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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             Washington, D.C. 20549

                                    Form 20-F

|_|          REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g)
                     OF THE SECURITIES EXCHANGE ACT OF 1934
                                       OR

|X|             ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                   For the fiscal year ended December 31, 2002

                                       OR

|_|           TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
                       THE SECURITIES EXCHANGE ACT OF 1934
                 For the transition period from        to

                        Commission File Number: 333-8766

                             Northern Offshore Ltd.
             (Exact name of registrant as specified in its charter)

                                     Bermuda
                 (Jurisdiction of incorporation or organization)

                         Par-la-Ville Place, 4th Floor,
                               Par-la-Ville Road,
                             Hamilton HM08, Bermuda
                              (Address of principal
                               executive offices)

Securities registered or to be registered pursuant to Section 12(b) of the Act:
None

Securities registered or to be registered pursuant to Section 12(g) of the Act:
None

Securities for which there is a reporting obligation pursuant to Section 15(d)
of the Act: None

     Indicate the number of outstanding shares of each of the issuer's classes
of capital or common stock as of the close of the period covered by the annual
report: 104,680,660 Common Shares, par value $0.25 per share.

     Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days.

                                 Yes |X| No |_|

     Indicate by check mark which financial statement the registrant has elected
to follow.

                             Item 17 |_| Item 18 |X|

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<PAGE>

                                TABLE OF CONTENTS
                                                                            Page
                                                                            ----
                                     PART I
Item 1.        Identity of Directors, Senior Management and Advisors.......... 1
Item 2.        Offer Statistics and Expected Timetable........................ 1
Item 3.        Key Information................................................ 1
Item 4.        Information on the Company.....................................10
Item 5.        Operating and Financial Review and Prospects...................23
Item 6.        Directors, Senior Management and Employees.....................36
Item 7.        Major Shareholders and Related Party Transactions..............39
Item 8.        Financial Information..........................................41
Item 9.        The Offer and Listing..........................................41
Item 10.       Additional Information.........................................42
Item 11.       Quantitative and Qualitative Disclosures about Market Risk.....44
Item 12.       Description of Securities Other Than Equity Securities.........45

                                     PART II
Item 13.       Defaults, Dividend Arrearages and Delinquencies................46
Item 14.       Material Modifications to the Rights of Security Holders
               and Use of Proceeds............................................46
Item 15.       Controls and Procedures........................................46
Item 16.       Reserved
Item 16A.      Audit Committee Financial Expert...............................46
Item 16B.      Code of Ethics.................................................46
Item 16C.      Principal Accountant Fees and Services.........................46
Item 16D.      Exemptions from the Listing Rules for Audit Committees.........47

                                    PART III
Item 17.       Financial Statements...........................................47
Item 18.       Financial Statements...........................................47
Item 19.       Exhibits ......................................................48

<PAGE>

                 CERTAIN DEFINITIONS; U.S. DOLLAR PRESENTATIONS

     Northern Offshore Ltd. ("Northern Offshore") is a company established under
the laws of Bermuda. Northern Offshore is a continuation of the offshore
drilling and production business of Northern Offshore ASA ("NOASA"), a public
limited company established under the laws of the Kingdom of Norway. Northern
Offshore is organized as a holding company that owns several subsidiary
companies. Our subsidiary companies conduct substantially all of our business.
Unless we inform you otherwise or the context indicates otherwise, references to
"we", "us" or "the Company" in this report on Form 20-F are to Northern
Offshore, its predecessors, including NOASA prior to Northern Offshore's
separation from NOASA, and its subsidiaries, collectively.

     We publish our consolidated financial statements in United States dollars.
In this report, references to "dollars," "$" or "USD" are to United States
dollars.

           CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS

     We are including the following discussion to inform our existing and
potential security holders generally of some of the risks and uncertainties that
can affect our company and to take advantage of the "safe harbour" protection
for forward-looking statements that applicable U.S. federal securities law
affords.

     From time to time, our management or persons acting on our behalf make
forward-looking statements to inform existing and potential security holders
about our company. These statements may include projections and estimates
concerning the timing and success of specific projects and our future revenues,
income and capital spending. Forward-looking statements are generally
accompanied by words such as "estimate," "project," "predict," "believe,"
"expect," "anticipate," "plan," "goal" or other words that convey the
uncertainty of future events or outcomes. Sometimes we will specifically
describe a statement as being a forward-looking statement and refer to this
cautionary statement.

     In addition, various statements this report contains, including those that
express a belief, expectation or intention, as well as those that are not
statements of historical fact, are forward-looking statements. Those
forward-looking statements appear in "Information on the Company" in Item 4,
"Operating and Financial Review and Prospects" in Item 5, and "Quantitative and
Qualitative Disclosures About Market Risk" in Item 17 of Part I of this report
and in the Notes to Consolidated Financial Statements we have included in Item
18 of Part III of this report and elsewhere in this report. These
forward-looking statements speak only as of the date of this report. We disclaim
any obligation to update these statements, and we caution you not to rely on
them unduly. We have based these forward-looking statements on our current
expectations and assumptions about future events. While our management considers
these expectations and assumptions to be reasonable, they are inherently subject
to significant business, economic, competitive, regulatory and other risks,
contingencies and uncertainties, most of which are difficult to predict and many
of which are beyond our control. These risks, contingencies and uncertainties
relate to, among other matters, the following:

     o    general economic and business conditions and industry trends;

     o    the condition of the offshore drilling and production services
          industry in the geographic areas where we operate;

     o    decisions about offshore exploration and development projects to be
          made by oil and gas companies;

     o    the highly competitive nature of our businesses;

     o    our future financial performance;

     o    our limited availability of capital and the terms and deployment of
          capital;

     o    whether we will be able to refinance our indebtedness currently due in
          2004 and 2005;

     o    the continued availability of qualified personnel; and

     o    changes in, or our failure or inability to comply with, government
          regulations, including those relating to the environment.

     We believe the items we have outlined above are important factors that
could cause our actual results to differ materially from those expressed in a
forward-looking statement made in this report or elsewhere by us or on our
behalf. We have discussed many of these factors in more detail elsewhere in this
report. These factors are not necessarily all the important factors that could
affect us. Unpredictable or unknown factors we have not discussed in this report
could also have material adverse effects on actual results of matters that are
the subject of our forward-looking statements. We do not intend to update our
description of important factors each time a potential important factor arises.
We advise our security holders that they should (1) be aware that important
factors not referred to above could affect the accuracy of our forward-looking
statements and (2) use caution and common sense when considering our
forward-looking statements.
<PAGE>

                                     PART I

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 following selected financial information has been derived from our
audited consolidated financial statements. Income statement data for 2002,
2001and 2000 and balance sheet data for 2002 and 2001 has been derived from
audited consolidated financial statements included in this report. Income
statement data for 1999 and 1998 and balance sheet data for 2000 and 1999 has
been derived from audited consolidated financial statements not included in this
report. You should read the following information in conjunction with "Operating
and Financial Review and Prospects" and the consolidated financial statements
and the notes thereto included in this report. Those financial statements were
prepared in accordance with U.S. GAAP.

<TABLE>
<CAPTION>
                                                                     Year ended December 31,
                                      --------------------------------------------------------------------------------
                                          2002               2001             2000            1999             1998
                                      -------------       ----------       ----------      ----------       ----------
                                                            (in thousands except per share amounts)
<S>                                   <C>                 <C>              <C>             <C>              <C>
Statement of Operations data:
Total revenues ....................   $      69,299           54,147           58,523          52,644          119,886
Operating profit (loss) ...........   $      (5,201)         (23,792)          21,006          25,034           44,388
Net income (loss) before cumulative
effect of a change in accounting
principle .........................   $     (24,855)         (38,053)          18,564           1,374           37,850
Cumulative effect of a change in
accounting principle(1) ...........   $       6,102              682               --              --               --
Net income (loss) .................   $     (18,753)         (37,371)          18,564           1,374           37,850
Net income (loss) before cumulative
effect of a change in accounting
principle per share
(basic and diluted) ...............   $       (0.24)           (0.39)            0.24            0.02             0.53
Cumulative effect of a change in
accounting principle per share ....   $        0.06             0.01               --              --               --
Net income (loss) per share
(basic and diluted) ...............   $       (0.18)           (0.38)            0.24            0.02             0.53

Weighted average shares outstanding
      Basic .......................     104,680,660       99,293,160       78,217,472      72,000,000       72,000,000
      Diluted .....................     104,680,660       99,293,160       78,591,780      72,000,000       72,000,000
Balance Sheet data:
Total assets ......................   $     170,335          204,127          216,489         246,109          330,911
Total debt ........................   $     187,639          196,372          191,645         247,775          330,000
Share capital .....................   $      26,170           26,170           23,476         102,224          102,224
Stockholders' equity (deficit) ....   $     (27,146)          (9,252)          10,715         (13,973)         (13,625)
</TABLE>

----------
(1)  Cumulative effect of a change in accounting principle in 2002 represents
     the effect of changing from the accruals method to the expense as incurred
     method of accounting for drydocking. Cumulative effect of a change in
     accounting principle in 2001 represents the effect of the adoption of SFAS
     133 on January 1, 2001.

B. Capitalization and Indebtedness

     Not applicable

C. Reasons for the Offer and Use of Proceeds

     Not applicable

D. Risk Factors

Our ability to service our debt depends on our future operating performance,
which is subject to many factors beyond our control. We may not be able to
refinance our indebtedness and our auditors have expressed significant doubt
about our ability to continue as a going concern.

     Even though most of our drilling units are currently laid up, we are
currently generating sufficient earnings under the Texaco Contract (described
below) being performed by Northern Producer and contracts being performed by the
Energy Searcher to cover our daily operating expenses and interest expense on
our indebtedness. However, we have experienced short-term liquidity deficiencies
which have resulted in our inability to pay interest payments on our 10% Senior
Notes due 2005 on the due dates. To date, we have been able to fund these
payments within the available 30-day grace period as granted under the terms of
the Notes Indenture. The minimum rate payments under the Texaco Contract
currently amount to approximately $43.8 million per year. The Energy Searcher is
currently earning a day-rate of $57,000 under its current contract with Daewoo,
which is expected to end in January 2004. Lay-up costs for the four drilling
units that are currently laid up amounts to approximately $3.5 million per year,
and interest on our indebtedness (after giving effect to our repurchases of our
10% Senior Notes due 2005) amount to approximately $18.9 million per year. As of
December 31, 2002, our cash and cash equivalents amounted to approximately $3.3
million.

     We are not currently generating sufficient cash flows from operations to
pay our existing indebtedness, including the 10% Senior Notes due 2005, at
maturity. Accordingly we expect that we will be required to obtain new debt or
equity financing to refinance our indebtedness at maturity, or to sell selected
assets. In April 2003 we arranged extensions of maturities of 3 loans totalling
$20.3 million and NOK 143.0 million (equivalent to $20.6 million) which were
originally due to be repaid in March and April 2003. These loans now have final
maturities between June and October 2004. In the absence of these loan
extensions it is unlikely that we would have been able to refinance this
indebtedness. We are unaware of any sources that would be available to us to
refinance this indebtedness or our Senior Notes at maturity. See "Operating and
Financial Review and Prospects -- Liquidity and Capital Resources" in Item 5 of
Part I of this report.

     Our ability to refinance our obligations under our outstanding 10% Senior
Notes due 2005 and our other outstanding indebtedness will depend in part on our
future operating performance, which is subject to prevailing economic
conditions, industry cycles and financial, business and other factors, many of
which are beyond our control. We can provide no assurance that our business will
generate cash flows sufficient to allow us to refinance our obligations. If we
are unable to generate sufficient cash flows from operations to allow us to
refinance our debt, we may be required, among other things, to restructure all
or a portion of our indebtedness or to sell selected assets or reduce or delay
planned capital expenditures or acquisitions. We can provide no assurance that
any such financing, refinancing or sale of assets would be available on
economically favourable terms or at all.

     Our Board of Directors is currently considering a proposal whereby the
Company's unsecured creditors would be asked to convert their claims into an
equity stake in the Company. We can give no assurance that any proposed debt to
equity conversion would be accepted by creditors.

     Our auditors have expressed significant doubt about our ability to continue
as a going concern. See "Financial Statements - Independent Auditor's Report" in
Item 18 of Part III of this report.

We have substantial indebtedness that limits our financial flexibility and will
impact our future operations. We have a working capital deficit and our capital
resources are very limited.

