest costs incurred during the
construction of newbuildings are capitalized, and capitalized interest amounted
to $151 million in 2008 compared with $80 million in 2009. The increase in
interest bearing debt over the course of 2009 also contributed to the
increase.
Other
financial items
In
US$ millions
|
2009
|
|
2008
|
|
Change
|
|
|
|
|
|
|
|
|
Interest
income
|
|
78
|
|
|
31
|
|
|
+152
|
%
|
Share
in results of associated companies
|
|
92
|
|
|
15
|
|
|
+513
|
%
|
Gain
on sale of associated companies
|
|
-
|
|
|
150
|
|
|
n/a
|
|
Impairment
loss on marketable securities and investments in associated
companies
|
|
-
|
|
|
(615
|
)
|
|
n/a
|
|
Gain
/ (loss) on derivative financial instruments
|
|
130
|
|
|
(353
|
)
|
|
n/a
|
|
Foreign
exchange gain (loss)
|
|
(25
|
)
|
|
131
|
|
|
n/a
|
|
Other
financial items
|
|
54
|
|
|
22
|
|
|
+145
|
%
|
Total
other financial items
|
|
329
|
|
|
(619
|
)
|
|
n/a
|
%
|
n/a –
percentage change has not been calculated as it is not considered to be
meaningful due to one off or exceptional items.
Interest
income increased by $47 million in 2009, primarily as a result of interest
earned on the investment in the Petromena bond acquired at the end of the first
quarter of 2009, which contributed interest of $44 million.
Our share
in the results of associated companies increased by $77 million in 2009, due to
all of our associated companies generating higher earnings.
In 2008 a
gain of $150 million was recorded on the disposal of shares in Apexindo and
there was an impairment loss of $615 million on our investments in Pride,
Scorpion and SapuraCrest.
There was
a gain on derivative financial instruments of $130 million in 2009, compared
with a loss of $353 million in 2008. We have entered into interest rate swaps,
forward exchange contracts and total return swap agreements, none of which is
accounted for as hedge accounting. The gain in 2009 and the loss in 2008 reflect
movements in interest rates, exchange rates and our share price in these
periods.
In 2009,
there was a foreign exchange loss of $25 million compared to a gain of $131
million in the same period in 2008. The loss in 2009 is primarily related to the
weakening of the US Dollar against the Norwegian Kroner, which adversely affects
the value of our debt denominated in Norwegian Kroner.
Other
financial items amounted to a gain of $54 million in 2009, and include Seahawk
shares received as dividend in kind from Pride amounting to approximately $25
million and a realized gain of $16 million on the partial redemption of the
Petromena NOK2.0 billion bond.
Income
taxes
Income
taxes amounted to a net cost of $120 million in 2009 compared to a net cost of
$48 million in 2008. The Company's effective tax rate was approximately 8.2% in
2009. Due to the write down of $615 million in 2008, which was not tax
deductible, the effective tax rate for 2008 is not comparable. The increase in
tax expense in 2009 is principally due to a higher portion of our income being
generated in taxable (versus nontaxable) jurisdictions or in taxable
jurisdictions with higher tax rates. Specifically, the Company's
recent start up of deepwater units operations in Indonesia, the Philippines and
Nigeria, the increased rig operations in Brazil and Norway and the commencement
of full operations in China for the reporting period have all contributed to
additional taxable income in 2009. Several of the new drilling operations are in
countries which tax drilling operations on the basis of deemed taxable income,
leading to an increase in tax costs compared with the previous year.
Additionally, in 2008 there was a non-taxable gain of $150 million recorded on
the disposal of shares in Apexindo.
Significant
parts of the Company's income and costs are reported in nontaxable jurisdictions
such as Bermuda. The drilling rig operations are normally carried out in taxable
jurisdictions. In the tax jurisdictions where the Company operates, the
corporate tax rate ranges from 16% to 35% (on earned income) and the deemed tax
rate varies from 5% to 8% of revenues. Further, losses in one tax jurisdiction
may not be offset against taxable income in other jurisdictions. Accordingly,
our effective tax rate may differ significantly from period to period depending
on the level of activity in and mix of each of the tax jurisdictions in which
our operations are conducted.
Fiscal
Year Ended December 31, 2008, compared to Fiscal Year Ended December 31,
2007.
The
following table sets forth the Company's operating results for 2008 and
2007:
|
|
Year
ended December 31, 2008
|
|
|
Year
ended December 31, 2007
|
|
In
US $millions
|
|
Mobile
units
|
|
|
Tender
rigs
|
|
|
Well
services
|
|
|
Total
|
|
|
Mobile
units
|
|
|
Tender
rigs
|
|
|
Well
services
|
|
|
Total
|
|
Total
operating revenues
|
|
|
1,144
|
|
|
|
342
|
|
|
|
620
|
|
|
|
2,106
|
|
|
|
837
|
|
|
|
266
|
|
|
|
449
|
|
|
|
1,552
|
|
Gain
on sale of assets
|
|
|
80
|
|
|
|
-
|
|
|
|
-
|
|
|
|
80
|
|
|
|
124
|
|
|
|
-
|
|
|
|
-
|
|
|
|
124
|
|
Total
operating expenses
|
|
|
756
|
|
|
|
216
|
|
|
|
565
|
|
|
|
1,537
|
|
|
|
612
|
|
|
|
169
|
|
|
|
406
|
|
|
|
1,187
|
|
Operating
income
|
|
|
468
|
|
|
|
126
|
|
|
|
55
|
|
|
|
649
|
|
|
|
349
|
|
|
|
97
|
|
|
|
43
|
|
|
|
489
|
|
Interest
expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(130
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(113
|
)
|
Other
financial items
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(619
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11
|
|
Income
before taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
387
|
|
Income
taxes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(48
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
78
|
|
Gain
on issuance of shares by subsidiary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50
|
|
Net
income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(123
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
515
|
|
Total
operating revenues
In
US $millions
|
|
2008
|
|
|
2007
|
|
|
Increase
|
|
|
|
|
|
|
|
|
|
|
|
Mobile
units
|
|
|
1,144
|
|
|
|
837
|
|
|
|
+37
|
%
|
Tender
rigs
|
|
|
342
|
|
|
|
266
|
|
|
|
+29
|
%
|
Well
services
|
|
|
620
|
|
|
|
449
|
|
|
|
+38
|
%
|
Total
operating revenues
|
|
|
2,106
|
|
|
|
1,552
|
|
|
|
+36
|
%
|
Total
operating revenues increased from $1.55 billion in 2007 to $2.11 billion in
2008, with increases in all three operating segments.
Total
operating revenues in the mobile unit segment increased by $307 million to $1.14
billion in 2008. The number of drilling units in the mobile units segment
increased from 10 at December 31, 2007 to 14 at December 31, 2008. Two new
semi-submersible rigs were delivered and started operation during the year
(
West Sirius
and
West Hercules
) along with
one ultra-deepwater drillship (
West Polaris
) and two jack-up
rigs (
West Triton
and
West Ariel
). The
jack-up rig
West
Titania
was sold. Although these units were delivered over the course of
the year and some did not contribute fully to operating revenues during the
year, the additional revenue generated by the new units, net of the rig sold,
amounted to $208 million. The economic utilization of the mobile units fleet
increased overall from 86% in 2007 to 88% in 2008. Average dayrates were also
higher in 2008, although in the latter part of the year the jack-up rig market
weakened to some extent, resulting in lower dayrates as well as periods with
idle units.
In the
tender rig operating segment, operating revenues increased from $266 million in
2007 to $342 million in 2008. The increase was partly due to the delivery of the
newbuilding tender rig
T11,
which began operations in the second quarter of 2008 and contributed $29
million in revenue. In addition, average dayrates for the tender rig fleet were
higher in 2008, although economic utilization declined from 100% in 2007 to 98%
in 2008.
Total
operating revenues for well services increased from $449 million (NOK 2,728
million) in 2007 to $620 million (NOK3,625 million) in 2008, mainly as a result
of higher activity levels in continuing operations and significant contributions
from businesses acquired in the year.
Gain
on sale of assets
A gain on
sale of assets of $80 million was recorded in 2008, arising from the sale of the
jack-up rig
West
Titania
. In 2007, a $124 million gain on sale of assets resulted from the
sale of the two FPSO's
Crystal
Ocean
and
Crystal
Sea
. These three units were all in the mobile units operating
segment.
Total
operating expenses
In
US$ millions
|
|
2008
|
|
|
2007
|
|
|
Increase
|
|
|
|
|
|
|
|
|
|
|
|
Mobile
units
|
|
|
756
|
|
|
|
612
|
|
|
|
+24
|
%
|
Tender
rigs
|
|
|
216
|
|
|
|
169
|
|
|
|
+28
|
%
|
Well
services
|
|
|
565
|
|
|
|
406
|
|
|
|
+39
|
%
|
Total
operating expenses
|
|
|
1,537
|
|
|
|
1,187
|
|
|
|
+29
|
%
|
Total
operating expenses increased from $1.19 billion in 2007 to $1.54 billion in
2008, with increases in all three operating segments. Total operating expenses
consist of rig operating expenses, depreciation, reimbursable expenses and
general and administration expenses. Total general and administration expenses
increased to $127 million in 2008 compared with $110 million in 2007.
Reimbursable expenses in each segment were closely in line with reimbursable
revenues.
Total
operating expenses in the mobile units segment increased from $612 million in
2007 to $756 million in 2008. Vessel and rig operating expenses increased by $86
million in the same period mainly reflecting the expenses of the new units that
came into operation during the 2008 period. Reimbursable expenses are at the
same level on a year to year comparison and the margin is in the range of 5% to
10%. Depreciation and amortization increased from $135 million in 2007 to $173
million in 2008. Of the increase of $38 million, $25 million was related to our
newbuildings delivered in 2008, while the majority of the remaining $13 million
was related to newbuildings delivered during 2007 for which we have expensed a
full year of depreciation in 2008 compared to only part of the year in 2007.
General and administrative expenses for the mobile units segment increased from
$73 million in 2007 to $92 million in 2008. The increase is related to an
increase in geographical operations which require larger onshore
support.
Total
operating expenses for the tender rig segment increased from $169 million in
2007 to $216 million in 2008. Vessel and rig operating expenses increased in the
same period from $101 million to $134 million. The increase of $33 million is
primarily related to the new unit
T11,
which commenced drilling operations in the second quarter of 2008. Depreciation
and amortization amounted to 42 million in 2008, an increase of $3 million
compared to the preceding year. The increase is related to the delivery of
T11.
Total
operating expenses for the well services division increased from $286 million in
2007 to $425 million in 2008. The increase is related to a corresponding
increase in operating revenues. Depreciation and amortization increased from $9
million in 2007 to $19 million in 2008. Well Services has been involved in
several acquisitions during 2008. The acquired companies have owned a
significant amount of fixed assets that are depreciated based on a straight line
basis, which has contributed to the increase.
Interest
expense
Interest
expense increased from $113 million in 2007 to $130 million in 2008 as a result
of the increase in interest bearing debt used to finance new drilling units and
acquisitions, partly offset by the 1.8% reduction in the weighted average
interest rate payable in the year. In addition to the interest
expense, interest costs incurred during the construction of newbuildings are
capitalized, and capitalized interest amounted to $153 million in 2008 compared
with $134 million in 2007.
Other
financial items
In
US$millions
|
|
2008
|
|
|
2007
|
|
|
Change
|
|
|
|
|
|
|
|
|
|
|
|
Interest
income
|
|
|
31
|
|
|
|
24
|
|
|
|
+29
|
%
|
Share
in results of associated companies
|
|
|
15
|
|
|
|
23
|
|
|
|
-35
|
%
|
Gain
on sale of associated companies
|
|
|
150
|
|
|
|
-
|
|
|
|
n/a
|
|
Impairment
loss on marketable securities and investments in associated
companies
|
|
|
(615
|
)
|
|
|
-
|
|
|
|
n/a
|
|
Gain
/ (loss) on derivative financial instruments
|
|
|
(353
|
)
|
|
|
7
|
|
|
|
n/a
|
|
Foreign
exchange gain (loss)
|
|
|
131
|
|
|
|
(53
|
)
|
|
|
n/a
|
|
Other
financial items
|
|
|
22
|
|
|
|
10
|
|
|
|
+120
|
%
|
Total
other financial items
|
|
|
(619
|
)
|
|
|
11
|
|
|
|
n/a.
|
|
n/a –
percentage change has not been calculated as it is not considered to be
meaningful due to one off or exceptional items
Interest
income increased in 2008 as a result of increased levels of cash on deposit,
consisting mainly of restricted cash.
The share
in results of associated companies declined in 2008 due to the disposal during
the year of our interest in Apexindo and the liquidation of Lisme AS, a
Norwegian holding company in which we had a 44% interest, in 2007. The sale of
shares in Apexindo resulted in a gain on disposal of $150 million.
At
December 31, 2008, we beneficially owned shares, including share purchase
agreements, in Pride, Scorpion and SapuraCrest. At December 31, 2008, we
determined that the fair value of these investments was below their carrying
value and that there was little prospect for a recovery in values in 2009.
Accordingly, in 2008 we recognized an impairment charge of $615 million relating
to these investments.
We have
entered into interest rate swaps, forward exchange contracts and total return
swap agreements, or TRS, none of which is accounted for as hedge accounting.
Most of these arrangements were established in 2008 and the fair value of these
derivative financial instruments at December 31, 2008 is reflected in the
consolidated financial statements, resulting in fair value losses totaling $353
million. Of this total, $177 million arises from mark-to-market adjustments on
our interest rate swaps (notional principal $1.78 billion at December 31, 2008)
and $117 million from mark-to-market adjustments on our forward exchange
contracts (forward sales of $0.47 billion at December 31, 2008). The remaining
$59 million loss relates to a TRS agreement indexed to the market price of
4,500,000 of our common shares.
The
foreign exchange gain in 2008 mainly results from debt denominated in Norwegian
Kroner and the weakening of the Norwegian Kroner against the U.S.
Dollar.
Other
financial items consist of gains on the sale of marketable
securities.
Income
taxes
Income
taxes amounted to a net cost of $48 million in 2008. In 2007, income taxes
amounted to a net income of $78 million, mainly as a result of the restructuring
of several rig-owning companies, which resulted in a non-recurring tax benefit
of $75 million. For 2008, restructuring of rig ownership resulted in a
non-recurring tax benefit of $43 million compared to a benefit of $75 million
realized in 2007. The change in the Company's effective tax rate from a benefit
of approximately 20.2% in 2007 to a cost of approximately 48.5% in 2008 was
principally due to a higher portion of our income being generated in taxable
jurisdictions in 2008, a smaller benefit arising from the
restructuring
of the Company's rig-assets, and the nondeductible impairment loss on marketable
securities which offset the nontaxable gain on the disposal of Apexindo shares
earlier in the year. Impairment losses on marketable securities and gains and
losses on the sales of shares in associated companies are reported in nontaxable
jurisdictions. The Company's recent start up of jack up operations in Australia
contributed to increased current tax in 2008.