     At December 31, 2002, our total debt was approximately $187.6 million of
which $10.6 million was due in 2003, $33.8 million is due in 2004 and $143.2
million is due in 2005. Our total assets were approximately $170.3 million and
our shareholders' deficit was approximately $27.1 million. We also had a working
capital deficit at December 31, 2002. Subject to the restrictions in the
indenture relating to our outstanding 10% Senior Notes due 2005, we may incur
additional indebtedness from time to time to provide working capital, to finance
acquisitions or capital expenditures and for other purposes, although we are
unaware of presently available sources for additional indebtedness. The level of
our indebtedness has several important effects on our future operations,
including, without limitation:

     o    substantially all of our cash flows from operations must be dedicated
          to the payment of interest and principal on our indebtedness;

     o    our debt service requirements limit our resources for capital
          expenditures, as well as upgrades and refurbishments of our vessels.

     o    our increased leveraged position will substantially increase our
          vulnerability to adverse changes in general economic and industry
          conditions; and

     o    our ability to obtain additional financing for working capital,
          capital expenditures, acquisitions, general corporate and other
          purposes may be limited.

     In this connection, the indenture relating to our outstanding 10% Senior
Notes due 2005 contains certain restrictive covenants that, among other things,
limit our ability and the ability of certain of our subsidiaries to incur
additional indebtedness and engage in sale-and-leaseback and other financing
transactions. We presently have no revolving credit facility or other sources of
liquidity except cash flow from operations. Most of our subsidiaries have
guaranteed our 10% Senior Notes. Such obligations may inhibit their ability to
obtain future financing for upgrades, refurbishments or other requirements. See
"Operating and Financial Review and Prospects -- Liquidity and Capital
Resources" in Item 5 of Part I of this report.

We have incurred recent losses in each of the last two years; we can provide no
assurance that we will achieve sustained profitability in the future.

     We incurred losses of $18.8 million in the year ended December 31, 2002 and
$37.4 million in the year ended December 31, 2001. We are engaged in a highly
competitive and historically cyclical business. Our ability to achieve financial
success will depend on, among other things, economic conditions in the offshore
oil and gas contract drilling and production industry and our ability to secure
favorable contracts for our drilling and production units. See "Operating and
Financial Review and Prospects" in Item 5 of Part I of this report.

We have a limited asset base and currently rely on one significant customer.

     As a result of our relatively small fleet of drilling and production units,
our revenues at any time primarily depend on contracts with a limited number of
customers, and our results of operations may fluctuate depending on the
termination of any of our contracts and our continued ability to obtain
additional contracts for our drilling and production units. Our contract with a
unit of Chevron Texaco Corporation ("Texaco") for the Northern Producer (the
"Texaco Contract"), accounted for 68% of our revenues and other income in 2002
(2001 - 85%). Texaco have notified us that they will not extend the current
contract beyond January 2005.

     If we are unable to employ our drilling and production units at
satisfactory rates, our results of operations could be materially and adversely
affected. Some of our vessels have not recently been upgraded and are therefore
more difficult to market. See "Information on the Company -- Contracts,
Marketing and Customers" in Item 4 and "Operating and Financial Review and
Prospects -- Liquidity and Capital Resources" in Item 5 of Part I of this
report.

We derive all our revenues from companies in the oil and gas exploration and
production industry, a mature and historically cyclical industry with levels of
activity that are significantly affected by the levels and volatility of oil and
gas prices. There are no alternative uses for drilling rigs.

     Demand for our services depends to a large extent on the level of
exploration and production activity in the oil and gas industry and the
willingness of exploration and production companies to spend capital on new
offshore drilling and development operations, which in turn depends in part on:

          o    prevailing oil and gas prices;
          o    expectations about future prices;
          o    the cost of exploring for, producing and delivering oil and gas;
          o    the discovery rate of new oil and gas reserves in offshore areas;
          o    domestic and international political, military, regulatory and
               economic conditions;
          o    technological advances;
          o    the ability of oil and gas companies to generate funds for
               capital expenditures;
          o    Competitors' drilling capacity; and
          o    Currency exchange rate fluctuations.

     Prices for oil and gas historically have been extremely volatile and have
reacted to changes in the supply of and demand for oil and natural gas
(including changes resulting from the ability of the Organization of Petroleum
Exporting Countries to establish and maintain production quotas), domestic and
worldwide economic conditions and political instability in oil producing
countries. We can provide no assurance that particular levels of oil and gas
activities and capital expenditures on offshore drilling and production
operations will be achieved or maintained or that demand for our services will
reflect the level of those activities. We anticipate prices for oil and natural
gas will continue to be volatile and affect the demand for and pricing of our
services. A material decline in oil or natural gas prices or activities could
exacerbate recent weak demand for our services and, therefore, our results of
operations and financial condition.

     The offshore contract drilling and production industry is a highly
competitive and historically cyclical business. The industry is characterized by
high capital costs, long lead times for construction of new drilling and
production units and numerous competitors for contracts. Offshore drilling and
production units have no alternative uses and, because of their nature and the
environment in which they work, have relatively high maintenance costs, whether
or not operating. Because these costs are essentially fixed, in order to avoid
additional expenses associated with temporarily idling or "stacking" our
drilling and production units, we may from time to time be required to bid our
drilling and production units out for hire at less than attractive rates,
depending on the prevailing contractual rates in a given region. We cannot
predict the future level of demand for our services. See "Information on the
Company -- Competition" in Item 4 of Part I of this report.

Our holding company structure involves risks associated with Northern Offshore's
ability to obtain cash from its operating subsidiaries to service its debt. Some
of our assets are pledged to secure our indebtedness.

     Northern Offshore is organized as a holding company whose only assets
consist of ownership interests in its subsidiaries. Consequently, Northern
Offshore's ability to obtain cash from its subsidiaries for the purpose of
meeting its debt service obligations, including the payment of principal and
interest on the 10% Senior Notes due 2005, depends on the earnings of its
subsidiaries and its ability to receive funds from its subsidiaries through
dividends, repayment of intercompany notes or other payments. The ability of
Northern Offshore's subsidiaries to pay dividends, repay intercompany notes or
make other advances or payments to Northern Offshore may be subject to
restrictions imposed by applicable law, tax considerations and the terms of
other agreements governing Northern Offshore's subsidiaries. The ability of our
subsidiaries Jet Holding Ltd and Jet Shipping Ltd to pay dividends is restricted
by the terms of a credit agreement with BNP Paribas. See "Information on the
Company -- Organization Structure" in Item 4 of Part I and "Liquidity and
Capital Resources" in Item 5 of Part I of this report. In addition, the Energy
Searcher is pledged to secure our loan from BNP and as a result is most likely
unavailable to satisfy claims of other creditors.

Our principal shareholder, World Shipholding Ltd., owns a majority of our Common
Shares, and its interests may conflict with those of our other security holders.

     World Shipholding Ltd. currently owns 53,813,342 of our outstanding Common
Shares, constituting 51.41% of our outstanding voting stock. World Shipholding
Ltd. is a subsidiary of Greenwich Holdings Ltd. Because of its level of
stockholding, World Shipholding Ltd. is able to exercise control over our
affairs, including the election of our Board of Directors. Furthermore, so long
as World Shipholding Ltd. owns more than one-third of our outstanding voting
stock, it will be able to prevent certain actions that require the affirmative
vote of at least two-thirds of our outstanding voting stock. In addition, Avalon
Holdings Ltd., an affiliate of World Shipholding Ltd., is one of our creditors.
We obtained a $30 million loan agreement from Avalon Holdings Ltd. in April 2000
to partially finance repurchases of some of our 10% Senior Notes due 2005. At
December 31, 2002, the outstanding amount under this loan agreement amounted to
$11.3 million. This loan is secured by repurchased Notes with a face amount of
$166.3 million.

     In addition to its indirect interests in our company, Greenwich Holdings
Ltd. has other interests in the shipping and offshore contract drilling
industries. Greenwich Holdings Ltd. (or any of its affiliates) may also invest
in other offshore drilling rigs, floating production facilities or other similar
competing units. In any contract-bidding situation a conflict between the
interest Greenwich Holdings Ltd. has in our company (through World Shipholding
Ltd.) and those other investments may develop.

     Greenwich Holdings Ltd.'s or World Shipholding Ltd.'s interests with
respect to matters potentially or actually involving or affecting us, such as
future acquisitions, financings and other corporate opportunities and attempts
to acquire us, may conflict with the interests of our other security holders.
Greenwich Holdings is indirectly controlled by John Fredriksen. See "Major
Shareholders and Related Party Transactions" in Item 7 of Part I of this report.

Our acquisition strategy involves various risks.

     Our future success may depend, in part, on the extent to which we are able
to acquire, at reasonable prices and on other favorable terms, and profitably
manage additional drilling and production units and related assets. Our current
financial situation severely limits our ability to take advantage of favourable
acquisition opportunities that may arise. We can provide no assurance, however,
that attractive acquisitions will be available to us at reasonable prices or
that any acquisition we complete will ultimately prove to be successful.
Acquisitions may involve a number of risks, including:

     o    adverse short-term effects on our operating results;
     o    diversion of management's attention;
     o    retaining, hiring and training of additional personnel;
     o    downturns in market conditions may force us to put acquired units into
          lay-up;
     o    risks associated with unanticipated assumed liabilities;
     o    increasing leverage and debt service requirements; and
     o    capital demands that exceed our resources.

     We can provide no assurance that we will be able to identify additional
suitable acquisition opportunities, negotiate acceptable terms, obtain financing
for acquisitions on satisfactory terms or successfully acquire identified
targets. Our failure to achieve consolidation savings, to incorporate acquired
assets into our existing operations successfully or to minimize any unforeseen
operational difficulties could have a material adverse effect on our financial
condition and results of operations.

We could be adversely affected if we lose the services of key members of our
management and third-party operators that we rely on.

     Our operations depend on the continuing efforts of our senior management.
Our business and prospects could be affected adversely if any of these persons
does not continue in his management role and we are unable to attract and retain
qualified replacements. We do not maintain key employee insurance. Certain
members of our management are not employed by us but are provided to us under
the terms of management agreements with related entities. See "Directors, Senior
Management and Employees" in Item 6 of Part I of this report.

     Although we retain the ability to direct the management of the operations
of all of our vessels, we rely on services of third parties to operate one of
our vessels. We have entered into a management agreement with a third party to
manage the operation of the Northern Producer for a fixed day rate and incentive
bonuses. If that third party does not perform its obligations under its
agreement with us, or if we are not able to obtain the services of a manager to
operate the Northern Producer or attract and retain capable operating management
and crew personnel for the Northern Producer when the existing management
agreement expires, we would be materially adversely affected. See "Information
on the Company" -- Contracts, Marketing and Customers" in Item 4 of Part I of
this report.

     An Increase in worldwide drilling demand and a corresponding increase in
the number of rigs working may periodically result in a shortage of qualified
rig personnel in the industry. A shortage of personnel could impede our ability
to enter into contracts with other parties to manage our rigs. It could also
result in wage increases, which could, without offsetting increases in revenues,
adversely affect our profitability. See "Information on the Company --
Employees" in Item 4 of Part I of this report.

Our operations involve risks associated with upgrade and refurbishment projects.
We may be unable to finance such projects.

     As of November 30, 2003 the average age of our vessels (based on the date
of construction, other than the Northern Explorer II, which is based on the date
of conversion rather than when its hull was originally constructed) was
approximately 30 years.

     All of our currently laid up units would need significant refurbishment or
upgrade expenditures before being put back into operation.

     We do not presently have sufficient capital resources to finance such
upgrade or refurbishment opportunities. See "Liquidity and Capital Resources" in
Item 5 of Part I of this report and "Information on the Company - Property,
Plants and Equipment" in Item 4 of Part I of this report. Upgrade and
refurbishment projects are subject to the risk of delay or cost overruns
inherent in any construction project, including shortages of materials or
skilled labour, unforeseen engineering problems, work stoppages, weather
interference, unanticipated cost increases and an inability to obtain any
requisite permits or approvals. Significant cost overruns or delays in any
refurbishment we do undertake would adversely affect our financial condition and
results of operations.

We operate in a highly competitive industry in which price competition is
intense, and we face competition from many competitors with greater resources
and newer drilling rigs.

     The offshore contract drilling and production services market is highly
competitive. Recent years have seen the creation of six dominant American
offshore drilling companies known as the Big 6 (Transocean, GlobalSantaFe,
Pride, Noble, ENSCO, Diamond), reducing market space for any niche player.
Operators generally award drilling and production contracts on a competitive bid
basis and, while an operator selecting an offshore drilling or production unit
may consider, among other factors, quality of service, safety record and
characteristics of equipment, price competition is a primary factor in
determining which qualified contractor with available equipment is awarded a
contract. We believe that competition for drilling and production services
contracts will continue to be intense for the foreseeable future.

     Most of our competitors are larger or have access to greater financial
resources than us, which will likely enable them to:

     o    better withstand industry downturns;
     o    compete on the basis of lower day rates and upgrade their existing
          drilling and production units;
     o    build new units; or
     o    acquire existing units that become available for purchase.