Significant
parts of the Company's income and costs are reported in nontaxable jurisdictions
such as Bermuda. The drilling rig operations are normally carried out in taxable
jurisdictions. In the tax jurisdictions where the Company operates the corporate
tax rate ranges from 16% to 35% (on earned income) and the deemed tax rate
varies from 5% to 8% of revenues. Further, losses in one tax jurisdiction may
not be offset against taxable income in other jurisdictions. Accordingly, our
effective tax rate may differ significantly from period to period depending on
the level of activity in and mix of each of the tax jurisdictions in which our
operations are conducted.
Gain
on issuance of shares by subsidiary
Our
subsidiary Seawell concluded share issuances in both 2008 and 2007, raising a
total of NOK190 million in 2008 and NOK275 million in 2007. We did not fully
participate in the 2008 share issuance and as a result our holding in Seawell
was reduced from 80% to 74%. We did not participate in the 2007 share issuance,
which resulted in a reduction in our holding from 100% to 80%. These share
issuances resulted in gains of $25 million and $50 million being recorded in
2008 and 2007, respectively. Due to a change in U.S. GAAP, any gains arising on
the future issue of shares by Seawell while it is our subsidiary will be
accounted for in shareholders equity and not in the statement of
operations.
B.
LIQUIDITY AND CAPITAL RESOURCES
We
operate in a capital intensive industry. Our purchase of the units
acquired from Greenwich, discussed above in Item4.A – "History and Development
of the Company", was financed through a combination of equity raised and debt
issued. Our subsequent investment in newbuildings and our acquisition of other
companies have been financed through a combination of equity issuances, bond and
convertible bond offerings, and borrowings from commercial banks. Our liquidity
requirements relate to servicing our debt, funding investment in drilling units,
funding working capital requirements and maintaining adequate cash reserves to
mitigate the effects of fluctuations in operating cash flows. Most of our
contract and other revenues are received monthly in arrears, and most of our
operating costs are paid on a monthly basis.
Our
funding and treasury activities are conducted within corporate policies to
maximize returns while maintaining appropriate liquidity for our requirements.
Cash and cash equivalents are held mainly in U.S. Dollars, Norwegian Kroner,
Brazilian Real, Australian Dollars, Euros, Singapore Dollars and Pound
Sterling.
Our
short-term liquidity requirements relate to servicing our debt and funding
working capital requirements. Sources of liquidity include cash balances,
restricted cash balances, short-term investments, amounts available under
revolving credit facilities and contract and other revenues. We believe that
contract and other revenues will generate sufficient cash flow to fund our
anticipated debt service and working capital requirements for the short and
medium terms.
Our
long-term liquidity requirements include funding the equity portion of
investments in new drilling units, and repayment of long-term debt balances
including those relating to the following borrowings of the Company and its
consolidated subsidiaries:
Secured credit
facilities
- $185
million secured term loan facility due 2010
- $800
million secured term loan facility due 2013
- $100
million secured term loan facility due 2010
- $585
million secured term loan facility due 2012
- $1.50
billion secured credit facility due 2014
- NOK1.50
billion senior debt facility due 2012
- $100
million secured term loan facility due 2014
- $1.50
billion senior secured credit facility due 2014
Ship Finance secured credit
facilities
- $170
million secured term loan facility due 2013 (VIE)
- $700
million secured term loan facility due 2013 (VIE)
- $1.40
billion secured term loan facility due 2013 (VIE)
Unsecured
bonds
- $30
million unsecured bond due 2012
- NOK500
million unsecured bond due 2012
- NOK800
million unsecured bond due 2011
Convertible
bonds
- $1.00
billion 3.625% unsecured convertible bonds due 2012
- $500
million 4.875% unsecured convertible bonds due 2014
CIRR
loans
- NOK1.75
billion Commercial Interest Reference Rate ("CIRR") credit facilities due
2016
- NOK1.01
billion Commercial Interest Reference Rate ("CIRR") credit facilities due
2020
At
December 31, 2009, we had remaining contractual commitments relating to nine
newbuilding contracts totaling $1.68 billion (December 31, 2008: $2.89
billion).
As of
December 31, 2009, we had cash and cash equivalents totaling $602 million (2008:
$657 million), including $142 million of restricted cash (2008: $281 million).
In the year ended December 31, 2009, we generated cash from operations of $1.45
billion (2008: $0.40 billion), used $0.92 billion in investing activities (2008:
$3.85 billion) and used $0.45 billion in financing activities (2008: $2.06
billion).
During
the year ended December 312009 we paid cash dividends of $0.50 per common share,
or a total of $0.20 billion (2008: $0.69 billion). A dividend of
$0.55 per common share totaling $0.22 billion was declared on February 25, 2010,
and paid on March 26, 2010.
To the
extent that we enter into significant further investments and/or newbuilding
commitments we expect that we will require additional issuances of equity and/or
new debt to meet our capital requirements. Without these new investments, we
believe that the cash that we generate from our operations will be sufficient to
cover our existing commitments to fund newbuildings, support our projected
growth including meeting our working capital needs, as well as permit us to pay
dividends to our stockholders and to pay our debt in accordance with the
existing maturity profile - see Item 8.A "Consolidated Statements and Other
Financial Information – Dividend Policy". A deterioration in our operating
performance, inability to obtain cost efficiencies, lack of success in adding
new contracts to our backlog, failure to complete our remaining newbuilding
program on time and within budget, as well as numerous other factors detailed
above in "Risk Factors" could limit our ability to further the growth of our
business, to meet working capital requirements, and to pay
dividends.
We plan
to pay our debt as it becomes due, although our leverage ratio will largely be
dependent upon our contract backlog and financial outlook. Any decision to
refinance debt maturing in future years will take the above factors into
consideration, and we believe it is likely that we will refinance a portion of
our debt.
Seadrill
Limited, as the parent company of its operating subsidiaries, is not a party to
any drilling contracts directly and is therefore dependent on receiving cash
distributions from its subsidiaries to meet its payment obligations. Cash
dividend payments are regularly transferred by the various subsidiaries. Surplus
cash held in subsidiaries is transferred to Seadrill Limited by intercompany
loans and/or dividend payments.
Borrowings
As of
December 31, 2009, we had total outstanding borrowings of $7.40 billion under
our credit facilities, at an average interest rate of 2.77%. Outstanding
borrowings at December 31, 2008, totaled $7.44 billion at an average interest
rate of 3.53%.
In
February 2005 Smedvig ASA ("Smedvig"), which we acquired in 2006, raised US$30.0
million through the issuance of a seven year bond which matures in February
2012. The bond bears quarterly interest of London Inter-Bank Offer Rate, or
LIBOR, plus a margin.
In July
2005 we entered into a $185 million secured term loan facility to partly fund
the acquisition of two jack-up rigs under construction. At December 31, 2009,
the outstanding balance was $45 million (2008: $72 million). The facility bears
interest at LIBOR plus a margin and is repayable over a term of five
years.
In August
2005 we entered into a $300 million secured loan facility with a syndicate of
banks. The facility was amended and increased in 2006 to $800
million. At December 31, 2009, the outstanding balance was $725
million (2008: $668 million). The facility consists of two tranches with
differing interest rates and repayment schedules, and each tranche bears
interest at LIBOR plus a margin. The final repayment of $368 million
is due in December 2013.
In
September 2005 we raised NOK500 million through the issuance of a seven year
bond, which matures in September 2012. The bond bears quarterly interest of
NIBOR (Norwegian Inter-Bank Offer Rate) plus a margin. At December 31, 2009, the
outstanding balance was $87 million (2008: $71 million).
In
October 2005 we entered into a $100 million secured term loan facility to partly
fund the acquisition of newbuilding jack-up rigs. At December 31, 2009, the
outstanding balance was $42 million (2008: $92 million). The facility bears
interest at LIBOR plus a margin and is repayable over a term of five
years.
In
December 2006 we entered into a $585 million secured term loan facility with a
syndicate of banks to partly fund the acquisition of eight tender rigs, which
have been pledged as security. At December 31, 2009, the outstanding balance was
$436 million (2008: $486 million). The facility bears interest at LIBOR plus a
margin and is repayable over a term of six years. At maturity a balloon payment
of $300 million is due.
In
February 2007, our fully consolidated VIE Rig Finance II Ltd (which is
wholly-owned by Ship Finance, a related party) entered into a $170 million
secured term loan facility with a syndicate of banks, in order to partly fund
the acquisition of the jack-up rig
West Prospero
. At December
31, 2009, the outstanding amount under the facility was $111 million (2008: $121
million). The facility bears interest at LIBOR plus a margin and is repayable
over a term of six years. The facility is secured by the assets of Rig Finance
II Ltd.
In June
2007 we entered into a $1.50 billion senior secured loan facility with a
syndicate of banks to partly fund the acquisition of four drilling rigs
West Alpha, West Epsilon
,
West Navigator
and
West Venture,
which
have been
pledged
as security. At December 31, 2009, the outstanding balance was $1.14 billion
(2008: $1.34 billion). The facility bears interest at LIBOR plus a margin and is
repayable over a term of seven years. A final payment of $600 million
is due on maturity.
In
November 2007 we issued at par $1.00 billion of convertible bonds, the proceeds
of which were used to fund our construction program and for general corporate
purposes. Interest on the bonds is fixed at 3.625% per annum, payable
semi-annually in arrears. The bonds are convertible into Seadrill Limited common
shares by the holders at any time up to 10 banking days prior to November 8,
2012. The conversion price set at the time of issuance was $34.474 per share,
representing a 45% premium to the share price at the time. Since then, dividend
distributions have reduced the conversion price to $30.78. Unless previously
redeemed, converted or purchased and cancelled, the bonds mature in November
2012.
In
December 2007 our 73.8% subsidiary Seawell entered into a NOK1.50 billion
multi-tranche Senior Debt facility with a syndicate of banks to finance working
capital. At December 31, 2009, the amount outstanding under this facility was
NOK1.21 billion, equivalent to $211 million (2008: NOK1.42 billion equivalent to
$203 million). The facility bears interest at NIBOR plus a margin and is
repayable over a term of five years.
In April
2008 we entered into a $100 million secured term loan facility with two banks to
partly fund the acquisition of a tender rig. At December 31, 2009, the
outstanding amount on this facility was $86 million (2008: $97 million). The
facility bears interest at fixed rates and is repayable over a term of six
years. A final payment of $60 million is due on maturity.
In April
2008 we entered into a CIRR term loan for NOK850 million with Eksportfinans ASA,
the Norwegian export credit agency. The loan bears interest at a fixed rate of
4.56% and is repayable over a term of eight years. The outstanding balance at
December 31, 2009, was NOK750 million, equivalent to $121 million (2008: NOK800
million, equivalent to $114 million).
In June
2008 we entered into a CIRR term loan for NOK904 million with Eksportfinans ASA.
The loan bears fixed interest at a fixed rate of 4.15% and is repayable over a
term of eight years. The outstanding balance at December 31, 2009, was NOK744
million, equivalent to$129 million (December 31, 2008: NOK850 million,
equivalent to $121 million).
In July
2008 we entered into a CIRR term loan for NOK1.01 billion with Eksportfinans
ASA. The loan bears fixed interest at a fixed rate of 4.15% and is repayable
over a term of twelve years. The outstanding balance at December 31, 2009, was
NOK927 million, equivalent to $160 million (December 31, 2008: NOK1.01 billion,
equivalent to $144 million).
In July
2008 our fully consolidated VIE SFL West Polaris Limited (which is wholly-owned
by Ship Finance) entered into a $700 million secured term loan facility with a
syndicate of banks, in order to partly fund the acquisition of the newbuilding
drillship
West Polaris
.
At December 31, 2009, the outstanding balance under the facility was $619 (2008:
$688 million). The facility bears interest at LIBOR plus a margin and is
repayable over a term of five years. The facility is secured by the assets of
SFL West Polaris Limited.
In
September 2008 our fully consolidated VIE SFL Deepwater Ltd (which is
wholly-owned by Ship Finance) entered into a $1.40 billion secured term loan
facility with a syndicate of banks, in order to partly fund the acquisition of
the two semi-submersible rigs
West Taurus
and
West Hercules.
At December
31, 2009, the outstanding balance under the facility was $1.26 billion (2008:
$1.14 billion). The facility bears interest at LIBOR plus a margin and is
repayable over a term of five years. The facility is secured by the assets of
SFL Deepwater Ltd.
In June
2009 we entered into a $1.50 billion secured facility with a group of various
commercial lending institutions and export credit agencies. The loan is secured
by first priority mortgages on two ultra-deepwater semi-submersible drilling
rigs (
West Aquarius
and
West Sirius
), one
deepwater drillship (
West
Capella
) and one jack-up drilling rig (
West Ariel
). The outstanding
balance at December 31, 2009, was $659 million, with $753 million still
available to draw down. The facility bears interest at LIBOR plus a margin and
is repayable over a term of five years.
In
September 2009 we issued at par $500 million of senior unsecured convertible
bonds, the proceeds of which are intended to be used for future growth. Interest
on the bonds is fixed at 4.875%, payable semi-annually in arrears. The bonds are
convertible into Seadrill Limited common shares at any time up to ten banking
days prior to September 29, 2014. The conversion price at the time of issuance
was $25.18 per share, representing a 35% premium to the share price at the time.
Since then, dividend distributions have reduced the conversion price to $23.97.
For accounting purposes $105 million has been allocated to the bond equity
component and $395 million to the bond liability component, due to the cash
settlement option stipulated in the bond agreement. Unless previously redeemed,
converted or purchased and cancelled, the bonds mature in September
2014.
In
October 2009 we issued a NOK800 million senior unsecured two year bond. The bond
bears interest at NIBOR plus a margin and the proceeds are for general corporate
purposes. At December 31, 2009, the outstanding balance was $134
million.
In the
year ended December 31, 2009 ,we repaid in full (i) a short-term bridging loan
($792 million outstanding at December 31 2008), (ii) the loan entered into by
our fully consolidated VIE Rig Finance Ltd to partly fund the acquisition of
West Ceres
, which was
sold in July 2009 ($107 million outstanding at December 31, 2008) and (iii) two
floating rate bonds totaling NOK1.00 billion which matured ($144 million
outstanding at December 31, 2008).
In
connection with the above three CIRR fixed interest term loans totaling NOK2.37
billion, three collateral cash deposits equal to the total outstanding loan
balances have been established with commercial banks. The collateral cash
deposits are reduced in parallel with repayments of the CIRR loans and receive
fixed interest at the same rates as those paid on the CIRR loans. The collateral
cash deposits are classified as "restricted cash" on the balance sheet, and the
effect of these arrangements is that the CIRR loans have no effect on net
interest bearing debt.
In
addition to security provided to lenders in the form of pledged assets, which is
the case for all of our credit facilities and bank loans, agreements relating to
long-term debt generally contain financial covenants. The main financial
covenants contained in our loan agreements are as follows:
|
·
|
Minimum
liquidity requirements: to maintain cash and cash equivalents of at least
$100 million within the group.
|
|
·
|
Interest
coverage ratio: to maintain an EBITDA to interest expense ratio of
2.5:1.
|
|
·
|
Current
ratio: to maintain a current assets to current liabilities ratio of at
least 1:1. Current assets are defined as book value less minimum
liquidity, but including up to 20% of shares in listed companies of which
we own 20% or more. Current liabilities are defined as book value less the
current portion of long term debt.
|
|
·
|
Equity
ratio: to maintain a total equity to total assets ratio of at least 30%.
Both equity and total assets are adjusted for the difference between book
and market values of drilling units.
|
|
·
|
Leverage
ratio: to maintain a ratio of net debt to EBITDA no greater than 4.5:1.
Net debt is calculated as all interest bearing debt less cash and cash
equivalents excluding minimum liquidity requirements.
|
For the
purposes of the above tests, EBITDA is defined as 12 months trailing earnings
before interest, taxation, depreciation and amortization.
The main
covenants for the Company's outstanding bonds are to maintain adjusted
shareholders' equity of at least $1.50 billion and a ratio of adjusted
shareholders' equity to total liabilities of at least 30% to 40%. Adjusted
shareholder's equity is book value of equity adjusted for the difference between
book and market values of drilling units.
.
We are in
compliance with all financial loan covenants as at December 31,
2009. At December 31, 2009, three month U.S. Dollar LIBOR was 0.25%
(2008: 1.43%) and three month NIBOR was 2.19% (2008: 3.97%).
Derivatives
We use
financial instruments to reduce the risk associated with fluctuations in
interest and foreign exchange rates. Most of these agreements do not qualify for
hedge accounting, and for these any changes in the fair values of the swap
agreements are included in the Consolidated Statement of Operations under
"gain/(loss) on derivative financial instruments". Two of our fully-consolidated
VIEs have executed interest rate cash flow hedges in the form of interest rate
swaps. Movements in the fair value of these hedging swaps are reflected in
"Accumulated other comprehensive income (loss)."
At
December 31, 2009, the Company and its consolidated subsidiaries, including
VIEs, had entered into interest rate swap contracts with a combined outstanding
principal amount of $4.12 billion at rates between 2.055% per annum and 4.629%
per annum. The overall effect of these swaps is to fix the interest
rate on $4.12 billion of floating rate debt at a weighted average interest rate
of 3.26% per annum. At December 31, 2009, our net exposure to short term
fluctuations in interest rates on our outstanding debt was $0.88 billion, based
on our total net interest bearing debt of $6.59 billion less the $4.12 billion
notional principal of our floating to fixed interest rate swaps, less the $1.59
billion in fixed interest loans.
Also at
December 31, 2009, we had entered into forward exchange contracts to sell
approximately $504 million in exchange for Norwegian Kroner and Singapore
Dollars between January 2010 and September 2012, at exchange rates ranging from
NOK5.71 to NOK6.40 per U.S. Dollar and from SGD1.39 to SGD1.42 per U.S.
Dollar.
In June
and July 2008 we entered into Total Return Swap ("TRS") agreements with a total
of 4,500,000 of our own common shares as the underlying security. The
agreements were scheduled to expire in December 2008 and the reference prices
were in a range of NOK141.2 to NOK157.8 per share. In November 2008 these
contracts were terminated and we simultaneously entered into a new TRS agreement
with 4,500,000 of our common shares as underlying security, with an agreed
reference price of NOK56.70 per share and an expiration date in February 2009.
In February 2009, we entered into a new TRS agreement for the same number of
shares with expiration date in August 2009 and the new reference price was
NOK61.3 per share. In August 2009, we entered into a new TRS agreement for the
same number of shares with an expiration date in February 2010 and an agreed
reference price of NOK98.44 per share. In February 2010 these contracts were
settled and we simultaneously entered a new TRS agreement for 3,500,000 of our
common shares as underlying security with an agreed reference price of NOK125.70
per share and an expiration date in February 2011. The settlement amount for the
TRS transaction will be (A) the market value of the shares at the date of
settlement plus all dividends paid by the Company between entering into and
settling the contract, less (B) the reference price of the shares agreed at the
inception of the contract plus the counterparty's financing costs. Settlement
will be either a payment from or to the counterparty, depending on whether (A)
is more or less than (B). There is no obligation for us to purchase any shares
under the agreement and this arrangement has been recorded as a derivative
transaction, with the fair value of the TRS recognized as an asset or liability
as appropriate, and changes in fair values recognized in the consolidated
statement of operations.
In
addition to the above TRS transactions, we may from time to time enter into
short-term TRS arrangements relating to securities in other companies. The above
TRS indexed to our own common shares was our only TRS agreement as at December
31, 2009.
Equity
At
December 31, 2009, 2008 and 2007, our issued and fully paid share capital
amounted to 399,133,216 common shares of par value $2.00 each, totaling $798
million. In 2007, we had two issuances of equity totaling 16 million new common
shares for total proceeds of approximately $303 million. We had no issuances of
equity in 2008 and 2009.
At
December 31, 2009, we were holding 110,200 of our common shares as treasury
shares (2008: 717,800; 2007: 608,700) and our net outstanding share capital
amounted to $798 million (2008: $797 million; 2007: $797 million). A share
repurchase program was approved by the Board in 2007, authorizing us to buy back
shares which may be either cancelled, or held as treasury shares to meet our
obligations relating to our share option scheme. Under the program we purchased
600,000 shares in the year ended December 31, 2008, and 950,000 shares in the
year ended December 31, 2007. No shares were purchased in the year ended
December 31, 2009. As of December 31, 2009, we have not cancelled any shares and
have used 1,439,800 of them to meet our share option scheme
obligations.
In May
2005 a general meeting of the Company approved authorizing the Board of
Directors to establish and maintain an employee share option scheme, or the
Option Scheme, in order to encourage the holding of shares in Seadrill by
individuals including directors, officers and employees of Seadrill and its
subsidiaries. The Board of Directors has made a number of grants
pursuant to rules established to implement the Option Scheme. As of December 31,
2009, we have granted 8,340,667 options, of which 6,199,833 remain outstanding.
The fair value cost of options granted is recognized in the statement of
operations as an expense, with a corresponding amount credited to additional
paid in capital (see Note 28 to the Consolidated Financial Statements). The
additional paid-in capital arising from share options was $16 million in the
year ended December 31, 2009 (2008: $15 million; 2007: $15
million).
As at
December 31, 2009,our total additional paid-in capital amounted to $2.12 billion
(2008: $1.99 billion; 2007: $1.98 billion), of which $1.96 billion arises from
shares issued at a premium, with the remaining balance attributable to the
Option Scheme, purchases and sales of treasury shares and the equity component
of the 4.875% convertible bond.
As at
December 31, 2009, we were party to a TRS agreement indexed to 4,500,000 of our
shares, whereby we are exposed to movements in the price of our shares (see
"Derivatives" above). In February 2010 the TRS agreement was settled and we
entered into a new TRS agreement indexed to 3,500,000 of our
shares.
Since
January 1, 2010, we have issued 13,155,000 new common shares for total proceeds
of approximately $323 million, which will be used to partly finance the
potential acquisitions of the CJ70 design jack-up rig and further investment in
Scorpion (see Item 5.F "Contractual Obligations" below) and general
purposes.
C.
RESEARCH AND DEVELOPMENT, PATENTS AND LICENSES, ETC.
We do not
undertake any significant expenditure on research and development, and have no
significant interests in patents or licenses.
D.
TREND INFORMATION
The
slowdown in the world economy following the credit crisis in the latter part of
2008 adversely affected activity levels in most areas of the offshore drilling
industry. Although oil and gas prices increased significantly through 2009, oil
companies retain a cautious attitude regarding the sustainability of
the short-term price recovery. As such, and in spite of the fact that most oil
companies express confidence in the long-term outlook for their business,
uncertainty persists surrounding investment in exploration and production
activities, resulting in postponement of drilling activities.
The area
of the market and type of rig most impacted by the drop in activity has been
benign environment jack-up rigs, where a significant number of units were
stacked in the Gulf of Mexico, Africa and Southeast Asia regions. The nature of
the jack-up market is that drilling assignments generally have a duration
lasting from three to twelve months. The wells that are drilled are often
tiebacks to existing infrastructure, which in many cases implies a higher
break-even oil price for marginal projects. Furthermore, the demand side also
consists of smaller operators, who are more dependent on funding through the
financial markets. As a result, the market for benign environment jack-ups was
adversely impacted by the uncertainty regarding future oil and gas prices and
challenging financial markets. There have been, however, positive signs over the
last few months in the form of increased activity from oil companies, with core
demand being focused on high specification and modern assets. This has resulted
in improved market conditions for new high specification jack-up rigs, which has
positively impacted dayrates for such equipment, although demand for older
jack-ups has remained weak with an uncertain near term outlook.
The
market for dynamically positioned deepwater units has been less affected, due to
the limited availability of such rigs in the short term and the continued
long-term focus on this area of activity by super majors and national oil
companies. Although there were fewer fixtures in 2009 compared to 2008, those
that were announced, including sublets between oil companies, were at dayrates
of approximately $500,000, which is relatively high by historical standards. In
the first quarter 2010, we have seen market rates decreasing to around $450,000
per day. We believe that the long-term outlook for dynamically positioned
deepwater rigs remains promising, due to expected strong demand, particularly in
Brazil, West Africa, and the U.S. and Mexican Gulf of Mexico. However, in the
near term we would not be surprised if the market was presented with some weak
fixtures from smaller offshore drilling companies with short-term availability,
due to financial strain and/or lack of operational track record in deep
water.
The
drop in shallow water activity, that severely affected the market for jack-up
rigs, also adversely affected the market for tender rigs. Like
jack-ups, tender rigs that have come off contract have been warm stacked due to
oil companies postponing drilling activity in response to the uncertainty
surrounding the direction of oil and gas prices. However, market enquiries from
oil companies in 2010 suggest that demand is picking up, reinforcing what we
believe is an attractive medium-term outlook for tender rigs. We have so far
this year secured employment for the newbuild tender rig
T12
for a one year assignment
in Thailand. We believe that the market will continue to improve and offer
opportunities to build additional order backlog and earnings visibility for this
asset class.
E.
OFF BALANCE SHEET ARRANGEMENTS
At
December 31, 2009, as described above, we were party to a TRS agreement indexed
to our own common shares. The fair value of this position as at December 31,
2009, is reflected in the Consolidated Financial Statements included in Item 18
of this Annual Report.
At
December 31, 2008, in addition to the TRS agreement indexed to our own shares,
we had forward purchase contracts for 16,300,000 shares in Pride. The fair
values of this position and the TRS agreement as at December 31, 2008, are
reflected in the Consolidated Financial Statements included in Item 18 of this
Annual Report. The forward purchase contracts for shares in Pride became
effective in July 2009, and the shares are included in our Consolidated Balance
Sheet as at December 31, 2009. We were not party to any other material off
balance sheet arrangements at December 31, 2009, and December 31,
2008.
F.
CONTRACTUAL OBLIGATIONS
At
December 31, 2009, we had the following contractual obligations and
commitments:
|
|
Payment
due by period
|
|
(In
US$millions)
|
|
Less
than
1
year
|
|
|
1 –
3
years
|
|
|
3 –
5
years
|
|
|
After
5
years
|
|
|
Total
|
|
3.625%
convertible bonds due 2012
|
|
|
-
|
|
|
|
1,000
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,000
|
|
4.875%
convertible bonds due 2014
(1)
|
|
|
-
|
|
|
|
-
|
|
|
|
500
|
|
|
|
-
|
|
|
|
500
|
|
Interest
bearing debt
|
|
|
774
|
|
|
|
1,961
|
|
|
|
3,103
|
|
|
|
159
|
|
|
|
5,997
|
|
Total
debt repayments
(1)
|
|
|
774
|
|
|
|
2,961
|
|
|
|
3,603
|
|
|
|
159
|
|
|
|
7,497
|
|
Total
interest payments
(2)
|
|
|
321
|
|
|
|
579
|
|
|
|
218
|
|
|
|
11
|
|
|
|
1,129
|
|
Accrued
pension liabilities
|
|
|
6
|
|
|
|
11
|
|
|
|
14
|
|
|
|
7
|
|
|
|
38
|
|
Other
non-current liabilities
|
|
|
7
|
|
|
|
15
|
|
|
|
16
|
|
|
|
-
|
|
|
|
38
|
|
Total
operating lease obligations
|
|
|
20
|
|
|
|
34
|
|
|
|
29
|
|
|
|
30
|
|
|
|
113
|
|
Total
drilling unit purchases
(3)
|
|
|
1,175
|
|
|
|
503
|
|
|
|
-
|
|
|
|
-
|
|
|
|
1,678
|
|
Total
contractual cash obligations
|
|
|
2,303
|
|
|
|
4,103
|
|
|
|
3,880
|
|
|
|
207
|
|
|
|
10,493
|
|
(1) In
September 2009 we issued $500 million of 4.875% convertible bonds due 2014. Due
to the hybrid nature of this financial instrument, for accounting purposes the
liability is divided into $395 million of debt and $105 million of equity. The
above contractual obligations assume that none of the bonds are converted into
common shares and that the full $500 million is repayable in 2014. Accordingly,
total debt repayments shown above exceed by $101million the interest bearing
debt shown in the consolidated balance sheet as at December 31,
2009.
(2)
Interest payments are based on the existing borrowings of the Company and its
consolidated subsidiaries. It is assumed that no refinancing of existing loans
takes place and that there is no repayment on revolving credit facilities.
Interest has been calculated using the US$Yield Curve published by Reuters, plus
agreed margins for each loan facility. The effects of interest rate swaps have
been included in the calculations.
(3)
Drilling unit purchase commitments relate to three jack-up rigs ($454 million),
three tender rigs ($143 million), two semi-submersible rigs ($781 million) and
one drillship ($300 million). We have an option not to take delivery of one of
the jack-up rigs, which if exercised would reduce the above commitments by $184
million. In April 2010 we announced that we have entered into an option
agreement to buy a CJ70 design harsh environment jack-up rig from the Jurong
shipyard. We intend to exercise the option, which will increase the above
commitments by $354 million.
(4) In
April 2010 we announced that we plan to make an offer for the outstanding shares
in Scorpion which we do not already own. The planned offer is triggered by the
Oslo Stock Exchange Mandatory Offer Rules, following our acquisition in April
2010 of shares in Scorpion at a price of NOK36.00 per share, which increased our
shareholding in Scorpion to 40.0% of its issued share capital. If the offer is
made at the price of NOK36.00 per share and is accepted by all of holders of the
outstanding shares, the cost of acquiring the remaining shares in Scorpion will
amount to approximately $330 million.
(5) The
potential acquisitions of the CJ70 design jack-up rig and further investment in
Scorpion will be partly financed by the private placement announced on April 12,
2010, of 12,500,000 common shares for gross proceeds of approximately $322
million. We are in the process of securing the necessary debt finance for the
remainder of the investments.
G.
SAFE HARBOR
See
section entitled "Forward Looking Statements" in this Annual
Report.
ITEM
6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A.
DIRECTORS AND SENIOR MANAGEMENT
The
following table sets forth information regarding our directors and officers, and
also certain key employees within our operating subsidiaries, who are
responsible for overseeing the management of our business.