     We believe that newer and refurbished drilling rigs will be favoured over
older generation rigs in contract bidding situations.

     Because a successful contract bid would require upgrade or refurbishment,
our present lack of capital resources for such purposes would likely inhibit our
ability to compete effectively.

     Moreover, some of our competitors have been able to establish strategic or
preferred alliances with major oil companies, which enhance their competitive
position. See "Information on the Company -- Competition" in Item 4 of Part I of
this report.

Our operations involve various risks associated with international operations
and currency fluctuations.

     All our revenues are currently generated from sources outside the United
States. Our operations in some parts of the world are subject to certain
political, economic and other uncertainties not encountered in U.S. domestic
operations, including:

     o    risks of war and other international conflicts;
     o    expropriation or nationalization of assets;
     o    renegotiation or nullification of existing contracts;
     o    changing political conditions;
     o    changing laws and policies affecting trade and investment;
     o    overlap of different tax structures; and
     o    the general hazards associated with the assertion of foreign
          sovereignty over certain areas in which operations are conducted.

Some of these risks may limit the movement of assets or funds or result in the
deprivation of contract rights or the taking of property without fair
compensation. Additionally, our ability to compete in many foreign jurisdictions
may be adversely affected by foreign governmental regulations that encourage or
mandate the hiring of local contractors, or by regulations that require foreign
contractors to employ citizens of, or purchase supplies from, a particular
jurisdiction.

     Our foreign operations sometimes face the additional risks of fluctuating
currency values, hard currency shortages and controls of foreign currency
exchange. We attempt to limit our exposure to foreign currency fluctuations by
denominating most of our drilling and production contracts in U.S. dollars and
by using foreign currency to pay those expenses that are denominated in such
foreign currency. However, certain rate elements of the Texaco Contract are
denominated in British pounds, and we may in the future enter into drilling and
production contracts that provide for payment in currencies other than the U.S.
dollar. Accordingly, our profitability will likely be affected by fluctuations
in foreign exchange rates.

Our operations involve inherent risks of loss, which could adversely affect our
results of operations and financial condition.

     Our operations are subject to the many hazards inherent in the offshore
drilling and production industry, including drilling hazards such as blowouts,
reservoir damage, loss of production, loss of well control, cratering and fires.
The occurrence of any of these events could result in the suspension of drilling
or production operations, substantial damage to or destruction of equipment and
injury or death to personnel on board one of our vessels. Damage to the
environment could also result from our operations, particularly through oil
spillage or extensive uncontrolled fires. In addition, our operations are
subject to perils peculiar to marine operations, including capsizing, grounding,
collision and loss or damage from severe weather or storms. Litigation arising
from any such event may result in our being named as a defendant in lawsuits
asserting large claims. We maintain insurance coverage in such amounts we
believe to be prudent against normal risks in our operations. Certain risks,
such as environmental impairment, however, are either not insurable or are
insurable only at rates our industry generally considers uneconomical. Moreover,
our insurance coverage in most cases does not protect us against loss of
revenues. Depending on competitive conditions and other factors, we will seek to
obtain indemnity agreements from our customers, which would require them to hold
us harmless in the event of loss of production, reservoir damage or liability
for pollution that originates below the surface of the water. When obtained,
such contractual indemnification protection may not in all cases be supported by
adequate insurance maintained by the customer. We can provide no assurance that
any such insurance or contractual indemnity protection will be sufficient or
effective under all circumstances or against all hazards to which we may be
subject. The occurrence of a significant event not fully insured or indemnified
against or the failure of a customer to meet its indemnification obligations to
us could materially and adversely affect our results of operations and financial
condition. Moreover, we can provide no assurance that we will be able to
maintain adequate insurance in the future at rates we consider reasonable or
that any particular types of coverage will continue to be available. See
"Information on the Company - Operating Risks and Insurance" in Item 4 of Part I
of this report.

Our operations are subject to various laws and governmental regulations that may
adversely affect our future operations.

     Our operations are subject to various governmental laws and regulations,
including those relating to:

     o    equipping and operating offshore vessels;
     o    vessel safety;
     o    currency conversions and repatriation;
     o    oil exploration and development;
     o    taxation of foreign earnings and earnings of expatriate personnel; and
     o    use of local employees and suppliers by foreign contractors.

We are required to invest financial and managerial resources to comply with
those laws and regulations and anticipate that we will continue to do so in the
future. In addition, we depend on the demand for our services from the oil and
gas exploration and production industry and, therefore, we are affected by
changing taxes, price controls and other laws relating to the oil and gas
industry generally. The adoption of laws and regulations curtailing exploration
and development drilling for oil and gas for economic or other policy reasons
would adversely affect our operations by limiting demand for offshore drilling
and production services. We cannot determine to what extent our future
operations and earnings may be affected by new legislation, new regulations or
changes in existing regulations.

     Our operations and assets are also affected by various environmental
protection laws and regulations, including those governing discharges into the
air and water, the handling and disposal of solid and hazardous wastes and the
health and safety of employees. The technical requirements of these laws and
regulations are becoming increasingly expensive, complex and stringent. These
laws may provide for "strict liability" for damages to natural resources or
threats to health and safety, rendering a party liable for environmental damage
without regard to negligence or fault on the part of that party. Sanctions for
non-compliance may include revocation of permits, corrective action orders,
administrative or civil penalties and criminal prosecution. Certain
environmental laws provide for strict, joint and several liability or
remediation of spills and other releases of hazardous substances. In addition,
companies may be subject to claims alleging personal injury or property damage
as a result of alleged exposure to hazardous substances. For example, some of
our vessels have asbestos aboard which could pose a liability risk. Such laws
and regulations may also expose us to liability for the conduct of or conditions
caused by others, or for acts by us that complied with all applicable laws when
they were performed. See "Information on the Company - Governmental Regulation
and Environmental Matters" in Item 4 of Part I of this report.

There are risks relating to service of process on and enforcement of judgments
against Northern Offshore and its subsidiaries and their respective officers and
directors

     Northern Offshore is organized under the laws of Bermuda, and each of the
guarantors on the 10% Senior Notes due 2005 is organized outside the United
States. All of their respective directors and executive officers reside outside
the United States. Substantially all of the assets of those persons and entities
are located outside the United States. As a result, it may not be possible for
investors to effect service of process upon, or enforce judgments against, those
persons or entities in the United States, or to enforce outside of the United
States judgments against any of them obtained in United States courts in any
action, in each case including actions predicated on the civil liability
provisions of the federal securities laws of the United States.

Item 4. Information on the Company

A. History and Development of the Company

     Northern Offshore is a continuation of the offshore drilling and production
services business formerly owned and operated by NOASA. NOASA was formed as a
Norwegian public company in December 1997 to acquire the floating production
facility Northern Producer and two drillships, the Northern Explorer II and the
Northern Explorer III, from our principal shareholder at the time, Hemen
Holdings Limited (collectively with its subsidiaries, "Hemen Holdings"). Hemen
Holdings is an affiliate of Greenwich Holdings, Ltd. and World Shipholding Ltd.
In connection with the reorganization transactions referred to in the
immediately following paragraph, World Shipholding Ltd. succeeded to Hemen
Holdings' majority equity interest in us. In addition, NOASA acquired the
semi-submersible drilling unit the Galaxy Driller from Galaxy Drilling Ltd., a
Cayman Islands company ("Galaxy Drilling"), in May 1998 for a purchase price of
$50 million.

     NOASA formed Northern Offshore in May 2000 as part of a series of
transactions that resulted in the separation of NOASA's business of providing
oil and gas drilling and production services from its ownership and operation of
oilfields. Northern Offshore is a company established under the laws of Bermuda.
On May 31, 2000, NOASA transferred all its operating assets and liabilities to
Northern Offshore in exchange for 79 million Common Shares of Northern Offshore.
On September 20, 2000, NOASA spun off Northern Offshore by distributing all
those shares to the shareholders of NOASA. Northern Offshore sold its majority
ownership interests in Naftex Energy Corporation ("Naftex") and Petrolex Energy
Corporation ("Petrolex"), two Canadian subsidiaries holding oil concessions in
Egypt, Brazil and Colombia, back to NOASA on September 4, 2000 for $6.4 million.
On September 6, 2000, NOASA bought the drillship Discoverer I for $12.3 million,
which it then sold to Northern Offshore on September 20, 2000 for the same
price. Northern Offshore increased its authorized capital and authorized shares
on September 12, 2000 to $24.0 million and 96,000,000 shares, respectively, and
issued 14,905,660 shares to NOASA in final settlement of the net amounts it owed
to NOASA after those two transactions. NOASA subsequently sold those Common
Shares to its shareholders. In October 2000, NOASA changed its name to Northern
Oil ASA. The Common Shares of both Northern Offshore and Northern Oil ASA are
listed on the Oslo Stock Exchange. Northern Offshore uses the ticker symbol NOF,
and Northern Oil ASA uses the ticker symbol NOI.

     We bought the Energy Searcher on June 22, 2001 at a price of $37 million.
The Energy Searcher is a conventionally moored drilling vessel, which can
operate in water depths up to 2,500 ft. We also acquired Jet Drilling (S) Pte
Ltd, a Singapore-based management company, in connection with our acquisition of
the Energy Searcher. Jet Drilling will form the basis for our future drilling
operations in South-East Asia. In connection with the acquisition of the Energy
Searcher, we incurred debt under a revolving credit facility with BNP Paribas.
The outstanding amount under this credit facility is currently $6.5 million and
repayment is due in June 2004. The acquisition was further financed through an
equity placement of 9.5 million Common Shares at NOK 16.50 per share, totaling
approximately $17 million, and a $9 million bridging loan from Den norske Bank,
which was guaranteed by Greenwich Holdings Ltd. This loan was repaid during 2001
and 2002.

     As part of our relocation to Bermuda, we closed our Oslo office effective
January 1, 2002 and entered into an agreement with Frontline Management
(Bermuda) Ltd. ("Frontline") for administrative services. Under the management
agreement, Frontline provides management support, budgetary and accounting
support services, maintains our corporate records, ensures our compliance with
applicable laws and requirements, and assists us with corporate finance matters.
Frontline is a subsidiary of Frontline Ltd., a publicly listed company, and is
affiliated with our majority shareholder World Shipholding Ltd. We believe that
the compensation we pay to Frontline Management for its administrative and
management services is not more than the price we would have paid to a third
party in an arm's-length transaction. See "Major Shareholders and Related Party
Transactions" in Item 7 of Part I of this report.

     Our registered office and principal business office is located at
Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda and
our telephone number at that address is +1 441 295 6178.

B.  Business Overview

Equipment Descriptions and Market Overview

Floating Production Vessels

     Oil and gas exploration and development companies use two basic types of
facilities to produce oil and gas from offshore fields: fixed platforms and
floating production vessels. Floating production vessels provide the capability
for use in deep waters beyond the limitations of fixed platforms. Fixed
platforms are generally restricted to use in water depths of 1,300 feet or less.
Additionally, floating production vessels are mobile and can therefore be
reused. They are sometimes used in water depths that could accommodate fixed
platforms, particularly in circumstances when the oil or gas reservoir has a
relatively short production life.

     Floating production vessels offer a cost-effective approach to offshore oil
and gas production and, combined with sub-sea completion technology, reduce the
threshold at which offshore production becomes economically viable. Floating
production was originally developed as an alternative to fixed platforms in
order to reduce overall costs and the financial exposure associated with
developing small to medium-sized offshore fields. These units are generally
capable of conducting the same operations as fixed platforms, with the exception
of drilling and heavy well maintenance, which only a few converted
semi-submersible drilling units are equipped for.

     Floating production vessels are of three basic types: tension-leg platforms
("TLPs"), spar platforms and floating production facilities ("FPFs").

     A TLP consists of a deck that sits atop four or more separate column-shaped
semi-submersible hulls, which are positioned on site with vertical tendons
(pipes) that run from the columns to the sea floor. The tendons hold the columns
partially submerged and are highly tensioned using the buoyancy of the hulls.
This system develops a restoring force against wave, wind and current forces in
proportion to the lateral displacement of the vessel. Wells for a TLP are often
predrilled through a sub-sea template. Long, flexible production risers, which
carry the hydrocarbons to the deck of the TLP, are supported in tension by
mechanical tensioner machines on the platform's deck and are directly subject to
wave, wind and current forces.

     A spar platform consists of a vertically floating, large-diameter cylinder
supporting a relatively conventional offshore drilling and production deck. The
structure is positioned with mooring systems using either piling or anchors.
Wells can be either predrilled or drilled from the platform. Individual buoyancy
tanks located inside the hull support the well risers in tension to protect both
the risers and the tanks from waveload forces. The hull of a spar platform can
be configured for significant oil storage, which can be advantageous in
locations that lack oilfield infrastructure. The spar platform concept
historically has been used for auxiliary structures such as those used to moor
and load tankers.

     An FPF consists of a ship or semi-submersible vessel upon which production
equipment is mounted. Certain semi-submersible floating production vessels also
have drilling capacity. In most cases, the FPF is either a converted tanker
(often referred to as a floating, production, storage and offloading ("FPSO")
unit) or a converted semi-submersible drilling unit. FPFs generally use sub-sea
completion technology, which provides a means of producing hydrocarbons with the
primary well control equipment located on the sea floor. This technology has
resulted in a significant amount of increased exploration and development
activity in the North Sea. The vast majority of floating production vessels
operating in the world today are FPFs.

     The selection of the type of offshore platform for a given project depends
on a number of factors, including the type of hydrocarbons to be produced,
whether additional drilling operations will be conducted simultaneously with
production, estimated production levels, the location and size of the field,
water depth, weather conditions, characteristics of the sea floor, earthquake
potential, deck load requirements, storage requirements and export alternatives.

Offshore Drilling Units

     Mobile offshore drilling units consist of a hull, positioning equipment and
drilling equipment. The design of a unit determines the marine environment in
which it can operate. The drilling equipment determines which drilling
operations a unit is capable of performing and is principally comprised of
hoisting equipment, a power plant, bulk and liquid handling systems, well
control apparatus and a means of rotating the drill string and tubulars. An
offshore drilling unit also has living quarters, cranes, a heliport and material
storage facilities.

            The major categories of competitive offshore drilling units include
the following:

     Jack-Up Rigs. Jack-up rigs are mobile self-elevating drilling platforms
equipped with legs that can be lowered to the ocean floor until a foundation is
established to support the drilling platform. The rig hull includes the drilling
rig, jacking system, crew quarters, loading and unloading facilities, storage
areas for bulk and liquid materials, helicopter landing deck and other related
equipment. The rig legs may have a lower hull (a "mat") attached to the bottom
of them in order to provide a more stable foundation in soft bottom areas.
Independent leg rigs are better suited for harder or uneven seabed conditions.
Jack-up rigs are generally limited to drilling in maximum water depth of
approximately 350 feet.

     Semi-submersible Rigs. Semi-submersible rigs are floating platforms, which,
by means of a water ballasting system, can be submerged to a predetermined
depth, so that a substantial portion of the lower hulls, or pontoons, is below
the water surface during drilling operations. The rig is "semi-submerged,"
remaining afloat, off bottom, in a position in which the lower hull is about
60-80 feet below the water line and the upper deck protrudes well above the
surface. These rigs maintain their position over the well through the use of an
anchoring system or computer controlled thruster system (a "dynamic positioning
system"). They have lower wave motions than other types of floating units
because of their geometry at the water line. Some semi-submersible rigs are
designed to work in water depths up to 6,000 feet. Some semi-submersible rigs
are self-propelled and move from location to location under their own power when
afloat on the lower hulls, or pontoons; however, most semi-submersible rigs are
relocated with the assistance of tugboats. Semi-submersible units are generally
more expensive to operate than jack-up rigs and, compared to a drillship, are
often limited in the amount of supplies that can be stored on board.

     Drillships. Drillships are ships that are equipped for drilling and are
typically self-propelled and move from one location to another under their own
power. A drillship uses either a conventional mooring system (anchors and
chains/wires) or a dynamic positioning system to position itself over a well
site. Conventionally moored drillships typically are limited to operations in
water depths of between 200 and 2,000 feet (their water depth capacity being a
function of, among other things, the length of their anchor chains). Certain
dynamically positioned drillships are capable of drilling in water depths of up
to 10,000 feet. Dynamically positioned drillships generally have greater
capacity and earn higher day rateday rates than conventionally moored
drillships, but also have higher operating costs. Although drillships have
drilling capabilities comparable to semi-submersible rigs, their larger variable
deck load capacities reduce the need to supply and support the vessel during
drilling operations. This offers drillships an advantage over semi-submersibles,
especially in remote drilling regions.

     Several factors determine the type of unit most suitable for a particular
job, the most significant of which include the marine environment, water depth
and seabed conditions at the proposed drilling location, whether the drilling is
being done over a platform or other structure, the intended well depth, variable
load requirements and well control equipment requirements where high-pressure
and high-temperature wells are contemplated. Thus, the market tends to be highly
segmented, and considerable variation in utilisation and day rateday rates often
exists for various units as a function of their capabilities.

     For a description of our equipment see "Property, Plants and Equipment" in
Item 4 of Part I of this report.

     For additional discussion of market conditions, see "Operating and
Financial Review and Prospects - Overview" in Item 5 of Part I of this report.

Contracts, Marketing and Customers

General

     Although we direct the marketing and operational control of our fleet, we
have outsourced management of the Northern Producer to Petrofac Facilities
Management ("PFM"), under a contract that runs concurrently with the Texaco
Contract (subject to our option to terminate after the initial four-year term).
The management agreement provides for fixed day rates and certain incentive
bonuses to PFM. In the future, we expect we will continue to outsource
management of our drilling and production units in situations where it is the
most cost-effective means of operation.

     We usually obtain our drilling and production contracts through competitive
bidding against other contractors. We generally seek contracts that compensate
us on a day rate basis, and we do not currently intend to undertake contracts on
a footage or turnkey basis. Under day rate contracts, the contractor provides
the drilling or production unit and the required personnel to operate the unit
(including repairs and maintenance) and supervise the drilling or production
operations. Compensation under a day rate contract is based on a rate per day
for each day that the drilling or production unit is used for drilling or
production operations. The typical day rate depends on market conditions, the
nature of the operations to be performed, the duration of the work, the
equipment and services to be provided, the geographical areas involved and other
variables. Day rate contracts may also contain an alternate, lower day rate that
applies when a unit is in route to a new site or when operations are interrupted
or restricted by equipment breakdowns, adverse weather or water conditions or
other conditions beyond the contractor's control. Some day rate contracts
provide for revision of the specified day rates in the event of material changes
in certain items of cost being incurred by the contractor.

     Day rate contracts generally specify the type of equipment the contractor
must use, the depth of the proposed well and the operating conditions and
requirements. Under a day rate contract, unlike most footage or turnkey
contracts, the contractor generally bears limited costs resulting from "inhole"
losses (such as time delays for various reasons, including stuck drill strings
and blow-outs).

     In general, a day rate drilling contract extends over a period of time
covering either the drilling of a single well or a group of wells or a stated
term. A day rate production contract is usually for a stated term. A day rate
contract may permit the customer to terminate it if the drilling or production
unit is destroyed or lost or if drilling or production operations are suspended
for a specified period of time as a result of a breakdown of major equipment or,
in some cases, events beyond the control of either party. In addition, most
contracts permit the customer to terminate the contract early by giving notice,
although in some circumstances the contract may require the customer to pay an
early termination fee. The customer may extend the contract term in many
instances.

     In certain foreign locations, we expect to enter into contracts through
arrangements involving local companies from time to time. The purpose of the
arrangements is to draw on the personnel resources and technical, supply and
governmental relations assistance of local venture partners and in some cases to
comply with local legal requirements. Typically, the financial terms are such
that each party receives payment on a "cost plus basis" or a percentage of the
revenues.

     Because of the small number of vessels comprising our fleet, we can operate
for only a small number of customers at any given time, and services to each
customer may constitute a significant portion of our revenues. Accordingly, our
business operations are subject to the risks associated with a business having a
limited number of customers for our products or services, and the loss of any
significant customer or a decrease in the drilling programs of significant
customers in the areas where they employ us may adversely affect our results of
operations.

  The Texaco Contract

     The Northern Producer is employed, under a contract with Texaco, for the
production of oil and gas from the Galley field in the U.K. sector of the North
Sea. The contract had an initial term of four years ending in January 2002.
Texaco has options to extend the contract for up to an additional six years over
four initial option periods of six months each and then four additional option
periods of one year each. Texaco may further extend the contract in order to
complete production following the expiration of the last option period. Texaco
has exercised options, thereby extending the contract term to January 6, 2005.
Texaco has notified us that they will not extend the current contract beyond
January 2005.

     For a further discussion of the contract terms of the Texaco Contract, see
"Operating and Financial Review and Prospects - Overview - The Texaco Contract"
in Item 5 of Part I of this report.

     The Galley field comprises a series of accumulations located approximately
100 miles northeast of Aberdeen, Scotland. Phase I of the Galley field involves
producing from a single development well in each of the Galley North and Galley
South discoveries. Phase II production started from an additional well in the
extension of the North reservoir in 1999. Texaco also drilled another production
well in the Galley North reservoir, which was tied into the Northern Producer at
the end of November 2001. Further Phase II work will, if undertaken, involve
production from other wells in these and the other discoveries and prospects in
the field, in addition to prospects not presently part of the Galley field,
including production of third parties from developing nearby fields which may
take advantage of the infrastructure Texaco has installed in the Galley field
area.

Competition

     The offshore contract drilling and production industry is a highly
competitive business. It is characterized by high capital costs, long lead times
for construction of new drilling or production units and numerous competitors
for offshore drilling contracts. Recent years have seen the creation of six
dominant American offshore drilling companies known as the Big 6 (Transocean,
GlobalSantaFe, Pride, Noble, ENSCO, Diamond), reducing market space for any
niche player. We believe that competition for drilling contracts will continue
to be intense for the foreseeable future. Offshore drilling and production units
have no alternative uses and, because of their nature and the environment in
which they work, have relatively high maintenance costs, whether or not
operating. Because these costs are essentially fixed, and in order to avoid
additional expenses associated with temporarily idling or "stacking" our
drilling and production units, we may from time to time be required to bid our
drilling and production units out for hire at less than attractive rates,
depending on the prevailing contractual rates in a given region. Most of our
competitors are larger than us or have access to greater financial resources
than we do, which may enable them to better withstand industry downturns,
compete on the basis of lower day rates, upgrade their existing drilling and
production units, build new units or acquire existing units that become
available for purchase. Moreover, some of our competitors have been able to
establish strategic or preferred alliances with major oil companies, which
enhance their competitive position. Operators generally award drilling and
production contracts on a competitive bid basis and, while an operator selecting
a unit may consider, among other factors, quality of service, safety record and
characteristics of equipment, price competition is a primary factor in
determining which qualified contractor with available equipment is awarded a
contract. Because a successful contract bid may require upgrade or
refurbishment, our present lack of capital resources for such purposes would
likely inhibit our ability to compete effectively. We cannot predict the future
level of demand for our services.

Operating Risks and Insurance

     Our operations are subject to the many hazards inherent in the offshore
drilling and production industry (including blowouts, reservoir damage, loss of
production, loss of well control, cratering and fires), the occurrence of which
could result in the suspension of drilling or production operations, substantial
damage to or destruction of equipment and injury or death to personnel on board.
Damage to the environment could also result from our operations, particularly
through oil spillage or extensive uncontrolled fires. In addition, our
operations are subject to perils peculiar to marine operations, including
capsizing, grounding, collision and loss or damage from severe weather or
storms. Litigation arising from any such event may result in us being named as a
defendant in lawsuits asserting large claims.

     We maintain broad insurance coverage, including insurance against general
and marine liability. Our offshore drilling and production equipment is covered
by physical damage insurance polices against marine and other perils, including
losses due to capsizing, collision, fire, hurricanes, storms, actions of waves,
cratering, blowouts and explosions. Certain risks, such as environmental
impairment risks, however, are either not insurable or are insurable only at
rates our industry generally considers uneconomical (See "Risk Factors" in Item
3. of Part I of this report). Moreover, our insurance coverage in most cases
does not protect us against loss of revenues. Depending on competitive
conditions and other factors, we will seek to obtain indemnity agreements from
our customers, which would require them to hold us harmless in the event of loss
of production, reservoir damage or liability for pollution that originates below
the surface of the water. When obtained, that contractual indemnification
protection may not in all cases be supported by adequate insurance maintained by
the customer. We can provide no assurance that any such insurance or contractual
indemnity protection will be sufficient or effective under all circumstances or
against all hazards to which we may be subject. The occurrence of a significant
event not fully insured or indemnified against or the failure of a customer to
meet its indemnification obligations to us could materially and adversely affect
our results of operations and financial condition. Moreover, we can provide no
assurance that we will be able to maintain adequate insurance in the future at
rates we consider reasonable or that any particular type of coverage will
continue to be available.