Name
|
Age
|
Position
|
John
Fredriksen
|
65
|
President,
Director and Chairman of the Board
|
Tor
Olav Trøim
|
47
|
Vice
President and Director
|
Kate
Blankenship
|
45
|
Director
and Audit Committee member
|
Kjell
E. Jacobsen
|
53
|
Director
|
Kathrine
Fredriksen
|
26
|
Director
|
Georgina
Sousa
|
59
|
Company
Secretary
|
Alf
C. Thorkildsen
|
53
|
Chief
Executive Officer, Interim Chief Financial Officer and President, Seadrill
Management AS
|
Per
Wullf
|
50
|
Chief
Operating Officer and Executive Vice President, Seadrill Management
AS
|
Tim
Juran
|
49
|
Executive
Vice President Deepwater Western Hemisphere
|
Svend
Anton Maier
|
45
|
Vice
President Deepwater Eastern Hemisphere
|
Sveinung
Lofthus
|
49
|
Senior
Vice President Europe
|
Ian
Shearer
|
48
|
Senior
Vice President Asia Pacific Jack-ups
|
Alf
Ragnar Løvdal
|
52
|
Senior
Vice President Tender Rigs
|
Thorleif
Egeli
|
46
|
Chief
Executive Officer, Seawell Management
AS
|
Certain
biographical information about each of our directors, executive officers and key
officers is set forth below.
John Fredriksen
has served as
Chairman of the Board, President and a director of the Company since its
inception in May 2005. Mr. Fredriksen has established trusts for the benefit of
his immediate family which control Hemen, our largest shareholder. Mr.
Fredriksen is Chairman, President, Chief Executive Officer and a director of a
related party Frontline, a Bermuda company listed on the NYSE, the Oslo Stock
Exchange and the London Stock Exchange. He is also a director of a related
party, Golar LNG Limited, or Golar, a Bermuda company listed on the Nasdaq
Global Market and the Oslo Stock Exchange whose principal shareholder is World
Shipholding Limited, a company indirectly influenced by trusts established by
Mr. John Fredriksen for the benefit of his immediate family. He is also a
director of a related party Golden Ocean Group Limited, or Golden Ocean, a
Bermuda company publicly on the Oslo Stock Exchange whose principal shareholder
is Hemen.
Tor Olav Trøim
has served as
Vice-President and a director of the Company since its inception in May 2005.
Mr. Trøim graduated as M.Sc Naval Architect from the University of Trondheim,
Norway in 1985. His careers include Equity Portfolio Manager with Storebrand ASA
(1987-1990), and Chief Executive Officer for the Norwegian Oil Company DNO AS
(1992-1995). Mr. Trøim serves as a director and Vice President of Golar, and as
a director of three Oslo Stock Exchange listed companies, Golden Ocean, Aktiv
Kapital ASA and Marine Harvest ASA. He served as a director of Frontline from
November 1997 until February 2008. Mr. Trøim served as a director of
Seatankers Management from 1995 until June 2009. He also has acted as
Chief Executive Officer for Knightsbridge Tankers Limited, a Bermuda company
listed on the Nasdaq Global Select Market, until September 2007 and for Golar
until April 2006.
Kate Blankenship
has served as
a director of the Company since its inception in May 2005. Mrs. Blankenship has
also served as a director of Frontline since 2003. Mrs. Blankenship joined
Frontline in 1994 and served as its Chief Accounting Officer and Secretary until
October 2005. Mrs. Blankenship has been a director of Ship Finance since October
2003. Mrs. Blankenship has been a director of Independent Tankers Corporation
Limited since February 2008, Golar since July 2003 and Golden Ocean since
November 2004. Mrs. Blankenship served as Chief Financial Officer of
Knightsbridge Tankers Limited from April 2000 to September 2007 and its
Secretary from December 2000 to March 2007. She is a member of the Institute of
Chartered Accountants in England and Wales.
Kjell E. Jacobsen
has served
as a director of the Company since May 2008, when he was appointed to fill a
casual vacancy on our board of directors. Mr. Jacobsen was Chief Executive
Officer of Seadrill Management AS from 2006 until 2008. From 2002 to 2006, Mr.
Jacobsen was the Chief Executive Officer of the Norwegian offshore drilling
contractor, Smedvig. Between 1991 and 2002, Mr. Jacobsen held several senior
positions, including his appointment as managing director of the mobile units of
Smedvig. From 1981 to 1991, Mr. Jacobsen worked for Statoil and Citibank in both
Oslo and London. Mr. Jacobsen graduated from the Norwegian Naval Academy in 1976
and from the Norwegian School of Economics and Business Administration in
1981.
Kathrine Fredriksen
has served
as a director of the Company since September 2008. Ms. Fredriksen has also
served as a director of Frontline and Golar since February 2008. She graduated
from Wang Handels Gymnas in Norway and studied at the European Business School
in London. Ms. Fredriksen is the daughter of Mr. John Fredriksen, our President
and Chairman.
Georgina Sousa
has served as
Company Secretary of the Company since February 2006. She is currently Head of
Corporate Administration for Frontline. Until January 2007, she was
Vice-President-Corporate Services of Consolidated Services Limited, a Bermuda
Management Company, having joined the firm in 1993 as Manager of Corporate
Administration. From 1976 to 1982 she was employed by the Bermuda law
firm of Appleby, Spurling & Kempe as a Company Secretary and from 1982 to
1993 she was employed by the Bermuda law firm of Cox & Wilkinson as Senior
Company Secretary.
Alf C. Thorkildsen
was
appointed Chief Executive Officer and President of Seadrill Management AS in
June 2008. He is also acting as Interim Chief Financial Officer of Seadrill
Management AS from April 2010 until October 2010, when a newly appointed Chief
Financial Officer is scheduled to take up the position. From 2002 to
2006, Mr. Thorkildsen was the Chief Financial Officer in the offshore drilling
contractor Smedvig, and following the acquisition of Smedvig by Seadrill Mr
Thorkildsen served as the Chief Operating Officer of Seadrill Management AS
until June 2008. Prior to joining Smedvig Mr. Thorkildsen worked for more than
20 years at Royal Dutch Shell plc, or Shell, in various senior positions. Mr.
Thorkildsen graduated from the Norwegian School of Business Administration with
a degree in economics and from Arizona State University with a Masters of
Business Administration.
Per Wullf
has served as the
Chief Operating Officer and Executive Vice President of Seadrill Management AS
since February 2009. Mr. Wullf has more than 28 years of experience in the
international offshore and onshore drilling industry with A.P. Moller - Maersk
A/S, serving as Managing Director for Maersk Drilling Norge AS from 2006 to
2009.
Tim Juran
has served as the
Executive Vice President, Deepwater Western Hemisphere since January 2007. Mr.
Juran has more than 28 years of experience in the international offshore and
onshore drilling industry, including several senior positions in Transocean Ltd.
and Reading & Bates Drilling Company. Mr. Juran graduated from the
University of Wisconsin - Platteville with a bachelor's degree in mining
engineering.
Svend Anton Maier
has served
as the Vice President, Deepwater Eastern Hemisphere since February 2007. Mr.
Maier has more than twenty years of experience in the offshore drilling
industry. Prior to joining us, Mr. Maier held several senior positions in
Transocean Ltd., including country manager in Nigeria, Equatorial Guinea and
Gabon. Mr. Maier graduated from the Maritime Institute of Tønsberg with a degree
in marine engineering.
Sveinung Lofthus
has served as
the Senior Vice President, Europe since 2005. Mr. Lofthus has more than 20 years
experience in the international offshore and onshore drilling industry,
including project and rig management positions in Smedvig. Mr. Lofthus graduated
from the University of Stavanger with a degree in petroleum
engineering.
Ian Shearer
was appointed the
Senior Vice President, Australasia Jack-ups in 2007. From 2004 to 2007 Mr.
Shearer was responsible for our platform drilling services in the U.K. Mr.
Shearer has 20 years of experience in the drilling industry, including several
senior positions with Smedvig. He graduated from the University of Aberdeen with
a bachelor's degree in mechanical engineering and from Robert Gordon's Institute
of Technology, Aberdeen with an M.Sc in offshore engineering.
Alf Ragnar Løvdal
was
appointed Senior Vice President, Tender Rigs in April 2009. He was previously
CEO in Seawell Management AS. Mr. Løvdal has 30 years of experience in the oil
and gas industry, including 20 years responsibility for the well services
business in the drilling contractor Smedvig. Before joining Smedvig,
Mr. Løvdal held various positions in different oil service companies, including
five years of offshore field experience with Schlumberger. He has a degree in
mechanical engineering from Horten Engineering Academy in Norway.
Thorleif Egeli
was appointed
Chief Executive Officer of Seawell Management AS in October 2009. Mr. Egeli has
more than 16 years of experience in the oil services industry, including his
most recent position as Vice President, Schlumberger North America. He graduated
from the Norwegian Technical University with a degree in mechanical engineering
and has an MBA from the Erasmus School of Management, Rotterdam.
B.
COMPENSATION
During
the year ended December 31, 2009, we paid our directors and executive officers
aggregate compensation of $8.3 million, including compensation in the form of
options exercised. In addition we have incurred compensation expense in the
aggregate amount of $0.1 million for their pension and retirement benefits.
These amounts include compensation of $1.5 million paid to the CEO, and $0.02
million expensed for the CEO's pension and retirement benefits.
In the
event the Chief Executive Officer resigns at the request of the board of
directors, he will receive compensation equal to his salary for two
years.
In
addition to cash compensation, during 2009 we also recognized an expense of $5.7
million relating to stock options granted in 2006, 2007, 2008 and 2009 to
certain of our directors and employees. The options vest over a three year
period, with the first tranche vesting in May 2007, and they expire between
September 2011 and May 2014. The exercise price of the options at December 31,
2009, was in the range $2.23 to NOK122.73 (equivalent to $21.29) per share, and
for most options shall be reduced by the amount of any future dividends declared
with respect to the common shares.
C.
BOARD PRACTICES
Our board
of directors is elected annually by a vote of a majority of the common shares
represented at the meeting at which one or more holders of one-third of our
outstanding common shares constitutes a quorum. In addition, the maximum and
minimum number of directors is determined by our shareholders at the annual
general meeting, but no less than two directors shall serve at any given time.
We currently have a maximum number of directors of eight. Each director shall
hold office until the next annual general meeting following his or her election
or until his or her successor is elected.
Our board
of directors currently consists of five directors. Three of our directors, John
Fredriksen, Kathrine Fredriksen and Tor Olav Trøim may be deemed affiliated with
our largest shareholder, Hemen. One of our directors, Kate Blankenship, is
independent pursuant to Rule 10A-3 of the Securities and Exchange Commission,
but is not considered independent pursuant to the rules of the Oslo Stock
Exchange. Our current board of directors does not follow the recommendation of
the Norwegian Code of Practice for Corporate Governance of two independent
directors.
We
currently have an audit committee, which is responsible for overseeing the
quality and integrity of our financial statements and its accounting, auditing
and financial reporting practices, our compliance with legal and regulatory
requirements, the independent auditor's qualifications, independence and
performance and our internal audit function. Our audit committee consists of
Mrs. Blankenship.
In
lieu of a compensation committee comprised of independent directors, our Board
of Directors is responsible for establishing the executive officers'
compensation and benefits. In lieu of a nomination committee
comprised of independent directors, our Board of Directors is responsible for
identifying and recommending potential candidates to become board members and
recommending directors for appointment to board committees.
There are
no service contracts between us and any of our Directors providing for benefits
upon termination of their employment or service.
D.
EMPLOYEES
As at
April 26, 2010, we have approximately 7,600 employees, including approximately
1,100 contracted-in staff.
Some of
our employees and our contracted labor, most of whom work in Brazil, Nigeria,
Norway and the U.K., are represented by collective bargaining agreements. As
part of the legal obligations in some of these agreements, we are required to
contribute certain amounts to retirement funds and pension plans and have
restricted ability to dismiss employees. In addition, many of these represented
individuals are working under agreements that are subject to salary negotiation.
These negotiations could result in higher personnel costs, other increased costs
or increased operating restrictions that could adversely affect our financial
performance.
We
consider our relationships with the various unions as stable, productive and
professional. At present, there are no ongoing negotiations or outstanding
issues.
Total employees (including contracted-in staff
)
|
|
December 31, 2007
|
|
|
December 31, 2008
|
|
|
December 31, 2009
|
|
|
April 26,
2010
|
|
Operating
segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
Mobile
units
|
|
|
1,700
|
|
|
|
2,700
|
|
|
|
3,100
|
|
|
|
3,100
|
|
Tender
rigs
|
|
|
1,500
|
|
|
|
1,700
|
|
|
|
1,800
|
|
|
|
1,800
|
|
Well
services
|
|
|
1,500
|
|
|
|
2,400
|
|
|
|
2,600
|
|
|
|
2,600
|
|
Corporate
|
|
|
100
|
|
|
|
100
|
|
|
|
100
|
|
|
|
100
|
|
Total
employees
|
|
|
4,800
|
|
|
|
6,900
|
|
|
|
7,600
|
|
|
|
7,600
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Geographical
location:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Norway
|
|
|
2,300
|
|
|
|
2,600
|
|
|
|
2,800
|
|
|
|
2,800
|
|
Rest
of Europe
|
|
|
300
|
|
|
|
900
|
|
|
|
800
|
|
|
|
800
|
|
USA
|
|
|
-
|
|
|
|
300
|
|
|
|
300
|
|
|
|
250
|
|
South
America
|
|
|
-
|
|
|
|
300
|
|
|
|
700
|
|
|
|
800
|
|
Asia
and Australia
|
|
|
2,100
|
|
|
|
2,600
|
|
|
|
2,500
|
|
|
|
2450
|
|
Africa
|
|
|
100
|
|
|
|
200
|
|
|
|
500
|
|
|
|
500
|
|
Total
employees
|
|
|
4,800
|
|
|
|
6,900
|
|
|
|
7,600
|
|
|
|
7,600
|
|
The
number of employees has increased over the past three years as a result of the
increase in our operating fleet of drilling units and business
acquisitions.
E.
SHARE OWNERSHIP
The table
below shows the number of common shares beneficially owned and the percentage
owned of our outstanding common shares for our directors, officers and key
employees as of April 26, 2010, and the percentage held of the total common
shares in issue. Also shown are their interests in share options awarded to them
under the Option Scheme which was approved by the Company in May 2005. The
subscription price for options granted under the scheme will normally be reduced
by the amount of all dividends declared by the Company in the period from the
date of grant until the date the option is exercised.