Foreign Operations

     Our operations in some parts of the world are subject to certain political,
economic and other uncertainties not encountered in U.S. domestic operations,
including risks of war and other international conflicts, expropriation or
nationalization of assets, renegotiation or nullification of existing contracts,
changing political conditions, changing laws and policies affecting trade and
investment, overlap of different tax structures and the general hazards
associated with the assertion of foreign sovereignty over certain areas in which
operations are conducted, each of which may limit the movement of assets or
funds or result in the deprivation of contract rights or the taking of property
without fair compensation. Additionally, our ability to compete in many foreign
jurisdictions may be adversely affected by foreign governmental regulations that
encourage or mandate the hiring of local contractors, or by regulations that
require foreign contractors to employ citizens of, or purchase supplies from, a
particular jurisdiction.

     Other risks inherent in foreign operations are the possibility of currency
exchange losses where revenues are received in currencies other than U.S.
dollars and losses resulting from an inability to collect dollar revenues
because of a shortage of convertible currency available to the foreign country.
Generally, we limit these risks by obtaining compensation in U.S. dollars or
freely convertible foreign currencies. See "Operating and Financial Review and
Prospects - Liquidity and Capital Resources - Exposure to Currency Fluctuations"
in Item 5 of Part I of this report.

Governmental Regulation and Environmental Matters

General

     Our operations are subject to various governmental laws and regulations,
including those relating to equipping and operating offshore vessels, vessel
safety, currency conversions and repatriation, oil exploration and development,
taxation of foreign earnings and earnings of expatriate personnel, use of local
employees and suppliers by foreign contractors and the protection of the
environment. We are required to invest financial and managerial resources to
comply with those laws and regulations and anticipate that we will continue to
do so in the future. In addition, we depend on the demand for our services from
the oil and gas exploration and production industry and, therefore, are affected
by changing taxes, price controls and other laws relating to the oil and gas
industry generally. The adoption of laws and regulations curtailing exploration
and development drilling for oil and gas for economic or other policy reasons
would adversely affect our operations by limiting demand for offshore drilling
and production services. We cannot determine to what extent new legislation, new
regulations or changes in existing regulations may affect our future operations
and earnings.

     We are required by various other governmental and quasi-governmental
agencies to obtain certain permits, licenses and certificates with respect to
our operations. The kinds of permits, licenses and certificates required in our
operations depend on a number of factors. We believe we have or can obtain all
permits, licenses and certificates necessary to conduct our business.

Environmental

     Our operations and assets are affected by various environmental protection
laws and regulations, including those governing discharges into the air and
water, the handling and disposal of solid and hazardous wastes and the health
and safety of employees. The technical requirements of these laws and
regulations are becoming increasingly expensive, complex and stringent. These
laws may provide for "strict liability" for damages to natural resources or
threats to health and safety, rendering a party liable for environmental damage
without regard to negligence or fault on the part of that party. Sanctions for
non-compliance may include revocation of permits, corrective action orders,
administrative or civil penalties and criminal prosecution. Certain
environmental laws provide for strict, joint and several liability or
remediation of spills and other releases of hazardous substances. Those laws and
regulations may expose us to liability for the conduct of or conditions caused
by others, or for actions of ours that complied with all applicable laws when
they were performed. In addition, we may become subject to claims alleging
personal injury or property damage as a result of alleged exposure to hazardous
substances.

     We cannot predict all the environmental requirements or circumstances that
will exist in the future, but anticipate that environmental control and
protection standards will become increasingly stringent. We have not experienced
and do not currently anticipate any material adverse effect on our business or
financial position as a result of future compliance with existing environmental
laws and regulations controlling the discharge of materials into the environment
or otherwise relating to the protection of the environment. However, future
events, such as changes in existing laws and regulations or their
interpretation, more vigorous enforcement policies of regulatory agencies or
stricter or different interpretations of existing laws and regulations, may
require us to make additional expenditures which may be material. Accordingly,
we can provide no assurance that we will not incur increased environmental
compliance costs in the future. In addition, offshore drilling and production
operations in certain areas have been opposed by environmental groups and, in
certain areas, have been restricted. To the extent laws are enacted or other
governmental actions are taken that prohibit or restrict offshore drilling and
production or impose environmental protection requirements that result in
increased costs to the oil and gas industry in general and the offshore drilling
and production industry in particular, our business and prospects could be
adversely affected.

C.  Organizational Structure

     Northern Offshore is a holding company that conducts its operations through
its wholly owned subsidiaries: Northern Offshore Management AS, a Norwegian
company; Katzen International Corp., a Liberian company; Sea Production Limited,
a British Virgin Islands company; Monarch Seacarriers Inc., a Liberian company
that owns the Northern Explorer II; Merit Maritime Limited, a Liberian company
that owns the Northern Explorer III; Northern Discoverer Inc., a Liberian
company that owns the Discoverer I; Qualimar Shipping Company Limited, a Cyprus
company that owns the Northern Producer; Helm Maritime Corp., a Liberian company
that owns the Galaxy Driller; Jet Holding Ltd, a St. Vincent and the Grenadines
company that owns the Energy Searcher; Jet Shipping Ltd, a St. Vincent and the
Grenadines company that bareboat charters and operates the Energy Searcher, Jet
Drilling (S) Pte Ltd, a Singapore company and Northern Offshore Leasing Ltd, a
Malaysian company (collectively, the "Subsidiaries").

     All of our subsidiaries are restricted subsidiaries under the terms of the
Indenture governing, and guarantors of, our issue of 10% Senior Notes due 2005
except for Splendour III Corporation, Jet Shipping Ltd. and Jet Holding Ltd.
which are unrestricted subsidiaries and are not guarantors and not subject to
the covenants contained in the Indenture.

D.  Property, Plants and Equipment

     The following table sets forth certain information with respect to our
drilling and production units, including their locations as of November 30,
2003:

<TABLE>
                                                     Year             Water     Drilling
                                                     Constructed/     Depth     Depth
Unit Name                  Type                      Upgraded         Rating    Rating        Location      Status
---------                  ----                      --------         ------     ------       --------      ------
                                                      (feet)          (feet)
<S>                        <C>                       <C>              <C>       <C>           <C>           <C>
Northern Producer          Semi-submersible FPF      976/91/97          N/A        N/A        UK            Operating
Northern Explorer II(1)    Drillship                 945/76/98          600     20,000        Malaysia      Idle
Northern Explorer III(1)   Drillship                 973/94/98          750     20,000        Malaysia      Idle
Galaxy Driller(1)          Semi-submersible          977/92/97          600     20,000        Malaysia      Idle
Discoverer I               Drillship                   1977           1,500     20,000        Mexico        Idle
Energy Searcher            Drillship                  1959/82         2,500     25,000        S.E. Asia     Operating
---------

</TABLE>

(1)  Each of the Northern Explorer II, the Northern Explorer III and the Galaxy
     Driller is capable of being upgraded to operate in waters as deep as 1,500
     feet, in each case for capital expenditures of approximately $5 million.

     The Northern Producer was originally constructed as a semi-submersible and
was converted into an FPF in 1991. The unit is specially constructed to operate
in harsh weather conditions and meets some of the world's most stringent
regulations applicable to floating production facilities. The Northern Producer
is equipped with a versatile process package, which enables it to produce in a
wide range of offshore fields. It is capable of maximum oil production and
export of approximately 55,000 barrels per day, gas production and export of
approximately 60 million cubic feet per day and water injection of up to 60,000
barrels per day. It has an eight-point chain mooring system and accommodations
for up to 75 people. We believe the Northern Producer's design and capabilities
could afford it future opportunities for employment in floating production
markets worldwide, including the Canadian continental shelf, the U.S. Gulf of
Mexico and offshore West Africa, South America (particularly Brazil) and
Southeast Asia.

     The Northern Producer is currently operating in the Galley field in the
U.K. sector of the North Sea under a long-term contract (the "Texaco Contract")
for a unit of Texaco, Inc. (collectively with its subsidiaries, "Texaco"). See
"- Business Overview -Contracts, Marketing and Customers - The Texaco Contract."

     Texaco have notified us that they will not extend the current contract
beyond January 2005.

     Northern Producer - Issues and Status

o    Asbestos-- some asbestos aboard.

o    North Sea-- proven reserves have been confirmed in zones belonging to other
     operators. The experience of Northern Producer offers potential for
     deployment after the end of the Texaco contract.

o    Other regions for possible deployment-- Brazil, US Gulf, Mexico and
     Australia, although US competition will be high.

     Northern Producer - Strengths and Weaknesses

o    Work History-- we believe the Texaco contract has comparable terms to
     similar industry deals.

o    Technology -- we believe the Northern Producer has a versatile process
     package suitable for similar production facilities in fields in all regions
     of the world.

o    Capabilities -- the Northern Producer has capacity for small to medium
     sized offshore fields as well as mature regions; the floating system is
     particularly suitable for operations under harsh weather conditions.

o    Refurbishment-- we believe the Northern Producer offers a high degree of
     convertibility and upgrade potential.

o    Contract marketability-- we believe that the vessel's Aker H-3 design
     translates to the best marketability for vessels of its type and age.

o    Age -- at over 25, the vessel is behind 3 new generations; the later
     generation semi -sub production facilities are built with more flexibility
     to adapt to different fields.

o    Specificity -- field specific equipment and systems are not easily
     transferable; existing process equipments are difficult to apply to new
     fields.

o    Sale market -- almost no second hand market for its kind of semi
     -submersible production facility; demand for floating production facilities
     of its kind is also relatively disconnected from movements in oil and gas
     prices.

     Both the Northern Explorer II and the Northern Explorer III are
self-propelled, conventionally moored and have drilling capabilities in
intermediate water depths. The Northern Explorer II and the Northern Explorer
III are "ice classed" vessels, with certifications by the American Bureau of
Shipping ("ABS") and Det Norske Veritas, respectively, and have variable deck
load capacities of 5,426 metric tons and 6,893 metric tons, respectively. Hemen
Holdings acquired both the Northern Explorer II and the Northern Explorer III in
1997 from Canadian Marine Drilling Limited ("Canmar"), a subsidiary of Amoco
Corporation. Canmar previously used the Northern Explorer II and the Northern
Explorer III in arctic regions under extreme climactic conditions. Each is
equipped with an 18 3/4-inch, 10,000 psi BOP stack and an eight-point wire/chain
mooring system, and each has accommodations for over 100 people. The Northern
Explorer II and the Northern Explorer III are equipped with Varco TDS-4 top
drive. Both the Northern Explorer II and the Northern Explorer III are currently
laid up in Malaysia.

     Northern Explorer II - Issues and Status

o    Corrosion -- pipes, plates, safety fencing, tanks and crane cabin are
     corroded.

o    Seizure-- one of the required seven diesel engines is in seized condition
     while another has its turbo charger removed.

o    Indentations-- knocks, dents and bruises are noticeable on the ship.

o    Power-- there is insufficient power supply from the generating sets on
     board.

o    Load-- thickness and load stress accommodation are not in good shape.

o    Upgrade Costs-- Company and independent sources estimate upgrade costs to
     be about $10 million.

o    Certification-- port registry and ABS certificates expired in 1999.

o    Physical State-- ability of decks and structures to endure stress or loads
     is doubtful.

o    Capabilities-- any refurbishment program has to first restore original
     capacity lost.

o    Asbestos -- the drillship has some asbestos on board.

     Northern Explorer II - Strengths and Weaknesses

o    Past Record -- vessel has operated under extreme climatic conditions in
     Canadian Arctic waters. o Class -- one of the only four ice-classed
     designed drillships worldwide.

o    Technology-- self-propelled, thus requiring no tugs and lift vessels for
     mobility; preferred by operators in remote drilling locations.

o    Economic Life-- if refurbished, 7 years expected remaining life.

o    Age-- a 57-year-old vessel with a conversion 27 years ago, the ship is
     considered old and outclassed by many generations.

o    Recent Record-- BP Gas contract in Indonesia was terminated on account of
     poor operational performance and bad motion characteristics.

o    Lay Up-- has been stacked more than four years, without proper servicing.

o    Refurbishment-- a drillship of its kind laid up about the same time in
     South East Asia was quickly refurbished thereafter, and re-contracted.

o    Marketability -- general tightness in second hand markets for drillships of
     its kind, and the vessel is likely to be offered work only in the peak of
     the cycle, and the last vessel going out.

     Since issuing our third quarter 2003 financial report, we have conducted a
review of the costs and benefits of keeping the Northern Explorer II in lay-up.
As a result we have adopted a plan to sell the Northern Explorer II for scrap as
we believe that the costs of refurbishment and upgrade of this unit are greater
than the likely economic benefit of such expenditure. We expect to realize
proceeds in the region of $2million. We expect to record an impairment charge on
this asset of approximately $4.2 million in the fourth quarter of 2003.

     Northern Explorer III - Issues and Status

o    Certification-- statutory, regulatory and trading certificates have all
     expired in 1999.

o    Physical State-- ability of decks and structures to endure operational
     stress or loads is doubtful.

o    Capabilities-- any refurbishment program has to consider capacity
     advancement.

o    Asbestos-- the driliship has asbestos on board, notably in domestic
     sections.

o    Options-- piecemeal scrap disposal or a massive huge-cost upgrading before
     putting the ship on the disposal market.

o    Rustiness-- facilities, decks, cranes, drilling accessories are rusty, some
     patchy.

o    Corrosion-- pipes, plates, safety fencing, tanks and crane cabin are
     corroded.

o    Overhaul-- one of the five required diesel engines is currently down and
     needs to be overhauled.

o    Load-- thickness and load stress accommodation ability is not in good
     shape.

o    Upgrade Costs-- company and independent sources estimate upgrade costs to
     be about $10 million.

     Northern Explorer III - Strengths and Weaknesses

o    Upgrading -- the drillship has proven to be suitable for upgrade to a water
     depth capability of up to 5,000 feet. o Capability -- current 1,000 feet
     water-depth is attractive, though still outclassed by newer vessels.

o    Technology-- self-propelled, thus requiring no tugs or lift vessels for
     mobility; preferred in remote drilling locations. The Northern Explorer III
     can also be upgraded to ultra depth.

o    Class -- one of only four ice-class designed drillships worldwide. o
     Economic Life -- if refurbished, 10 years expected remaining life.

o    Age-- 26 years since drillship conversion has translated to an outclassed
     vessel well behind rigs built since mid-1980's to meet modern drilling
     technology.

o    Lay Up-- 4 1/2 years is regarded as elongated cold stack.

o    Image-- other drillships in the same class in the region have since been
     reactivated and re-contracted.

o    Asbestos-- reports show vessel does not meet Australian asbestos
     requirements.

o    Marketability-- second hand markets are not favourable to a disposal of its
     kind of vessel.

     The Galaxy Driller is a second-generation, conventionally moored
semi-submersible drilling unit that is capable of drilling in intermediate water
depths. It is equipped with an 18 3/4-inch, 10,000-psi BOP stack, a Varco TDS-3
top drive and an eight-point wire/chain mooring system, and has accommodations
for up to 96 people. The Galaxy Driller is currently laid up in Malaysia.

     Galaxy Driller - Issues and Status

o    Capability-- this has been impaired by prolonged stack, and an upgrade
     would be necessary to first redeem/renew last operating water depth of
     600Ft

o    Certificates-- trading and operating certificates have expired in January
     2002

o    Asbestos - some asbestos aboard, raising concerns about health standards;
     this would have to be addressed in any upgrade

o    Comparable-- Rig 82, a similar rig to the Galaxy Driller, was sold in
     October 2001 for $5.6 million

o    Upgrading - could be transformed to tender rig for about US$30 million,
     increasing marketability, but also taking the rig off the market for about
     6 months

o    Upgrade Costs-- company and independent sources estimate upgrade costs to
     be about $6.0 million

     Galaxy Driller - Strengths and Weaknesses

o    Work History-- the Galaxy Driller has had a stable working past, and the
     termination of its last contract in 1998 was not on account of operational
     incapacity

o    Marketability-- its location, South East Asia, is one of the most active
     regions currently

o    Small Size-- on record as the smallest ever built semi-drilling rig, making
     it suitable for small wells and intermediate water depths

o    Economic Life-- if refurbished, 10 years expected remaining life

o    Age-- given its age Galaxy Driller is small and old and will be among the
     last unit out working in a booming market

o    Long Stack--the rig has had 4 years of cold stack, well above the average
     for most rigs in South East Asia

o    Market-- the market for semi-subs has been less active at the second hand
     market end, rig has been offered unsuccessfully in several tenders in 2002
     and 2003

o    Storage-- due to its small size, the rig offers limited storage capacity,
     making supply vessels necessary

     The Discoverer I is a turret-moored drillship built in 1977 and acquired in
September 2000 at a price of $12.3 million. The Discoverer I has certifications
from ABS. It has a variable deck load capacity of 5,965 metric tonns. Discoverer
I completed a three-year drilling program with PEMEX in Mexico prior to delivery
to Northern Offshore. The Discoverer I is equipped with a 10,000-psi BOP stack
and a Varco TDS-3 top drive, and has accommodations for over 100 people. The
Discoverer I is currently laid up in Mexico.

     Discoverer I - Issues and Status

o    Steelwork-- in good shape although a stress test has not been carried out
     for some time

o    Coatings-- exterior coatings are in poor condition with painting systems
     failure standing at over 70%. Heavy rusts may be pushing steelwork and
     decks into severe damage zone

o    Facilities-- deck and domestic facilities have experienced wear and tear

o    Safety-- life-rafts, fire extinguishers and lifeboat inspections are
     overdue

o    Upgrade Costs-- Company and independent sources estimate upgrade costs to
     be about $6.5 million

o    Certification-- trading, safety, registration certificates expired in 2001

o    Capabilities-- Upgrade must attend to general dilapidation and focus on
     depth capacity in light of the new generation improvements in this respect

o           Asbestos-- the ship has some asbestos on board

            Discoverer I - Strengths and Weaknesses

o    Work History -- three-year contract successfully completed with Pemex in
     Mexico which lasted until August 2000 o Water Tightness -- drillship is
     still water tight o Technology -- self-propelled, requiring no tugs and
     lift vessels for mobility; preferred by operators in remote drilling
     locations o Economic Life -- if refurbished, 13 years expected remaining
     life

o    Old Age-- at over 25, the ship is substantially outdated compared to modern
     drilling capabilities in the industry; it has a depreciated engine and
     corroded compartments, and is susceptible to a shortened post-upgrade
     useful life

o    Long Stack-- the drillship is under prolonged stack; by contrast contracted
     ships of its class have an average lay-up of six months

o    Costs-- upgrade costs are high, going by recent similar drillship
     conversions and upgrading

o    Marketability-- there are no second hand buyers for the drillship class,
     and the liquidity provided by speculative dealers has disappeared since mid
     2001

     The Energy Searcher is a conventionally moored drilling vessel, which can
operate in water depths up to 2,500 ft. It is equipped with an 18 3/4-inch,
10,000-psi BOP stack, a Maritime Hydraulics 500 PTD top-drive and an eight-point
chain mooring system. It has a deck load capacity of 9,157 tons and has
accommodations for 110 people. The Energy Searcher is currently operating
offshore in S.E. Asia under a contract with Daewoo at a day-rate of $57,000,
which is expected to last until mid-January 2004.

     Energy Searcher - Issues and Status

o    Asbestos-- the drillship has some asbestos on board

o    State-- in good condition, suitable for operations at current full drilling
     capacity

     Energy Searcher - Strengths and Weaknesses

o    Work History -- the Searcher has been in continuous operation, building an
     attractive work history o Capabilities -- her current 2,500 ft water-depth
     capacity is mid-range competitive o Marketability -- there is demand for
     this type and design of vessel, currently in South East Asia and Mexico o
     Economic Life -- 13 years expected remaining life

o    Age-- the Energy Searcher has a 20-year conversion age, but the deck bulk
     carrier is carrying an age of 40 years; this tends to be factored into
     consideration in the second hand market

o    Market-- market liquidity for second hand drillships of its kind (age,
     build, capabilities) has virtually dried up

o    South East Asia-- the Energy Searcher finds itself in an active region
     where it is out-competed by the "Big 6" in the South East Asian regional
     market

     As stated above, all of our currently laid up units would need significant
refurbishment or upgrade expenditures before being put back into operation, and
we do not have the capital resources to finance these expenditures. See "Risk
Factors" in Item 3 of Part I of this report.

     As of November 30, 2003 the average age of our vessels (based on the date
of construction, other than the Northern Explorer II, which is based on the date
of conversion rather than when its hull was originally constructed) was
approximately 30 years.

Item 5. Operating and Financial Review and Prospects

     Statements we make in the following discussion that express a belief,
expectation or intention, as well as those that are not historical fact, are
forward-looking statements that are subject to risks, uncertainties and
assumptions. Our actual results, performance or achievements, or industry
results, could differ materially from those we express in the following
discussion as a result of a variety of factors, including the risks and
uncertainties we have referred to under the heading "Cautionary Statement
Concerning Forward-Looking Statements" immediately preceding Part I of this
report.

Going Concern

     Based on the budget and projected cash flow prepared under current
conditions, the company will be unable to meet a substantial part of its
obligations falling due in 2004 and 2005. Management hopes to find employment
for one or more of its four units, which are currently laid up. We believe that
any meaningful contribution resulting from employment of units currently laid up
would significantly improve the Company's ability to refinance its debt
obligations falling due in 2004 and 2005.

     If it is not possible to generate sufficient cash flow or to raise
additional capital to pay these debt obligations as they fall due then the
Company will be forced to sell assets to meet its obligations. There is no
guarantee that the Company would be able to raise sufficient capital through
asset sales to meet its debt obligations. These conditions give rise to
substantial doubt as to the ability of the Company to continue to operate as a
going concern.

     The discussion of our business opportunities below is based on the
assumption that we will be able to continue as a going concern. See "Financial
Statements" in Item 18 of Part III of this report.

Overview

     Northern Offshore is a continuation of the offshore drilling and production
operations of NOASA, which was formed in December 1997, and, consequently, has a
limited operating history. Because of our limited operating history, the
historical financial information this report contains may not be indicative of
our future operating results and financial condition. Our results of operations
will depend primarily on the level of exploration and production activity in the
oil and gas industry and the industry's willingness to spend capital on offshore
drilling and development operations, which in turn depends in part on prevailing
oil and gas prices, expectations about future prices, the cost of exploring for,
producing and delivering oil and gas, the discovery rate of new oil and gas
reserves in offshore drilling areas, domestic and international political,
military, regulatory and economic conditions, technological advances and the
ability of oil and gas companies to generate funds for capital expenditures.

     Prices for oil and gas historically have been extremely volatile and have
reacted to changes in the supply of and demand for oil and natural gas
(including changes resulting from the ability of the Organization of Petroleum
Exporting Countries ("OPEC") to establish and maintain production quotas),
domestic and worldwide economic conditions and political instability in oil
producing countries. We can provide no assurance that particular levels of oil
and gas activities and capital expenditures on offshore drilling and production
operations will be achieved or maintained or that demand for our services will
reflect the level of those activities. We anticipate prices for oil and natural
gas will continue to be volatile and affect the demand for and pricing of our
services. A material decline in oil or natural gas prices or activities could
materially adversely affect the demand for our services and, therefore, our
results of operations and financial condition.

     The offshore contract drilling and production industry is a highly
competitive and historically cyclical business. The industry is characterized by
high capital costs, long lead times for construction of new drilling and
production units and numerous competitors for contracts. Offshore drilling and
production units have no alternative uses and, because of their nature and the
environment in which they work, have relatively high maintenance costs, whether
or not operating. Because these costs are essentially fixed, and in order to
avoid additional expenses associated with temporarily idling or "stacking" our
drilling and production units, we may from time to time be required to bid our
drilling and production units out for hire at less than attractive rates,
depending on the prevailing contractual rates in a given region. See
"Information on the Company - Business Overview - Competition" in Item 4 of Part
I of this report.

     According to industry analysts, the short-term outlook for drilling
activity is gloomy in most market segments and regions. By December 2003, the
oil majors will have set next year's budgets, deciding how much capital to
allocate to drilling activities in 2004. It is expected that budgets will remain
flat compared to previous years.

     As a result of our relatively small fleet of drilling and production units,
our revenues at any time are primarily dependent on contracts with a limited
number of customers, and our results of operations may fluctuate depending on
the termination of any of our contracts and our continued ability to obtain
additional contracts for our drilling and production units. The Texaco Contract
accounted for 68% of our operating revenues in 2002. The Northern Explorer II,
the Northern Explorer III and the Galaxy Driller are currently without contracts
and are laid up in Malaysia, close to Singapore. The Discoverer I is currently
without a contract and is laid up in Mexico, and the Energy Searcher is
currently operating offshore in S.E. Asia under a contract with Daewoo at a
day-rate of $57,000, which is expected to last only until mid January 2004.. We
are actively marketing each of those units either for contract or sale. If we
are successful in achieving asset sales at attractive prices we would expect to
use proceeds of sales to refurbish or upgrade our remaining units to increase
the likelihood of obtaining future contracts. All of our laid up units would
require significant refurbishment or upgrade expenditure before being put back
into operation. (See Item 4. - Information on the Company - Property, Plants and
Equipment in Part I of this report).

     Since issuing our third quarter 2003 financial report, we have conducted a
review of the costs and benefits of keeping the Northern Explorer II in lay-up.
As a result we have adopted a plan to sell the NE II for scrap as we believe
that the costs of refurbishment and upgrade of this unit are greater than the
likely economic benefit of such expenditure. We expect to realize proceeds in
the region of $2million. We expect to record an impairment charge on this asset
of approximately $4.2 million in the fourth quarter of 2003.