Director
or Key Employee
|
Beneficial
Interest in Common Shares of
$2.00
each
|
|
Interest
in Options
|
|
Number
of shares
|
%
|
|
Total
number
of options
|
Number
of options
vested
|
Exercise
price
|
Expiry
date
|
John
Fredriksen
(2)
|
(2)
|
(2)
|
|
-
|
-
|
-
|
-
|
Tor
Olav Trøim
(3)
|
635,000
|
(1)
|
|
-
|
-
|
-
|
-
|
Kate
Blankenship
|
41,000
|
(1)
|
|
20,000
|
-
|
NOK
84.83
|
May
2014
|
Kjell
E. Jacobsen
|
-
|
(1)
|
|
175,000
100,000
|
175,000
33,333
|
NOK
86.60
NOK
116.72
|
December
2011
January
2014
|
Kathrine
Fredriksen
|
-
|
(1)
|
|
-
|
-
|
-
|
-
|
Georgina
Sousa
|
-
|
(1)
|
|
-
|
-
|
-
|
-
|
Alf
C. Thorkildsen
|
20,000
|
(1)
|
|
275,000
325,000
|
275,000
-
|
NOK
86.60
NOK
84.83
|
December
2011
May
2014
|
Per
Wullf
|
-
|
(1)
|
|
150,000
|
-
|
NOK
84.83
|
May
2014
|
Tim
Juran
|
855
|
(1)
|
|
150,000
140,000
|
150,000
-
|
NOK
98.63
NOK
104.64
|
September
2011
May
2014
|
Svend
Anton. Maier
|
-
|
(1)
|
|
12,500
25,000
60,000
|
12,500
16,667
-
|
NOK
83.81
NOK
114.23
NOK
84.83
|
September
2011
September
2011
May
2014
|
Sveinung
Lofthus
|
2,000
|
(1)
|
|
100,000
60,000
|
100,000
-
|
NOK
72.73
NOK
84.83
|
September
2011
May
2014
|
Ian
Shearer
|
-
|
(1)
|
|
40,000
60,000
|
3,333
-
|
NOK
114.23
NOK84.83
|
September
2011
May
2014
|
Alf
Ragnar Løvdal
|
-
|
(1)
|
|
40,000
|
|
NOK
90.83
|
May
2014
|
Thorleif
Egeli
|
800
|
(1)
|
|
-
|
-
|
-
|
-
|
(1)
less than one percent
(2) Hemen
Holding Ltd, or Hemen, is a Cyprus holding company, the shares of which are held
in trusts established by Mr. John Fredriksen for the benefit of his immediate
family. Mr. Fredriksen disclaims beneficial ownership of the 133,097,583 shares
of our common stock held by Hemen, except to the extent of his voting and
dispositive interest in such shares of common stock. Mr. Fredriksen has no
pecuniary interest in the shares held by Hemen. In addition, to the holdings of
shares and options contained in the table above, as of April 26, 2010, Hemen is
party to separate TRS agreements relating to 3,900,000 of our common
shares.
(3) In
addition to the holdings of shares and options contained in the table above, as
of April 26, 2010, Drew Investment Ltd., a company controlled by Tor Olav Trøim,
is party to separate TRS agreements relating to 400,000 of our common
shares.
ITEM
7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A.
MAJOR SHAREHOLDERS
The
following table presents certain information as at April 6, 2010, regarding the
ownership of our common shares with respect to each shareholder whom we know to
beneficially own more than five percent of our outstanding common
shares:
|
|
Common
Shares Held
|
|
Shareholder
|
|
Number
|
|
|
%
|
|
Hemen
(1)
|
|
|
133,097,583
|
|
|
|
32.35
|
%
|
Folketrygdfondet
(2)
|
|
|
27,001,030
|
|
|
|
6.56
|
%
|
Fidelity
Management and Research Company
(3)
|
|
|
20,501,728
|
|
|
|
5.10
|
%
|
Wellington
Management Company LLP
(3)
|
|
|
21,846,224
|
|
|
|
5.47
|
%
|
(1)
Hemen, a Cyprus holding company, the shares of which are held in trusts
established by Mr. John Fredriksen for the benefit of his immediate
family.
(2)
Folketrygdfondet manages the Government Pension Fund of Norway on behalf of the
Norwegian Ministry of Finance.
(3) Share
ownership information is based on Norwegian Securities Regulation notification
statements, available on www.newsweb.no.
As of
April 26, 2010, the Company had a single shareholder of record in the United
States, in whose name all shareholdings in the United States are recorded. We
had a total of 411,443,816 common shares outstanding as of April 26,
2010.
Our major
shareholders have the same voting rights as our other shareholders. No
corporation or foreign government owns more than 50% of our outstanding common
shares. We are not aware of any arrangements, the operation of which may at a
subsequent date result in a change in control of Seadrill.
B.
RELATED PARTY TRANSACTIONS
The
Company was formed on March 10, 2005, and its shares commenced trading on the
Oslo Stock Exchange in November 2005. Its shares commenced trading on the New
York Stock Exchange in April 2010. Since its formation, the Company's largest
shareholder has been Hemen, which currently holds approximately 32% of our
shares. Under the mandatory offer rules of the Oslo Stock Exchange
described in Item 4.A "History and Development of the Company – Summary of Oslo
Stock Exchange Mandatory Offer Rules", if Hemen were to acquire more
than 1/3 of our shares, it could trigger the mandatory offer
rules. Hemen has not advised us of any intention to do
so.
The
Company transacts business with the following related parties, being companies
in which Hemen and companies associated with Hemen have a significant
interest:
|
·
|
Ship
Finance International Limited ("Ship
Finance")
|
|
·
|
Metrogas
Holdings Inc ("Metrogas")
|
|
·
|
Scorpion
Offshore Ltd ("Scorpion")
|
|
·
|
Frontline
Management (Bermuda) Limited
("Frontline")
|
In July
2006 we entered into a sale and leaseback agreement with Ship Finance, a company
listed on the New York Stock Exchange in which Hemen indirectly controls
approximately 43% of the outstanding shares. Under the agreement we sold the
jack-up rig
West Ceres
to Rig Finance Ltd, or Rig Finance, a wholly-owned subsidiary of Ship Finance,
for a total consideration of $210 million. Upon sale the rig was immediately
leased back to us for a period of 15 years, with the Company having fixed price
purchase options after three, five, seven, 10, 12 and 15 years. In July 2009, we
exercised our option to repurchase
West Ceres
from Rig Finance
at the option price of US$136 million. Lease payments to Rig Finance amounted to
$20 million in 2009 (2008: $41 million).
In
January 2007 we entered into a sale and leaseback agreement with Ship Finance,
under which we sold the jack-up rig
West Prospero
to Rig Finance
II Ltd, or Rig Finance II, a wholly-owned subsidiary of Ship Finance, for a
total consideration of $210 million. Upon sale the rig was immediately leased
back to us for a period of 15 years, with the Company having fixed price
purchase options after three, five, seven, 10, 12 and 15 years. Lease payments
to Rig Finance II amounted to $30 million in 2009 (2008: $46
million).
In May
2008 we entered into a sale and leaseback agreement with Ship Finance, under
which the Company would sell the drillship
West Polaris
to SFL West
Polaris, a wholly-owned subsidiary of Ship Finance, for a total consideration of
$845 million upon completion of construction. Upon delivery the drillship was
leased back to us for a period of 15 years, with the Company having fixed price
purchase options after four, six, eight, 10, 12 and 15 years. In addition, Ship
Finance has a right to sell the drillship to us after 15 years at a fixed price.
Lease payments to SFL West Polaris amounted to $127 million in 2009 (2008: $37
million).
In
September 2008 we entered into a sale and leaseback agreement with Ship Finance,
under which we sold two newbuilding semi-submersible rigs
West Hercules
and
West Taurus
to SFL Deepwater
Ltd, or SFL Deepwater, a wholly-owned subsidiary of Ship Finance, for a total
consideration of $1.70 billion. Upon delivery the rigs were immediately leased
back to us for a period of 15 years, with the Company having fixed price
purchase options for
West
Hercules
after three, six, eight, 10, and 12 years and for
West Taurus
after six, eight,
10 and 12 years. In addition, we have fixed price obligations to purchase the
rigs after 15 years. Lease payments to SFL Deepwater amounted to $224 million in
2009 (2008: $29 million).
We
consolidate the above four Ship Finance VIEs, Rig Finance, Rig Finance II, SFL
West Polaris and SFL Deepwater, as it is has been determined that we
are the primary beneficiary of the risks and rewards connected with the
ownership of the units and the lease contracts. This has the effect that the
Ship Finance equity in the VIEs, including their earnings, is attributable to
non-controlling interests. Following our repurchase of
West Ceres
in July 2009
,
Rig Finance will no longer
be a consolidated VIE.
In
November 2008, the Company granted Ship Finance an unsecured short-term credit
facility of $115 million. Ship Finance repaid $25 million in the first quarter
of 2009 and the balance of $90 million was sold to Metrogas, a company
indirectly controlled by trusts established by Mr. John Fredriksen for the
benefit of his immediate family. In November 2009, the loan of $90 million was
assigned back to the Company. At the same time the repayment schedule was
amended to provide a maturity date of January 31, 2011. The agreed interest
payable monthly by Ship Finance is based on terms believed by us to be no less
favorable than are available from unaffiliated third parties. Interest
receivable on the loan amounted to $8.8 million in 2009 (2008: $2.1
million).
In April
2009 the Company obtained an unsecured credit facility of $60 million from
Metrogas, which was repaid in June 2009. Interest payable on the facility
amounted to $0.7 million in 2009.
In
November 2009, the Company granted Scorpion an unsecured short-term credit
facility of $27.7 million, increasing to $79.7 million in December 2009. The
applicable interest rate is based on terms believed by us to be no less
favorable than are available from unaffiliated third parties and is due
semi-annually. Interest received on the loan amounted to $1.0 million in 2009.
In February 2010, the Company granted Scorpion a secured short-term credit
facility of $49.5 million. The applicable interest rate is based on terms
believed by us to be no less favorable than are available from unaffiliated
third parties.
Frontline,
a company indirectly controlled by Hemen, provides us with management support
and administrative services. Fee payments to Frontline amounted to $0.2 million
in 2009 (2008: $0.2 million) and are included in "General and administrative
expenses", as they do not merit separate disclosure.
C.
INTERESTS OF EXPERTS AND COUNSEL.
Not
applicable.
ITEM
8. FINANCIAL INFORMATION
A. CONSOLIDATED
STATEMENTS AND OTHER FINANCIAL INFORMATION
Please
see the section of this Annual Report on Form 20-F entitled Item 18 "Financial
Statements."
Legal
Proceedings
The
Company is routinely party, as plaintiff or defendant, to claims and lawsuits in
various jurisdictions for demurrage, damages, off-hire and other claims and
commercial disputes arising from the operation of our drilling units, in the
ordinary course of our business or in connection with our acquisition
activities. The Company believes that the resolution of such claims will not
have a material adverse effect on our operations or financial condition. The
following dispute is the only legal proceeding which we consider to be
material.
Gazprom
dispute
At the
end of 2005 and the beginning of 2006, the Company had a dispute with Gazprom in
connection with the operations of the jack-up rig
West Larissa
, which was named
Ekha
at that
time.
In May
2009, legal hearings took place in the High Court of Justice, London, and the
Court has issued a decision with the following main conclusions:
|
·
|
The
Company was awarded charter hire for the period from November 23, 2005, to
January 9, 2006, being the date up to when the incident occurred.
Including interest this amounted to approximately $6.8
million.
|
|
·
|
The
Company was not awarded hire for the time after the incident, nor was the
Company awarded any reimbursement for uninsured costs related to its
claim.
|
|
·
|
The
Court has ruled that Gazprom is entitled to recover costs and expenses
related to
West
Larissa
, where Gazprom can demonstrate that these were wasted as a
consequence of Seadrill's actions during the incident. The Judge also
ruled that Gazprom wrongfully terminated the Contract, and has thus
rejected Gazprom's claim for losses associated with the contracting of
another rig.
|
It is not
possible at this stage to quantify the net outcome of this ruling. The amount of
Gazprom's counter-claim, as well as responsibility for incurred legal costs,
will be decided in a separate hearing at a later stage. The Court's decision has
been appealed by the Company, and appeal hearings are scheduled to take place
during the first half of 2010. The Company does not expect the final outcome to
have a significant effect on its financial results.
Dividend
Policy
Under our
bye-laws, our board of directors may declare cash dividends or distributions,
and may also pay a fixed cash dividend biannually or on other dates. Our Board
of Directors' stated objective is to generate competitive returns for its
shareholders. Any dividends declared will be in the sole discretion of the Board
of Directors and will depend upon earnings, market prospects, current capital
expenditure programs and investment opportunities. Under Bermuda law, the Board
of Directors has no discretion to declare or pay a dividend if there are
reasonable grounds for believing that (a) the Company is, or would after the
payment be, unable to pay its liabilities as they become due; or (b) the
realizable value of the Company's assets would thereby be less than the
aggregate of its liabilities and issued share capital and share premium
accounts.
In
addition, since we are a holding company with no material assets
other than the shares of our subsidiaries through which we conduct our
operations, our ability to pay dividends will depend on our subsidiaries'
distributing to us their earnings and cash flow.
Since our
listing on the Oslo Stock Exchange in November 2005, we have paid dividends as
follows:
Payment date
|
|
Amount per share
|
|
2010
|
|
|
|
March
26, 2010
|
|
$
|
0.55
|
|
|
|
|
|
|
2009
|
|
|
|
|
December
7, 2009
|
|
$
|
0.50
|
|
|
|
|
|
|
2008
|
|
|
|
|
March
14, 2008
|
|
$
|
0.25
|
|
June
18, 2008
|
|
$
|
0.60
|
|
September
16, 2008
|
|
$
|
0.60
|
|
September
30, 2008
|
|
$
|
0.30
|
|
B.
SIGNIFICANT CHANGES
None
ITEM
9. THE OFFER AND LISTING
A.
OFFER AND LISTING
DETAILS
Shares of
our common stock, par value $2.00 per share, have traded on the Oslo Stock
Exchange, or OSE, since November 22, 2005, under the symbol "SDRL". The closing
price of our shares on the Oslo Stock Exchange was NOK162.50 on April 26,
2010.
Shares of
our common stock commenced trading on the New York Stock Exchange, or NYSE, on
April 15, 2010, also under the symbol "SDRL". The closing price of our shares on
the NYSE was $27.83 on April 26, 2010.
The NYSE
listing is intended to be the Company's "primary listing" and the OSE listing is
intended to be the Company's secondary listing.
The
following table sets forth the fiscal years high and low closing prices of our
common shares since they began trading on the Oslo Stock Exchange in November
2005:
|
|
High
NOK
|
|
|
Low
(NOK)
|
|
Fiscal
year ended December 31
|
|
|
|
|
|
|
2009
|
|
|
149.80
|
|
|
|
47.00
|
|
2008
|
|
|
179.75
|
|
|
|
41.60
|
|
2007
|
|
|
134.25
|
|
|
|
98.10
|
|
2006
|
|
|
114.50
|
|
|
|
55.75
|
|
2005
|
|
|
55.00
|
|
|
|
43.00
|
|
The
following table sets forth, for each full financial quarter for the two most
recent fiscal years, the high and low closing prices of our common shares
trading on the Oslo Stock Exchange:
|
|
High
NOK
|
|
|
Low
(NOK)
|
|
Fiscal
year ended December 31, 2009
|
|
|
|
|
|
|
First
quarter
|
|
|
68.80
|
|
|
|
47.00
|
|
Second
quarter
|
|
|
101.25
|
|
|
|
65.40
|
|
Third
quarter
|
|
|
120.60
|
|
|
|
83.00
|
|
Fourth
quarter
|
|
|
149.80
|
|
|
|
115.60
|
|
|
|
High
NOK
|
|
|
Low
(NOK)
|
|
Fiscal
year ended December 31,2008
|
|
|
|
|
|
|
First
quarter
|
|
|
141.00
|
|
|
|
102.75
|
|
Second
quarter
|
|
|
179.75
|
|
|
|
135.50
|
|
Third
quarter
|
|
|
160.25
|
|
|
|
114.75
|
|
Fourth
quarter
|
|
|
114.00
|
|
|
|
41.60
|
|
The
following table sets forth, for the six most recent months, the high and low
closing prices of our common shares trading on the Oslo Stock
Exchange:
|
|
High
NOK
|
|
|
Low
(NOK)
|
|
March
2010
|
|
|
143.00
|
|
|
|
136.20
|
|
February
2010
|
|
|
140.20
|
|
|
|
124.10
|
|
January
2010
|
|
|
150.00
|
|
|
|
132.50
|
|
December
2009
|
|
|
148.50
|
|
|
|
132.20
|
|
November
2009
|
|
|
139.00
|
|
|
|
117.00
|
|
October
2009
|
|
|
119.30
|
|
|
|
104.50
|
|
On April
26, 2010, the exchange rate between the Norwegian Kroner and the U.S. Dollar was
NOK 5.86 to one U.S. Dollar (December 31, 2009: NOK 5.77 to one U.S.