     In addition, Texaco may terminate the Texaco Contract under certain
circumstances without further payment to us. See "-The Texaco Contract." If we
are unable to employ our drilling and production units at satisfactory rates,
our results of operations will be adversely affected. We usually obtain our
drilling and production contracts through competitive bidding against other
contractors. See "Information on the Company - Business Overview - Contracts,
Marketing and Customers - General" in Item 4 of Part I of this report.

 The Texaco Contract

     The Northern Producer is employed under a contract with Texaco for the
production of oil and gas from the Galley field in the U.K. sector of the North
Sea. The contract has an initial four-year period, which ended in January 2002,
and Texaco has options to extend the contract for up to an additional six years
over four initial option periods of six months each and then four additional
option periods of one year each. It may further extend the contract in order to
complete production following the expiration of the last option period. Texaco
has exercised its options to extend the contract to January 2005. Texaco have
notified us that they will not extend the current contract beyond January 2005.
We will try to redeploy the Northern Producer thereafter, but there can be no
assurance that we will be successful. Even if we were successful, there would
likely be a transitional period during which no revenues would be received.

     The Galley field comprises a series of accumulations located approximately
100 miles northeast of Aberdeen, Scotland. To date, there has been production
from two discoveries in the field, the Galley South and the Galley North.

     The Texaco Contract is divided into two phases: Phase I and Phase II. Phase
I, which began production on March 25, 1998, involves production from the Galley
North and Galley South reservoirs. The first oil from Phase II was produced in
March 1999 from an additional well in the extension of the North reservoir.
Phase II may also involve production from the other discoveries and prospects in
the field, in addition to prospects not part of the Galley field, including
production of third parties from developing nearby fields which may take
advantage of the infrastructure Texaco is installing in the Galley field area.

     The payments under the Texaco Contract are based on various day rate
elements (collectively, the "Aggregate Day rate") and a tariff rate (the "Tariff
Rate"), which partially depends on oil production volumes from the Galley field
and nearby third-party fields.

     The Aggregate Day rate includes, among others, elements representing
reimbursements of (1) our operating costs, including reimbursement of the
amounts we are required to pay PFM under our management agreement with PFM
pursuant to which PFM operates the Northern Producer on our behalf (the
"Operating Cost Elements"), and (2) costs we incurred in modifying the hull and
topsides of the Northern Producer (the "Modification Elements"). These elements
are denominated in British pounds and, for purposes of the following discussion,
have been translated into U.S. dollars based on the exchange rate of $1.00 =
0.63 British pounds, the noon buying rate in the City of New York for cable
transfers in British pounds as certified for customs purposes by the Federal
Reserve Bank of New York on March 31, 2003 (the "GBP Exchange Rate"). The
Aggregate Day rate is currently approximately $120,000 per day, which will
decrease to approximately $96,000 from November 9, 2003 for the remainder of the
contract term (subject, in each case, to the escalation of the Operating Cost
Elements referred to above). Escalation of the Operating Cost Elements is
subject to the agreement of Texaco concerning the calculation of the applicable
escalation factors in any period. These Aggregate Day rate amounts reflect a
recent increase to the Modification Elements to reflect the installation of
certain equipment on board the Northern Producer. These upgrades include the
installation of a natural gas liquid ("NGL") recovery unit and a third flowline
to handle production from the first well in Phase II. The Aggregate Day rate is
subject to reduction by a specified amount (approximately $5,400 per day) for
any day on which the Northern Producer fails to produce 10% of available
production (as defined in the contract), other than during periods when annual
maintenance is being performed or during other planned shutdowns and subject to
our ability to make up production shortfalls within the same calendar month or
the next succeeding calendar month.

     The Tariff Rate varies depending on the volume and source of production and
ranges between $1.25 and $2.00 per barrel of oil produced. For Phase I
production during the initial four-year term of the contract, the Tariff Rate
was $2.00 per barrel for production up to an aggregate of 22.8 million barrels,
$1.50 per barrel for production between 22.8 million and 29.5 million barrels
and $2.00 per barrel for production in excess of 29.5 million barrels. No tariff
was applicable to Phase I production beyond the initial four-year term (i.e.
after January 5, 2002). The Tariff Rate for Phase II production is $1.25 per
barrel for production from the Galley field (excluding the Galley North and
Galley South reservoirs) and generally $1.85 per barrel for production from
third-party fields. To date, no third-party fields have been drilled and we
currently do not anticipate drilling on third-party fields. In periods when
Texaco suspends operations and no production takes place, Texaco will pay us a
suspension rate of $18,000 per day in lieu of the Tariff Rate (subject to credit
against future Tariff Rate obligations), unless the suspension is caused by a
technical failure of the Northern Producer.

The rate elements currently in effect under the Texaco Contract are summarized
in the table below:

                                             Jan 2002-            Nov 2003-
                                             Nov 2003-            Jan 2008
                                             ---------            --------

Approximate aggregate day rate              $ 120,000               96,000
Per barrel tariff rate:
      Phase II - Galley field                    1.25                 1.85
      Phase II - 3rd party fields                1.25                 1.85

     (1) Any periods beyond January 5, 2002 are at Texaco's option. Texaco has
exercised its options to extend the contract until January 5, 2005. Texaco have
notified us that they will not extend the current contract beyond January 2005.

     (2)The Operating Cost Elements and the Modification Elements are reflected
in the Aggregate Day rate based on the GBP Exchange Rate of $1.00 = 0.63 British
pounds on March 31, 2003. The Operating Cost Elements are subject to annual
escalation to reflect anticipated cost increases and inflation.

     At cessation of production under the contract we are required to demobilise
the Northern Producer from the Galley Field. Our estimated cost is GBP 1.5
million.

     Our management contract with PFM runs concurrently with the Texaco Contract
(subject to our option to terminate after the initial four-year term). The
agreement provides for a fixed management fee at a rate of GBP 911 per day and
for incentive bonuses to PFM in the range of $0.02 to $0.025 per barrel produced
above certain defined levels. These amounts are in addition to operation and
production day rates and other fees payable to PFM that are reimbursed as
Operating Cost Elements of the Aggregate Day rate we receive from Texaco. In
addition, Texaco pays certain bonuses directly to PFM and to employees on board
the Northern Producer based on production activity and safety performance.

     Production under Phase I of the Texaco Contract began on March 25, 1998. We
earn a tariff rate per barrel in the range from $1.25 to $2.00 as outlined in
the table above. Texaco guaranteed a minimum production of 22.8 million barrels
over the initial four years of production, based on average daily production of
26,450 barrels/day, 21,400 barrels/day, 9,250 barrels/day and 5,200 barrels/day
for the first, second, third and fourth years of operation, respectively.

     The following table presents the approximate average production level from
the Northern Producer over the last three years:

                                             Barrels per day
                                             ---------------

1st quarter 2000                             40,000
2nd quarter 2000                             37,000
3rd quarter 2000                             28,300
4th quarter 2000                             34,200
1st quarter 2001                             30,000
2nd quarter 2001                             20,000
3rd quarter 2001                             22,400
4th quarter 2001                             22,700
1st quarter 2002                             22,100
2nd quarter 2002                             19,700
3rd quarter 2002                             13,200
4th quarter 2002                             15,000

     Texaco has the right to terminate the Texaco Contract (1) if we breach
certain provisions of the contract and fail to take actions to cure the breach
within five days of notice from Texaco, (2) on certain events of bankruptcy or
insolvency involving us, (3) if the Northern Producer becomes a total loss or
sustains damage (other than damage caused by Texaco) rendering it unable to
produce oil for 90 consecutive days or for 90 cumulative days in any period of
120 consecutive days, (4) if a force majeure condition exists for more than 30
consecutive days or for 30 cumulative days in any period of 90 consecutive days
or (5) if we or any of our representatives violate certain laws, including the
U.S. Foreign Corrupt Practices Act. Texaco has the right to terminate the
contract for its own commercial reasons at the end of each option period. Texaco
has exercised options, thereby extending the contract term to January 6, 2005.
Texaco have notified us that they will not extend the current contract beyond
January 2005.

Revenues and Operating Expenses

     During 2002 and 2001, the Northern Producer and the Energy Searcher (after
its acquisition in June 2001) were the only income generating units in our
fleet. During 2000 and 1999, the Northern Producer was our only unit generating
operating income. During 1998, we derived our revenues and other income from (1)
payments under day rate-based contracts for our drilling and production units,
including the Texaco Contract, (2) payments under the "bareboat" charter for the
Galaxy Driller and (3) payments from Hemen Holdings under the Minimum Rate
Guarantees described below. In future periods, we expect our revenues will be
primarily a function of:-

     o    utilisation rates and day rates for active contracts, which depend in
          part on the market price of oil and gas;

     o    availability of capable drilling and production units for particular
          jobs;

     o    availability of capital for refurbishments and upgrades;

     o    any redeployment of the Northern Producer after January 2005;

     o    whether we are able to put any of our laid up units back into
          operation in light of our present capital constraints

     Our operating expenses include all our direct costs and expenditures
associated with operating active drilling and production units and the cost of
lay up for inactive units. Our operating expenses, excluding depreciation and
amortization, are generally comprised of (1) fees and expenses under our
management service agreements (see "Information on the Company - Business
Overview - Contracts, Marketing and Customers - General" in Item 4 of Part I of
this report), (2) wages and social expenses, which include shore-based and
offshore labor costs, and (3) other operating (non-personnel-related) and
administrative expenses, which include repair and maintenance of our drilling
and production units, insurance, various foreign taxes, fuel costs (when not
covered by a contract), mobilization costs (when not covered by a contract),
certain overhead expenses and special periodic survey costs. For vessels that
are in lay up, daily lay up costs are generally equal to actual operating costs
during short periods of lay up and generally between $1,000 and $3,000 per day
per unit during extended periods of lay up.

  Depreciation and Amortization

     We depreciate each of our drilling and production units on a straight-line
basis over the remaining expected useful life of the unit. Significant
investments on each unit are capitalized and depreciated in accordance with the
nature of the investment. Investments that are deemed to increase the value of
an asset for the asset's remaining useful life are depreciated over the
remaining useful life of the asset.

Financial Income/Expenses

     We are subject to pay interest on our indebtedness at a fixed rate of 10%
on our outstanding amount of 10% Senior Notes due 2005 and at floating rates
based on Libor or Nibor plus margins of between 2% and 6.5% on our other
indebtedness. As some of our indebtedness is denominated in NOK, we are subject
to foreign currency exchange gains or losses when the exchange rate for NOK
fluctuates with respect to the U.S. Dollar. From time to time, we may hedge our
exposure to movements in exchange rates by entering into derivative contracts,
which give rise to gains or losses. At the current date we are not party to any
such contracts.

Inflation

     As a result of the relatively low levels of inflation in the areas of our
operations during the last three years, inflation did not have a significant
effect on our results of operations during the years ended December 31, 2002,
2001 and 2000. However, changing prices and other market forces, particularly
changes in prices for oil and natural gas, impact our business. See "-Overview"
and "-Results of Operations."

Exposure to Currency Fluctuations

     Although Northern Offshore is domiciled in Bermuda, the majority of our
monetary assets, liabilities and revenues and a significant portion of our
operating costs are denominated in U.S. dollars. Therefore, in the opinion of
our management, our functional currency is the U.S. dollar. In addition, we use
the U.S. dollar as our reporting currency. Our foreign operations sometimes
involve the risks of fluctuating currency values, hard currency shortages and
controls of foreign currency exchange. From time to time we may attempt to limit
our exposure to foreign currency fluctuation by the use of derivative contracts.
We currently have no such contracts. However, certain rate elements of the
Texaco Contract are denominated in British pounds, and we may in the future
enter into drilling and production contracts that provide for payment in
currencies other than the U.S. dollar. Accordingly, our profitability will
likely be affected by fluctuations in foreign exchange rates.

A.   Critical Accounting Policies

     Our consolidated financial statements are prepared in accordance with
accounting principles generally accepted in the United States of America, which
require us to make estimates in the application of our accounting policies based
on the best assumptions, judgments, and opinions of management. Following is a
discussion of the accounting policies that involve a higher degree of judgment
and the methods of their application. For a description of all of our material
accounting policies, see Note 3 to our consolidated financial statements set
forth in Item 18.

     Revenue and expense recognition

     Day rate contract revenues and expenses related to contracts that extend
beyond the end of an accounting period are accrued on the basis of the number of
contract days on either side of the balance sheet date. The Texaco contract
includes provisions for annual changes in certain elements of the contract day
rates to reflect changes in certain price indices. We only recognise changes in
these day rate elements when they have been agreed and accepted by Texaco. In
periods during which we are entitled to receive income based on day rates, which
have not been agreed and accepted by Texaco, we accrue day rate revenues based
on the previously agreed and accepted rates. As a result we may be required to
recognise adjustments to income that we have recognised in previous periods in
the period in which changes in day rates are agreed and accepted by Texaco.
Other contract revenues including mobilisation fees and completion bonuses are
only recognised when all the conditions required to ensure payment have been
met. Significant repair and maintenance costs are expensed when incurred.
Interest expenses are accrued on a daily basis.