Dollar).
C.
MARKETS
Our
common shares currently trade on the New York Stock Exchange and the Oslo Stock
Exchange under the symbol "SDRL".
ITEM
10. ADDITIONAL INFORMATION
A.
SHARE CAPITAL
Not
applicable.
B.
MEMORANDUM AND ARTICLES OF ASSOCIATION
The
Memorandum of Association of the Company was filed as Exhibit 1.1 to the
Company's Registration Statement on Form 20-F (Registration No. 001-34667 ),
which was filed with the Securities and Exchange Commission on March 25, 2010,
and is hereby incorporated by reference into this Annual Report.
The
object of our business, as stated in Section six of our Memorandum of
Association, is to engage in any lawful act or activity for which companies may
be organized under The Companies Act, 1981 of Bermuda, or the Companies Act,
other than to issue insurance or re-insurance, to act as a technical advisor to
any other enterprise or business or to carry on the business of a mutual fund.
Our Memorandum of Association and Bye-laws do not impose any limitations on the
ownership rights of our shareholders.
Under our
Bye-laws, annual shareholder meetings will be held in accordance with the
Companies Act at a time and place selected by our board of directors.
The quorum at any annual or general meeting is equal to one or more
shareholders, either present in person or represented by
proxy, holding in the aggregate shares carrying 33 1/3 percent of the
exercisable voting rights. The meetings may be held at any
place, in or outside of Bermuda, other than Norway. Special meetings may be
called at the discretion of the board of directors and at the request of
shareholders holding at least one-tenth of all outstanding shares entitled to
vote at a meeting. Annual shareholder meetings and special meetings
must be called by not less than seven days' prior written notice specifying the
place, day and time of the meeting. The board of directors may fix any date as
the record date for determining those shareholders eligible to receive notice of
and to vote at the meeting. No shareholder shall be entitled to attend unless
written notice of the intention to attend and vote in person or by proxy,
together with the power of attorney or other authority (if any) under which it
is signed, or a notarized copy of that power of attorney, is sent to the Company
Secretary, to reach the Registered Office by not later than 48 hours before the
time for holding the meeting.
There are
no pre-emptive, redemption, conversion or sinking fund rights attached to our
shares of common stock. All or any of the rights attached to our shares may be
altered by either the written consent or majority vote at a special general
meeting of a majority of shareholders who hold at least 75% of the nominal value
of our issued and outstanding shares. The holders of common shares are entitled
to one vote per share on all matters submitted to a vote of holders of common
shares. There are no limitations on the right of non-Bermudians or non-residents
of Bermuda to hold or vote our common shares. Unless a different majority is
required by law or by our bye-laws under bye-law 57, resolutions to be approved
by holders of common shares require approval by a simple majority of votes cast
at a general meeting. Under our bye-laws, we have the power to purchase our
shares of common stock for cancellation or to be held as treasury
shares.
Our
directors are elected by a majority of the votes cast at our annual general
meeting. Our board of directors must consist of at least two members. The number
of directors may be modified by simple majority of the votes cast at a general
meeting.
Each
director serves from his or her election until his or her successor is duly
elected and qualified except in the case of earlier resignation or removal.
Under our bye-laws, our board of directors has the authority to appoint any
individual to fill a casual vacancy on the board. In a director's absence, the
director may appoint any person (including another director) to act as his or
her alternate. Basic director fees are determined by majority vote at a general
meeting, and the board of directors has the authority to grant additional fees
for extraordinary services rendered as a director. Directors may participate
fully in any transaction or arrangement where they have an interest, so long as
they declare the nature of their interest at the first opportunity either in
meeting or by writing to our board of directors. Under our bye-laws our board of
directors has the authority to exercise all the powers of the Company to borrow
money and to mortgage or charge our undertaking property, assets and uncalled
capital in the course of managing our business, subject to the provisions of
Bermuda law.
Our
bye-laws provide that no director, alternate director, officer, member of a
committee under bye-law 103, resident representative of the Company, or their
heirs, executors or administrators, shall be liable for the acts, receipts,
neglects, or defaults of any other such person or any person involved in our
formation, or for any loss or expense incurred by us through the insufficiency
or deficiency of title to any property acquired by us, or for the insufficiency
or deficiency of any security in or upon which any of our monies shall be
invested, or for any loss or damage arising from the bankruptcy, insolvency, or
tortuous act of any person with whom any monies, securities, or effects shall be
deposited, or for any loss occasioned by any error of judgment, omission,
default, or oversight on his part, or for any other loss, damage or misfortune
whatever which shall happen in relation to the execution of his duties, or
supposed duties, to us or otherwise in relation thereto.
Bermuda
law permits our bye-laws to contain provisions excluding personal liability of a
director, alternate director, officer, member of a committee authorized under
bye-Law 103, resident representative or their respective heirs, executors or
administrators to the company for any loss, damage or expense (including but not
limited to liabilities under contract, tort and statute or any applicable
foreign law or regulation and all reasonable legal and other costs and expenses
properly payable) incurred by him as such director, alternate director, officer,
member of a committee authorized under bye-Law 103 or resident representative in
the reasonable belief that he has been so appointed or elected notwithstanding
any defect in such appointment or election.
Bermuda
law also grants us the power generally to indemnify a director, alternate
director, officer, member of a committee authorized under bye-law 103, resident
representative or their respective heirs, executors or administrators to the
company in defending any proceedings, whether civil or criminal, in which
judgment is given in his favor, or in which he is acquitted, or in connection
with any application under the Companies Act in which relief from liability is
granted to him by the court.
Under our
bye-laws, our shareholders agree to waive any claim or right of action they
might have, whether individually or by right of the Company, against any
director, alternate director, officer, person or member of a committee
authorized under bye-law 103, resident representative of the company or any of
their respective heirs, executors or administrators due to any action taken by
any such person, or the failure of any such person to take any action in the
performance of his duties, or supposed duties, to us or otherwise in relation
thereto.
Notwithstanding
any of the foregoing, no indemnity, waiver or exclusion of liability contained
in our bye-laws in favor of any person is effective in respect of liabilities
arising from such person's own fraud or dishonesty.
Under our
bye-laws, our board of directors may in its sole discretion, declare dividends
or distributions and pay a fixed cash dividend bi-annually or on other dates.
Under Bermuda law, the board of directors has no discretion to declare or pay a
dividend if there are reasonable grounds for believing that (a) the Company is,
or would after the payment be, unable to pay its liabilities as they become due;
or (b) the realizable value of the Company's assets would thereby be less than
the aggregate of its liabilities and its issued share capital and share premium
accounts.
In the
event of our liquidation, dissolution or winding up, our shareholders have the
right to receive a pro rata share, in a proportion equal to their proportionate
shareholding, of the surplus assets of the Company after all of the Company's
liabilities are discharged. A liquidator may, with the sanction of a 2/3
majority vote at a general meeting and after the discharge of all of the
Company's liabilities, divide among our shareholders in specie or in kind the
whole or any part of the remaining assets and may, for such purposes, assign
such values as he deems fair.
Anti-Takeover
Effects of Provisions of Our Constitutional Documents
Several
provisions of our bye-laws may have anti-takeover effects. These provisions are
intended to avoid costly takeover battles, lessen our vulnerability to a hostile
change of control and enhance the ability of our board of directors to maximize
shareholder value in connection with any unsolicited offer to acquire us.
However, these anti-takeover provisions, which are summarized below, could also
discourage, delay or prevent (1) the merger, amalgamation or acquisition of our
company by means of a tender offer, a proxy contest or otherwise, that a
shareholder may consider in its best interest and (2) the removal of our
incumbent directors and executive officers.
Should a
person or persons resident for tax purposes in Norway, other than Nordea Bank
Norge ASA, become the holder of 50% or more of the aggregate of our issued and
outstanding common stock, being held or owned directly or indirectly, we will be
entitled to dispose of such number of shares that would reduce the person or
persons ownership of our common stock to under 50%.
Where a
person or entity becomes the owner of more than 30% of our issued and
outstanding common stock, our board of directors can decline to register the
acquired common shares in excess of 30% unless the acquirer makes an offer to
purchase our remaining shares of common stock or agrees to sell part of the
shares of common stock acquired to reduce the number of our common shares held
by them to below 30% of our issued and outstanding common stock. Sale of the
acquirer's shares over 30% of the issued and outstanding common stock must take
place no later than two weeks from when his total share ownership rose above
30%, the acquisition date. Offers to purchase our remaining shares must occur
within four weeks of the acquisition date and the offer price must be at least
as high as the highest price paid by the acquirer in the six months prior to the
acquisition date. Should the acquirer fail to reduce his common shares or make
an offer for the outstanding common shares with the time period, the acquirer
will not be able to exercise any rights associated with the shares in excess of
30% of our outstanding and issued common stock.
There is
a statutory remedy under Section 111 of the Bermuda Companies Act 1981 which
provides that a shareholder may seek redress in the Bermuda courts as long as
such shareholder can establish that a company's affairs are being conducted, or
have been conducted, in a manner oppressive or prejudicial to the interests of
some part of the shareholders, including such shareholder.
C.
MATERIAL CONTRACTS
The
Company has no material contracts other than those entered in the ordinary
course of business.
D.
EXCHANGE CONTROLS
The
Bermuda Monetary Authority (the "BMA") must give permission for all issuances
and transfers of securities of a Bermuda exempted company like ours. We have
received general permission from the BMA to issue any unissued common shares and
for the free transferability of our common shares as long as our common shares
are listed on an "appointed stock exchange". Our common shares are
listed on the Oslo Stock Exchange and the New York Stock Exchange – each of
which is an "appointed stock exchange". Our common shares may
therefore be freely transferred among persons who are residents and
non-residents of Bermuda.
Although
we are incorporated in Bermuda, we are classified as a non-resident of Bermuda
for exchange control purposes by the BMA. Other than transferring
Bermuda Dollars out of Bermuda, there are no restrictions on our ability to
transfer funds into and out of Bermuda or to pay dividends to US residents who
are holders of Common Shares or other nonresidents of Bermuda who are holders of
our common shares in currency other than Bermuda Dollars.
In
accordance with Bermuda law, share certificates may be issued only in the names
of corporations, individuals or legal persons. In the case of an applicant
acting in a special capacity (for example, as an executor or trustee),
certificates may, at the request of the applicant,
record
the capacity in which the applicant is acting. Notwithstanding the recording of
any such special capacity, we are not bound to investigate or incur any
responsibility in respect of the proper administration of any such estate or
trust.
We will
take no notice of any trust applicable to any of our shares or other securities
whether or not we had notice of such trust.
As an
"exempted company", we are exempt from Bermuda laws which restrict the
percentage of share capital that may be held by non-Bermudians, but as an
exempted company, we may not participate in certain business transactions
including: (i) the acquisition or holding of land in Bermuda (except that
required for its business and held by way of lease or tenancy for terms of not
more than 21 years) without the express authorization of the Bermuda
legislature; (ii) the taking of mortgages on land in Bermuda to secure an amount
in excess of $50,000 without the consent of the Minister of Finance of Bermuda;
(iii) the acquisition of securities created or issued by, or any interest in,
any local company or business, other than certain types of Bermuda government
securities or securities of another "exempted company", "exempted partnership"
or other corporation or partnership resident in Bermuda but incorporated abroad;
or (iv) the carrying on of business of any kind in Bermuda, except in so far as
may be necessary for the carrying on of its business outside Bermuda or under a
license granted by the Minister of Finance of Bermuda.
The
Bermuda government actively encourages foreign investment in "exempted" entities
like us that are based in Bermuda but do not operate in competition with local
business. In addition to having no restrictions on the degree of foreign
ownership, we are subject neither to taxes on our income or dividends nor to any
exchange controls in Bermuda. In addition, there is no capital gains tax in
Bermuda, and profits can be accumulated by us, as required, without limitation.
There is no income tax treaty between the United States and Bermuda pertaining
to the taxation of income other than applicable to insurance
enterprises.
E.
TAXATION
The
following is a discussion of the material Bermuda, United States federal income
and other tax considerations with respect to the Company and holders of common
shares. This discussion does not purport to deal with the tax consequences of
owning common shares to all categories of investors, some of which, such as
dealers in securities, investors whose functional currency is not the United
States Dollar and investors that own, actually or under applicable constructive
ownership rules, 10% or more of our common shares, may be subject to special
rules. This discussion deals only with holders who hold the common shares as a
capital asset. Holders of common shares are encouraged to consult their own tax
advisors concerning the overall tax consequences arising in their own particular
situation under United States federal, state, local or foreign law of the
ownership of common shares.
Bermuda
and Other Non-U.S. Tax Considerations
As of the
date of this document, we are not subject to taxation under the laws of Bermuda,
and distributions to us by our subsidiaries also are not subject to any Bermuda
tax. As of the date of this document, there is no Bermuda income, corporation or
profits tax, withholding tax, capital gains tax, capital transfer tax, estate
duty or inheritance tax payable by non-residents of Bermuda in respect of
capital gains realized on a disposition of our common shares or in respect of
distributions by us with respect to our common shares. This discussion does not,
however, apply to the taxation of persons ordinarily resident in Bermuda.
Bermuda holders should consult their own tax advisors regarding possible Bermuda
taxes with respect to dispositions of, and distributions on, our common
shares.
Under
current Bermuda law, we are not subject to tax on income or capital gains. We
have received from the Minister of Finance under The Exempted Undertaking Tax
Protection Act 1966, as amended, an assurance that, in the event that Bermuda
enacts legislation imposing tax computed on profits, income, any capital asset,
gain or appreciation, or any tax in the nature of estate duty or inheritance,
the imposition of any such tax shall not be applicable to us or to any of our
operations or shares, debentures or other obligations, until March 28, 2016.
This assurance is subject to the proviso that it is not to be construed to
prevent the application of any tax or duty to such persons as are ordinarily
resident in Bermuda or to prevent the application of any tax payable in
accordance with the provisions of the Land Tax Act 1967. The
assurance does not exempt us from paying import duty on goods imported into
Bermuda. In addition, all entities employing individuals in Bermuda
are required to pay a payroll tax and there are other sundry taxes payable,
directly or indirectly, to the Bermuda government. We and our
subsidiaries incorporated in Bermuda pay annual government fees to the Bermuda
government.
The
March 28, 2016 date is common to all exempted companies incorporated in
Bermuda. It is expected, based on past practices, that the Minister
of Finance will extend that date and the application of the
assurance. If the Minister of Finance does not grant a new exemption
or extend our current assurance, and if the Bermudian Parliament passes
legislation imposing taxes on exempted companies, we may become subject to
taxation in Bermuda at some point after March 28,
2016.
Bermuda
currently has no tax treaties in place with other countries in relation to
double-taxation or for the withholding of tax for foreign tax
authorities.
Dividends
distributed by Seadrill Limited out of Bermuda
Currently,
there are no withholding taxes payable in Bermuda on dividends distributed from
Seadrill Limited to its shareholders.
Taxation
of rig owning entities
The
majority of our drilling rigs are owned in tax-free jurisdictions such as
Bermuda, Cayman Islands and Liberia. There is no taxation of the rig owners'
income in these jurisdictions. The remaining drilling rigs are owned in
jurisdictions with income or tonnage taxation of the rig owners' income. These
jurisdictions are Cyprus, Hong Kong, Hungary, Singapore and
Svalbard.
Please
also see the section below entitled "Taxation in country of drilling
operations".
Taxation
in country of drilling operations
Income
derived from drilling operations is generally taxed in the country where these
operations take place (currently including Angola, Australia, Brazil, China,
Congo, Denmark, Indonesia, Malaysia, Nigeria, Norway, Thailand, UK, USA and
Vietnam). The taxation of income derived from drilling operations could be based
on net income, deemed income and/or withholding taxes etc, depending upon the
applicable tax legislation in each country of operation. Some
countries levy withholding taxes on bareboat charter payments (internal rig
rent), branch profits, crew, dividends, interest and management
fees.
Drilling
operations can be carried out by locally incorporated companies, foreign
branches of operating companies or foreign branches of the rig owning entities.
We elect the appropriate structure having regard to the applicable legislation
of each country where the drilling operations occur.
In some
countries where the drilling operations are performed, a tax liability may also
arise for the rig owning entity.
Net
income
Net
income corresponds to gross income for the drilling operations less
tax-deductible costs (i.e. operating costs, crew, insurance, management fees and
capital costs (internal bareboat fee or tax depreciation and interest costs)
incurred in relation to those operations. In addition to net income
tax, withholding tax on branch profits, dividends, internal bareboat fees etc
may also be levied.
Net
income taxation for an international drilling contractor is complex, and pricing
of internal transactions (rig sales, bareboat fees and services etc.) will
allocate overall taxable income between the relevant countries. We apply OECD
Transfer Pricing Guidelines as a basis to arrive at pricing for internal
transactions. OECD Transfer Pricing Guidelines describe various methods to
arrive at pricing of internal services based on terms believed by us to be no
less favorable than are available from unaffiliated third parties, and disputes
can arise with tax authorities regarding whether the pricing of such internal
transactions is correct.
Deemed
income
Deemed
income tax is normally calculated based on gross turnover, which can include or
exclude reimbursables and often reflects an assumed profit ratio, multiplied by
the applicable corporate tax rate. Some countries will also levy withholding
taxes on the distribution of dividend/branch profits at the deemed tax
rate.
Withholding
taxes etc. in country of drilling operations
Some
countries base their taxation solely on withholding tax on gross
turnover. In addition, some countries levy stamp duties, training
taxes or similar taxes on the gross turnover.
Customs
duties
Customs
duties are generally payable on the importation of drilling rigs, equipment and
spares into the country of operation, although several countries provide
exemption from such duties for the temporary importation of drilling rigs. This
exemption may also apply to the temporary importation of equipment.
Taxation
of other income
Other
income related to crewing, management fees and technical services will be
generally taxed in the country of residency of the service provider, although
withholding tax and/or income tax may also be imposed in the country where the
drilling operations take place.
Financial
income, dividend income, and investment income will be taxable in accordance
with the legislation applicable in the country in which the company holding the
investment is resident. For companies resident in Bermuda, there is currently no
tax on these types of income.
Some
countries levy withholding taxes on outbound dividends and interest
payments.
Capital
gains taxation
For rigs
located in Bermuda, Cayman Islands, Cyprus, Liberia and Singapore, no capital
gains tax is payable in these countries. However, some countries may apply a
capital gains tax or a claw-back of tax depreciation (whole or part) when
drilling rigs are sold while working in the country of operation, or within a
certain time after completion of such drilling operations, or when the rig is
exported after completion of such drilling operations.
Other
taxes
Our
operations may be applicable to sales taxes, VAT or similar taxes in various
countries.
Taxation
of shareholders
Taxation
of shareholders will depend upon the jurisdiction where the shareholder is a tax
resident. Shareholders should seek advice from their tax advisor to establish
the relevant taxation applicable to their circumstances.
United
States Federal Income Tax Considerations
In the
opinion of Seward & Kissel LLP, our United States counsel, the following are
the material United States federal income tax consequences to us of our
activities and to U.S. Holders and Non-U.S. Holders, each as defined below, of
our common stock. This discussion does not purport to deal with the
tax consequences of owning common stock to all categories of investors, some of
which, such as dealers in securities, investors whose functional currency is not
the United States Dollar and investors that own, actually or under applicable
constructive ownership rules, 10 percent or more of our common stock, may be
subject to special rules. The following discussion of United States
federal income tax matters is based on the United States Internal Revenue Code
of 1986, or the Code, judicial decisions, administrative pronouncements, and
existing and proposed regulations issued by the United States Department of the
Treasury, all of which are subject to change, possibly with retroactive
effect. The discussion below is based, in part, on the description of
our business as described herein and assumes that we conduct our business as
described herein. Unless otherwise noted, references in the following
discussion to the "Company," "we" and "us" are to Seadrill Limited and its
subsidiaries on a consolidated basis.
United
States Federal Income Taxation of U.S. Holders
As used
herein, the term "U.S. Holder" means a beneficial owner of common stock that is
a United States citizen or resident, United States corporation or other United
States entity taxable as a corporation, an estate the income of which is subject
to United States federal income taxation regardless of its source, or a trust if
a court within the United States is able to exercise primary jurisdiction over
the administration of the trust and one or more United States persons have the
authority to control all substantial decisions of the trust.
If a
partnership holds our common stock, the tax treatment of a partner will
generally depend upon the status of the partner and upon the activities of the
partnership. If you are a partner in a partnership holding our common stock, you
are encouraged to consult your tax advisor.
Distributions
Subject
to the discussion of passive foreign investment companies below, any
distributions made by us with respect to our common stock to a U.S. Holder will
generally constitute dividends, which may be taxable as ordinary income or
"qualified dividend income" as described in more detail below, to the extent of
our current or accumulated earnings and profits, as determined under United
States federal income tax principles. Distributions in excess of our earnings
and profits will be treated first as a nontaxable return of capital to the
extent of the U.S. Holder's tax basis in his common stock on a dollar-for-dollar
basis and thereafter as capital gain. Because we are not a United States
corporation, U.S. Holders that are corporations will not be entitled to claim a
dividends received deduction with respect to any distributions they receive from
us. Dividends paid with respect to our common stock will generally be treated as
"passive category income" or, in the case of certain types of U.S. Holders,
"general category income" for purposes of computing allowable foreign tax
credits for United States foreign tax credit purposes.
Dividends
paid on our common stock to a U.S. Holder who is an individual, trust or estate
(a "U.S. Individual Holder") will generally be treated as "qualified dividend
income" that is taxable to such U.S. Individual Holders at preferential tax
rates (through 2010) provided that (1) the common stock is readily tradable on
an established securities market in the United States (such as the New York
Stock Exchange, on which we plan to list our common stock); (2) we are not a
passive foreign investment company for the taxable year during which the
dividend is paid or the immediately preceding taxable year (as discussed below);
and (3) the U.S. Individual Holder has owned the common stock for more than 60
days in the 121-day period beginning 60 days before the date on which the common
stock becomes ex-dividend. There is no assurance that any dividends paid on our
common stock will be eligible for these preferential rates in the hands of a
U.S. Individual Holder. Legislation has been previously introduced in
the U.S. Congress which, if enacted in its present form, may preclude our
dividends from qualifying for such preferential rates prospectively from the
date of the enactment. Any dividends paid by the Company which are
not eligible for these preferential rates will be taxed as ordinary income to a
U.S. Holder.
Special
rules may apply to any "extraordinary dividend" generally, a dividend in an
amount which is equal to or in excess of ten percent of a stockholder's adjusted
basis (or fair market value in certain circumstances) in a share of common stock
paid by us. If we pay an "extraordinary dividend" on our common stock that is
treated as "qualified dividend income," then any loss derived by a U.S.
Individual Holder from the sale or exchange of such common stock will be treated
as long-term capital loss to the extent of such dividend.
Sale,
Exchange or other Disposition of Common Stock
Assuming
we do not constitute a passive foreign investment company for any taxable year,
a U.S. Holder generally will recognize taxable gain or loss upon a sale,
exchange or other disposition of our common stock in an amount equal to the
difference between the
amount
realized by the U.S. Holder from such sale, exchange or other disposition and
the U.S. Holder's tax basis in such stock. Such gain or loss will be treated as
long-term capital gain or loss if the U.S. Holder's holding period is greater
than one year at the time of the sale, exchange or other disposition. Such
capital gain or loss will generally be treated as United States source income or
loss, as applicable, for U.S. foreign tax credit purposes. A U.S. Holder's
ability to deduct capital losses is subject to certain limitations.
Passive
Foreign Investment Company Status and Significant Tax Consequences
Special
United States federal income tax rules apply to a U.S. Holder that holds stock
in a foreign corporation classified as a passive foreign investment company (a
"PFIC") for United States federal income tax purposes. In general, a foreign
corporation will be treated as a PFIC with respect to a United States
shareholder in such foreign corporation, if, for any taxable year in which such
shareholder holds stock in such foreign corporation, either:
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at
least 75 percent of the corporation's gross income for such taxable year
consists of passive income (e.g., dividends, interest, capital gains and
rents derived other than in the active conduct of a rental business);
or
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·
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at
least 50 percent of the average value of the assets held by the
corporation during such taxable year produce, or are held for the
production of, passive income.
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For
purposes of determining whether a foreign corporation is a PFIC, it will be
treated as earning and owning its proportionate share of the income and assets,
respectively, of any of its subsidiary corporations in which it owns at least 25
percent of the value of the subsidiary's stock.
Income
earned by a foreign corporation in connection with the performance of services
would not constitute passive income. By contrast, rental income would generally
constitute "passive income" unless the foreign corporation is treated under
specific rules as deriving its rental income in the active conduct of a trade or
business or is received from a related party.
We
presently believe that we are not a PFIC and do not anticipate becoming a
PFIC. This is, however, a factual determination made on an annual
basis and is subject to change. Therefore, we can give you no
assurance as to our PFIC status.
As
discussed more fully below, if we were to be treated as a PFIC for any taxable
year, a U.S. Holder would be subject to different taxation rules depending on
whether the U.S. Holder makes an election to treat us as a "Qualified Electing
Fund," which election we refer to as a "QEF election." As an alternative to
making a QEF election, a U.S. Holder should be able to make a "mark-to-market"
election with respect to our common stock, as discussed below.
Taxation
of U.S. Holders Making a Timely QEF Election
If a U.S.
Holder makes a timely QEF election, which U.S. Holder we refer to as an
"Electing Holder," the Electing Holder must report each year for United States
federal income tax purposes his pro rata share of our ordinary earnings and our
net capital gain, if any, for our taxable year that ends with or within the
taxable year of the Electing Holder, regardless of whether or not distributions
were received from us by the Electing Holder. The Electing Holder's adjusted tax
basis in the common stock will be increased to reflect taxed but undistributed
earnings and profits. Distributions of earnings and profits that had been
previously taxed will result in a corresponding reduction in the adjusted tax
basis in the common stock and will not be taxed again once distributed. An
Electing Holder would generally recognize capital gain or loss on the sale,
exchange or other disposition of our common stock. A U.S. Holder would make a
QEF election with respect to any year that our company is a PFIC by filing IRS
Form 8621 with his United States federal income tax return. If we were aware
that we or any of our subsidiaries were to be treated as a PFIC for any taxable
year, we would, if possible, provide each U.S. Holder with all necessary
information in order to make the QEF election described above. If we
were to be treated as a PFIC, a U.S. Holder would be treated as owning his
proportionate share of stock in each of our subsidiaries which is treated as a
PFIC and such U.S. Holder would need to make a separate QEF election for any
such subsidiaries. It should be noted that we may not be able to
provide such information if we did not become aware of our status as a PFIC in a
timely manner.
Taxation
of U.S. Holders Making a "Mark-to-Market" Election
Alternatively,
if we were to be treated as a PFIC for any taxable year and, as we anticipate,
our stock is treated as "marketable stock," a U.S. Holder would be allowed to
make a "mark-to-market" election with respect to our common stock, provided the
U.S. Holder completes and files IRS Form 8621 in accordance with the relevant
instructions and related Treasury Regulations. The "mark-to-market"
election will not be available for any of our subsidiaries. If that election is
made, the U.S. Holder generally would include as ordinary income in each taxable
year the excess, if any, of the fair market value of the common stock at the end
of the taxable year over such holder's adjusted tax basis in the common stock.
The U.S. Holder would also be permitted an ordinary loss in respect of the
excess, if any, of the U.S. Holder's adjusted tax basis in the common stock over
its fair market value at the end of the taxable year, but only to the extent of
the net amount previously included in income as a result of the mark-to-market
election. A U.S. Holder's tax basis in his common stock would be adjusted to
reflect any such income or loss amount. Gain realized on the sale, exchange or
other disposition of our common stock would be treated as ordinary income, and
any loss realized on the sale, exchange or other disposition of the common stock
would be treated as ordinary loss to the extent that such loss does not exceed
the net mark-to-market gains previously included by the U.S.
Holder. It should be noted that the mark-to-market election would
likely not be available for any of our subsidiaries which are treated as
PFICs.
Taxation
of U.S. Holders Not Making a Timely QEF or Mark-to-Market Election
Finally,
if we were to be treated as a PFIC for any taxable year, a U.S. Holder who does
not make either a QEF election or a "mark-to-market" election for that year,
whom we refer to as a "Non-Electing Holder," would be subject to special rules
with respect to (1) any excess distribution (i.e., the portion of any
distributions received by the Non-Electing Holder on our common stock in a
taxable year in excess of 125 percent of the average annual distributions
received by the Non-Electing Holder in the three preceding taxable years, or, if
shorter, the Non-Electing Holder's holding period for the common stock), and (2)
any gain realized on the sale, exchange or other disposition of our common
stock. Under these special rules:
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the
excess distribution or gain would be allocated ratably over the
Non-Electing Holders' aggregate holding period for the common
stock;
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the
amount allocated to the current taxable year and any taxable year before
we became a PFIC would be taxed as ordinary income;
and
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the
amount allocated to each of the other taxable years would be subject to
tax at the highest rate of tax in effect for the applicable class of
taxpayer for that year, and an interest charge for the deemed deferral
benefit would be imposed with respect to the resulting tax attributable to
each such other taxable year.
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These
penalties would not apply to a pension or profit sharing trust or other
tax-exempt organization that did not borrow funds or otherwise utilize leverage
in connection with its acquisition of our common stock. If a Non-Electing Holder
who is an individual dies while owning our common stock, such holder's successor
generally would not receive a step-up in tax basis with respect to such
stock.
United
States Federal Income Taxation of "Non-U.S. Holders"
A
beneficial owner of common stock that is not a U.S. Holder is referred to herein
as a "Non-U.S. Holder."
Dividends
on Common Stock
Non-U.S.
Holders generally will not be subject to United States federal income tax or
withholding tax on dividends received from us with respect to our common stock,
unless that income is effectively connected with the Non-U.S. Holder's conduct
of a trade or business in the United States. If the Non-U.S. Holder is entitled
to the benefits of a United States income tax treaty with respect to those
dividends, that income is taxable only if it is attributable to a permanent
establishment maintained by the Non-U.S. Holder in the United
States.
Sale,
Exchange or Other Disposition of Common Stock
Non-U.S.
Holders generally will not be subject to United States federal income tax or
withholding tax on any gain realized upon the sale, exchange or other
disposition of our common stock, unless:
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the
gain is effectively connected with the Non-U.S. Holder's conduct of a
trade or business in the United States. If the Non-U.S. Holder is entitled
to the benefits of an income tax treaty with respect to that gain, that
gain is taxable only if it is attributable to a permanent establishment
maintained by the Non-U.S. Holder in the United States;
or
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the
Non-U.S. Holder is an individual who is present in the United States for
183 days or more during the taxable year of disposition and other
conditions are met.
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If the
Non-U.S. Holder is engaged in a United States trade or business for United
States federal income tax purposes, the income from the common stock, including
dividends and the gain from the sale, exchange or other disposition of the stock
that is effectively connected with the conduct of that trade or business will
generally be subject to regular United States federal income tax in the same
manner as discussed in the previous section relating to the taxation of U.S.
Holders. In addition, if you are a corporate Non-U.S. Holder, your earnings and
profits that are attributable to the effectively connected income, which are
subject to certain adjustments, may be subject to an additional branch profits
tax at a rate of 30 percent, or at a lower rate as may be specified by an
applicable income tax treaty.
Backup
Withholding and Information Reporting
In
general, dividend payments, or other taxable distributions, made within the
United States to you will be subject to information reporting requirements. Such
payments will also be subject to backup withholding tax if paid to a
non-corporate U.S. Holder who:
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fails
to provide an accurate taxpayer identification
number;
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is
notified by the Internal Revenue Service that he has failed to report all
interest or dividends required to be shown on his federal income tax
returns; or
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in
certain circumstances, fails to comply with applicable certification
requirements.
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Non-U.S.
Holders may be required to establish their exemption from information reporting
and backup withholding by certifying their status on Internal Revenue Service
Form W-8BEN, W-8ECI or W-8IMY, as applicable.
If a
Non-U.S. Holder sells his common stock to or through a United States office or
broker, the payment of the proceeds is subject to both United States backup
withholding and information reporting unless the Non-U.S. Holder certifies that
he is a non-U.S. person, under penalties of perjury, or otherwise establishes an
exemption. If a Non-U.S. Holder sells his common stock through a non-United
States office of a non-United States broker and the sales proceeds are paid to
the Non-U.S. Holder outside the United States then information reporting and
backup withholding generally will not apply to that payment. However,
United States information reporting requirements, but not backup withholding,
will apply to a payment of sales proceeds, even if that payment is made to a
Non-U.S. Holder outside the United States, if the Non-U.S. Holder sells common
stock through a non-United States office of a broker that is a United States
person or has some other contacts with the United States.
Backup
withholding tax is not an additional tax. Rather, a taxpayer
generally may obtain a refund of any amounts withheld under backup withholding
rules that exceed the taxpayer's income tax liability by filing a refund claim
with the Internal Revenue Service.
Other
Tax Considerations
In
addition to the tax consequences discussed above, we may be subject to tax in
one or more other jurisdictions where we conduct activities. The
amount of any such tax imposed upon our operations may be material.
F.
DIVIDENDS AND PAYING AGENTS
Not
applicable.
G.
STATEMENT BY EXPERTS
Not
applicable.
H.
DOCUMENTS ON DISPLAY
We are
subject to the informational requirements of the Securities Exchange Act of
1934, as amended. In accordance with these requirements we file reports and
other information with the Commission. These materials, including this annual
report on Form 20-F and the accompanying exhibits, may be inspected and copied
at the public reference facilities maintained by the Commission at 100 F Street,
NE, Room 1580, Washington, D.C. 20549. You may obtain information on
the operation of the public reference room by calling 1 (800) SEC-0330, and you
may obtain copies at prescribed rates from the Public Reference Section of the
Commission at its principal office in Washington, D.C. The Commission
maintains a website (http://www.sec.gov.) that contains reports, proxy and
information statements and other information regarding registrants that file
electronically with the Commission. In addition, documents referred to in this
annual report on Form 20-F may be inspected at our principle executive offices
at Par-la-Ville Place, 14 Par-la-Ville Road, Hamilton, Bermuda HM 08 and at the
offices of Seadrill Management AS at Løkkeveien 111, 4007 Stavanger,
Norway.
I.
SUBSIDIARY INFORMATION
Not
applicable
ITEM
11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are
exposed to various market risks, including foreign currency fluctuations,
changes in interest rates, equity and credit risk. Our policy is to
hedge our exposure to these risks where possible, within boundaries deemed
appropriate by management. We accomplish this by entering into a
variety of derivative instruments and contracts to maintain the desired level of
risk exposure. We may enter into derivative instruments from time to time for
speculative purposes.
Foreign
Exchange Risk
The
Company and the majority of its subsidiaries use the U.S. Dollar as their
functional currency because the majority of their revenues and expenses are
denominated in U.S. Dollars. Accordingly, the Company's reporting currency is
also U.S. Dollars. We do, however, earn revenue and incur expenses in other
currencies and there is thus a risk that currency fluctuations could have an
adverse effect on the value of our cash flows.
Our
foreign currency risk arises from:
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the
measurement of debt and other monetary assets and liabilities denominated
in foreign currencies converted to U.S. Dollars, with the resulting gain
or loss recorded as "Other financial
items";
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changes
in the fair value of foreign currency forward contracts, which are
recorded as "Other financial
items";
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the
impact of fluctuations in exchange rates on the reported amounts of our
revenues and expenses which are contracted in foreign currencies;
and
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foreign
subsidiaries whose accounts are not maintained in U.S. Dollars, which when
converted into U.S. Dollars can result in exchange adjustments which are
recorded as a component in shareholders'
equity.
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We use
foreign currency forward contracts to manage our exposure to foreign currency
risk on certain assets, liabilities and future anticipated transactions. Such
derivative contracts do not qualify for hedge accounting treatment and are
recorded in the balance sheet under "Other current assets" if the forward
contracts have a net positive fair value, and under "Other current liabilities"
if the forward contracts have a net negative fair value, with changes in the
fair value recorded in the statement of operations under "Other financial
items". At December 31, 2009, we had various forward contracts to
sell approximately $504 million between January 2010 and September 2012 for
Norwegian Kroner and Singapore Dollars at exchange rates ranging from
NOK/US$5.71 to NOK/US$6.40 and from SGD/US$1.39 to SGD/US$1.42. The fair value
of our currency forward contracts as at December 3, 2009, and December 31, 2008,
was as follows:
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December 31, 2009
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December 31, 2008
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(In
millions of U.S. Dollars)
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Notional
Amount
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Fair
value
|
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Notional
Amount
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Fair
Value
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Other
current assets (liabilities)
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504
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16
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|
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474
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|
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(21
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)
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A 1%
change in the exchange rate between the U.S. Dollar and the bought forward
currencies would result in a fair value gain or loss of $5.0 million that would
be reflected in our Consolidated Statements of Operations, based on our currency
forward contracts as at December 31,2009.
Interest
Rate Risk
A
significant portion of our debt obligations and surplus funds placed with
financial institutions are subject to movements in interest rates. It is our
policy to obtain the most favorable interest rates available without increasing
our foreign currency exposure. In keeping with this, our surplus funds are
placed in fixed deposits with reputable financial institutions which yield
better returns than bank deposits. The deposits generally have short-term
maturities so as to provide us with the flexibility to meet working capital and
capital investments.
We use
interest rate swaps to manage our exposure to interest rate risks. Interest rate
swaps are used to convert floating rate debt obligations to a fixed rate in
order to achieve an overall desired position of fixed and floating rate debt.
The extent to which interest rate swaps are used is determined by reference to
our net debt exposure and our views regarding future interest rates. Most of our
interest rate swaps do not qualify for hedge accounting and movements in their
fair values are reflected in the statement of operations under "gain/(loss) on
derivative financial instruments". Interest rate swap agreements that have a
positive fair value are recorded as "Other current assets", while swaps with a
negative fair value are recorded as "Other current liabilities".
At
December 31, 2009, we had entered into interest rate swap agreements with a
combined outstanding principal amount of approximately $2.85 billion at rates
between 2.06% per annum and 4.63% per annum. The swap agreements mature between
December 2011 and December 2018. The fair values of our interest rate swaps as
at December 31, 2009, and December 31, 2008, were as follows:
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December 31, 2009
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December 31, 2008
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(In
millions of U.S. Dollars)
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Outstanding
principal
|
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Fair
value
|
|
|
Outstanding
principal
|
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Fair
Value
|
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Other
current assets (liabilities)
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2,854
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(70
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)
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1,740
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|
(146
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)
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In
addition to the above interest rate swaps, two of our fully-consolidated VIEs
have executed interest rate cash flow hedges in the form of interest rate swaps.
Movements in their fair value are reflected in "Accumulated other comprehensive
income (loss)", with their fair value recorded as "Other current assets" or
"Other current liabilities". At December 31, 2009, the fully-consolidated VIEs
had entered into interest rate swap agreements with a combined outstanding
principal amount of $1.27 billion at rates between 2.19% per annum and 3.89% per
annum. These swap agreements mature between October 2012 and August 2013, and
their fair values as at December 31, 2009, and December 31, 2008, were as
follows:
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|
December 31, 2009
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December 31, 2008
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|
|
D
|
|
Outstanding
principal
|
|
|
Fair
value
|
|
|
Outstanding
principal
|
|
|
Fair
Value
|
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Other
current assets (liabilities)
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1,268
|
|
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(33
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)
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1,139
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|
|
(55
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)
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At
December 31, 2009, our net exposure to floating interest rate fluctuations on
our outstanding debt was $0.88billion, compared with $3.04 billion at December
31, 2008. This net exposure is based on our $5.00billion of floating rate debt
less the $2.85billion outstanding principal covered by our interest rate swaps
and less the $1.27 billion outstanding principal of our VIEs' interest rate
hedges at December 31, 2009. A 1% change in short-term interest rates would thus
increase or decrease our interest expense by approximately $9 million on an
annual basis as of December 31, 2009 (December 31, 2008: $30
million).
Equity
risk
At
December 31, 2009, we had entered into a TRS contract indexed to 4,500,000 of
our own shares, whereby we carry the risk of fluctuations in the market price of
our shares. The settlement amount for the contract will be (A) the market value
of the shares at the date of settlement plus the amount of dividends paid on the
shares by us between entering into and settling the contract, less (B) the
reference price of the shares agreed at the inception of the contract plus the
counterparty's financing costs. Settlement will be either a payment from or to
the counterparty, depending on whether (A) is more or less than (B). The
contract was scheduled to expire in February 2010 and the agreed reference price
was NOK98.44 per common share. The open position at December 31, 2009, exposes
us to market risk associated with our share price, and it is estimated that a
10% reduction in the price below the value at December 31, 2009, would generate
an adverse fair value adjustment of up to $7.7 million, which would be recorded
in the Statement of Operations. In February 2010 the number of shares underlying
the TRS agreement was reduced by 1,000,000 shares to 3,500,000 shares and the
agreement was extended to February 2011. Early termination of this
TRS agreement is possible. The new reference price is NOK125.70 per common
share.
In
addition to the above TRS transaction indexed to our own shares, we may from
time to time enter into short-term TRS arrangements relating to securities in
other companies.
The fair
market value of our $1.00 billion 3.625% convertible bonds at December 31, 2009,
was $1.00 billion (2008: $0.51 billion). The fair market value of our $0.50
billion 4.875% convertible bonds at December 31, 2009, was
$0.61billion.
Concentration
of credit risk
The
market for our services is the offshore oil and gas industry, and the customers
consist primarily of major integrated oil companies, independent oil and gas
producers and government-owned oil companies. We perform ongoing credit
evaluations of our customers and generally do not require collateral in our
business agreements. Reserves for potential credit losses are maintained when
necessary.
The
following table shows those of our customers who have generated more than nine
percent of our contract revenues in one of the periods shown:
|
|
Year
ended December 31,
|
|
Customer
|
|
2009
|
|
|
2008
|
|
|
2007
|
|
Statoil
|
|
|
17
|
%
|
|
|
32
|
%
|
|
|
33
|
%
|
Shell
|
|
|
10
|
%
|
|
|
7
|
%
|
|
|
13
|
%
|
Total
|
|
|
13
|
%
|
|
|
5
|
%
|
|
|
8
|
%
|
Exxon
|
|
|
12
|
%
|
|
|
5
|
%
|
|
|
6
|
%
|
Petrobras
|
|
|
10
|
%
|
|
|
-
|
|
|
|
-
|
|
Other
customers
|
|
|
38
|
%
|
|
|
51
|
%
|
|
|
40
|
%
|
Total
|
|
|
100
|
%
|
|
|
100
|
%
|
|
|
100
|
%
|
We may
also face credit related losses in the event that counterparties to our
derivative financial instrument contracts do not perform according to the terms
of the contract. The credit risk arising from these counterparties relates to
unrealized profits from foreign exchange forward contracts and interest rate
swaps. We generally do not require collateral for our financial instrument
contracts. We do, however, enter into master netting agreements with our
counterparties to derivative financial instrument contracts to mitigate our
exposure to counterparty credit risks. These agreements provide us with the
legal right to discharge all or a portion of amounts owed to a counterparty by
offsetting against them any amounts that the counterparty may owe
us.
In the
opinion of management, our counterparties are creditworthy financial
institutions, and we do not expect any significant loss to result from their
non-performance. The credit exposure of interest rate swap agreements, currency
option contracts and foreign currency contracts is represented by the fair value
of contracts with a positive fair value at the end of each period, reduced by
the effects of master netting agreements.
ITEM
12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
A.
DEBT SECURITIES
Not
applicable.
B.
WARRANTS AND RIGHTS
Not
applicable.
C.
OTHER SECURITIES
Not
applicable.
D.
AMERICAN DEPOSITORY SHARES
Not
applicable.