     Property and equipment

     Property and equipment is reflected in the balance sheet at its historical
cost less accumulated depreciation and any write-downs. Cost of assets includes
the interest cost capitalised for assets that have been upgraded or reactivated.
Depreciation is recorded on a straight-line basis in accordance with the
estimated useful lives of the assets. We make judgements about the estimated
useful lives of our assets which are based on our knowledge and experience of
drillships and floating production platforms. The actual lives of our assets may
differ from our estimates. If the actual useful lives of our assets differ from
our estimates we may incur higher depreciation charges in future or additional
writedowns of our assets. We are not able to quantify the effects on our
financial position of possible future changes to these estimates.

     Impairment of long-lived assets

     Long-lived assets and certain identifiable intangibles held and used by
Northern Offshore are required to be reviewed for impairment whenever events or
a change in circumstances indicate that the carrying amount of an asset may not
be recoverable. In performing the review for recoverability, we estimates the
future cash flows expected to result from the use of the asset and its eventual
disposition. If the undiscounted future cash flows are less than the carrying
amount of the asset, the asset is deemed impaired. The amount of impairment is
measured as the difference between the carrying amount and the fair value of the
asset. Generally, long-lived assets and certain intangibles to be disposed of
are reported at the lower of their carrying amount or their fair value less
selling costs.

     The carrying values of our long-lived assets and certain identifiable
intangibles may not represent their fair market value at any point in time since
the market prices of second hand production and drilling vessels tend to
fluctuate with changes in the market for employment of these units. We only
record impairment losses when events occur that cause us to believe that future
cash flows for any individual production or drilling vessel will be less than
its carrying value.

     In assessing the recoverability of a vessel's carrying amount, the Company
must make judgements regarding estimated future cash flows. These judgements
include assumptions about market rates for our vessels, operating costs for our
vessels, the estimated economic useful life of our vessels and the length of
time we will hold our vessels for use. In making these assumptions the Company
refers to historical trends and performance as well as any known future factors.
Factors we consider important which could effect recoverability and trigger
impairment include significant underperformance relative to expected operating
results, new regulations that change the estimated useful economic life of our
vessels, significant negative industry or economic trends, and future decisions
to sell vessels. We are not able to quantify the effects on our financial
position of possible future changes to these assumptions.

     For laid up units it is not possible for us to accurately estimate future
cash flows. Therefore, any impairment charge will be based solely on brokers'
estimates of resale value.

B.   Operating Results

Year Ended December 31, 2002 Compared with Year Ended December 31, 2001

     Operating revenues for the year ended December 31, 2002 were $69.3 million
compared to $54.1 million for the year ended December 31, 2001. The increase of
$15.2 million was mostly due to the inclusion of a full year's earnings of the
Energy Searcher, which was acquired in June 2001.

     Operating expenses (excluding depreciation, amortisation and impairment
losses) totalled $36.2 million in the year ended December 31, 2002 compared with
$28.7 million in the year ended December 31, 2001. The net increase of $7.5
million is principally due to the following factors:

     o    Inclusion of a full year's costs of the Energy Searcher in 2002

     o    Lower administrative costs since closure of the Company's Oslo office
          in January 2002

     o    Recording of a claim against the Company by INPEX of $0.9 million in
          2002

     INPEX raised a claim against the Company in 2002 for their losses caused by
damaged equipment belonging to the Energy Searcher. The claim was settled for
USD 0.9 million in July 2003. This amount has been recorded in other operating
expenses in the income statement for the year ended December 31, 2002.

     Depreciation for the year ended December 31, 2002 amounted to $16.7 million
compared with $17.6 million in the year ended December 31, 2001. The reduction
is a result of lower depreciation charges as a result of the write-downs of the
Northern Explorer III and Galaxy Driller in December 2001 offset by the
inclusion of a full year's charge for Energy Searcher in 2002.

     Based on our impairment testing accounting policy we provided further
write-downs of Northern Explorer III and Galaxy Driller in 2002 amounting to
$21.6 million, which compared to total write-downs relating to the same vessels
of $31.6 million in 2001.

     Our net financial expenses totalled $19.2 million in the year ended
December 31, 2002 compared with $13.6 million in the year ended December 31,
2001. Interest expense was $18.9 million in the year ended December 31, 2002
compared to $20.4 million in the year ended December 31, 2001. The decrease of
$0.5 million was due to net repayments of indebtedness during 2002 combined with
lower Libor rates compared with the prior year. We recorded foreign currency
exchange losses of $5.8 million in the year ended December 31, 2002 due mainly
to the appreciation of the NOK against the U.S. Dollar in the year, which
increased the U.S. Dollar equivalent amount of our NOK denominated debt. In the
year ended December 31, 2001 the corresponding amount was a loss of $0.1
million. Foreign currency exchange losses in the year ended December 31, 2002
were offset by gains of $5.3 million on derivative contracts, which hedged our
exposure to fluctuations on the exchange rate between the U.S. Dollar and NOK.
The corresponding gain in the year ended December 31, 2002 was $0.1 million.
Financial income/expenses included gains from early extinguishments of debt
amounting to $6.4 million in the year ended December 31, 2001. In the year ended
December 31, 2002 there were no extinguishments of debt.

     In the year ended December 31, 2002 we recorded a gain of $6.1 million as
the cumulative effect of changing to a different accounting principle for
drydocking costs. We previously accrued drydocking costs and during the year
ended December 31, 2002 we changed to the expense-as-incurred method. In the
year ended December 31, 2001 we recorded a gain of $0.7 million as a result of
the adoption of SFAS 133.

     Our operating loss for 2002 was $5.2 million. Our operating loss for 2001
was $23.8 million. Our net loss for 2002 was $18.8 million. Our net loss for
2001 was $37.4 million.

Year Ended December 31, 2001 Compared with Year Ended December 31, 2000

     Operating revenues for the year ended December 31, 2001 were approximately
$54.7 million, compared to approximately $52.4 million for the year ended
December 31, 2000. We did not record any other revenues for the year ended
December 31, 2001 compared to other revenues of approximately $6.1 million year
ended December 31, 2000 as a result of a settlement with Coplex of our claim
relating to the cancelled bareboat charter for the Galaxy Driller.

     Our operating expenses (excluding depreciation and amortization) for 2001
totalled $28.7 million, up from approximately $21.9 million for 2000. The
increase in operating expenses was mainly due to the acquisition of the
drillship Energy Searcher in June 2001 and administrative costs relating to our
operations in Singapore (since June 2001) together with the costs of closing our
Oslo office.

     Depreciation for 2001 was approximately $17.6 million, up from
approximately $15.6 million for 2000. The increase in depreciation is due to
depreciation relating to the Energy Searcher, which was acquired in June 2001.
In 2001 we wrote down the book value of the Galaxy Driller and Northern Explorer
III, which we considered have suffered from impairment, by $31.6 million (2000 -
$nil).

     During 2001, we repurchased an aggregate principal amount of $23.4 million
of our 10% Senior Notes due 2005 at an average price of 71.9% of their face
amount, resulting in a gain of $6.6 million. This compared to repurchases during
2000 of $81.1 million at an average price of 61.9% of their face amount,
resulting in a gain of $29.3 million. See "-- Liquidity and Capital Resources".

     Our operating loss for 2001 was $23.1 million. Our operating profit for
2000 was approximately $21.0 million. Our net loss for 2001 was $37.4 million.
Our net income for 2000 was $18.6 million.

C.   Liquidity and Capital Resources

     On May 8, 1998, we issued and sold $340.0 million aggregate principal
amount of our 10% Series A senior notes due 2005 (together with the related
guarantees issued by certain of our Subsidiaries, the old 10% Senior Notes due
2005) in a non-public transaction (the `1998 Debt Offering') exempt from the
registration requirements under the Securities Act of 1933, as amended (the
"Securities Act"). We issued the old 10% Senior Notes due 2005 under an
indenture dated as of May 1, 1998 between Northern Offshore, as issuer, the
Subsidiaries, as subsidiary guarantors, and Chase Bank of Texas, National
Association, as trustee, as amended (the "Indenture").

     We issued the new 10% Senior Notes due 2005 in an exchange offer and
registration rights agreement pursuant to the Indenture. The new 10% Senior
Notes due 2005 are general unsecured obligations of Northern Offshore with an
equal ranking in right of payment to all future senior indebtedness of Northern
Offshore and senior to all subordinated indebtedness Northern Offshore may incur
in the future. The Notes and the guarantees are unsecured and are effectively
subordinated to all of our secured indebtedness.

     As a result of the depressed high yield bond market in the United States
between 1998 and 2001, we took the opportunity to repurchase some of our 10%
Senior Notes. The following table summarizes these repurchases:

                                Average           Aggregate
                 Face           Repurchase        Repurchase      Gain on
Year             Amount         Price (%)         Price           Repurchase
----             ---------------------------------------------------------------
                                         (in millions)

1998              $10.0         59%                 $5.9           $4.1
1999              $82.2         49%                $40.6          $41.7
2000              $81.1         62%                $50.2          $30.9
2001              $23.5         72%                $16.8           $6.6
                 ------         ------            ------          ------

Total            $196.8         58%               $113.5          $83.3
                 ======         ======            ======          ======

     We have an aggregate principal amount of $143.2 million outstanding as of
December 31, 2002. We may from time to time repurchase additional notes in the
future, depending on, among other things, market conditions, trading values of
the notes and our working capital balances.

     The repurchased Notes are held by us and one of our subsidiaries and are
accounted for as if extinguished. However, Notes with a face value of $166.3
million are pledged to secure a loan from Avalon Holdings Ltd., an affiliated
third party.

     The repurchases made in 2001 were partly financed by new NOK denominated
loans totaling NOK 168,000,000 (equivalent to $24.1 million). We raised NOK
143,000,000 through the public issuance of bonds, and Kredittbanken ASA, a
Norwegian bank, loaned us the remaining NOK 25,000,000. The loan from
Kredittbanken ASA was fully repaid in April 2003. The NOK bond issue was due to
be repaid in full in April 2003 and has been extended by agreement with
bondholders to October 2004 (as discussed below).

     The repurchases made in 2000 were partly financed by a $30 million loan
(the "Avalon Loan") obtained from Avalon Holdings Ltd., an affiliate of World
Shipholding Ltd. Borrowings under the Avalon Loan are secured by $166.3 million
aggregate principal amount of 10% Senior Notes due 2005. In February 2001, the
loan was amended to modify the repayment schedule and extend the facility to
July 2002. In April 2003 the loan was further amended to extend repayment to
June 2004 when a final repayment of $3.2 million is due (as discussed below).
The balance outstanding on this loan is $11.3 million as at June 2003. The
interest rate payable is LIBOR plus 6.5% per annum. We also borrowed $10.0
million from Avalon Holdings Ltd. in 2002 under a revolving credit facility.
This facility was fully repaid by December 31, 2002. The proceeds were used to
repay the Den norske Bank loan described below and to provide general liquidity.
Also see "Major Shareholders and Related Party Transactions - Related Party
Transactions" in Item 7 of Part I of this report.

     We bought the Energy Searcher on June 22, 2001 at a price of $37 million.
The Energy Searcher is a conventionally moored drilling vessel, which can
operate in water depths up to 2,500 ft. We also acquired Jet Drilling (S) Pte
Ltd, a Singapore based management company, on the same date. Jet Drilling is
intended to form the basis for our future drilling operations in South-East
Asia. In connection with the acquisition of the Energy Searcher, we incurred
debt under an $11.0 million revolving credit facility with BNP Paribas. The
amount outstanding under this loan facility is $6.5 million as at November 30,
2003. Interest is payable at LIBOR plus a margin of 3%. The loan has been
extended to June 2004 when $5.5 million is due as a final repayment (as
discussed below). The acquisition of Energy Searcher was further financed
through an equity placement of 9.5 million Common Shares at NOK 16.50 per share,
totalling approximately $17 million, and a $9 million bridging loan from Den
norske Bank, which was guaranteed by Greenwich Holdings Ltd. This loan provided
for payments of interest at a rate equal to LIBOR plus 2% per annum. This loan
was fully repaid as at December 31, 2002. In connection with the guarantee, we
paid Greenwich Holdings Ltd., an affiliate, a guarantee commission equal to 4%
per annum on the amount outstanding.

     As of December 31, 2002 we had a working capital deficit and a cash balance
of $3.3 million. As of December 31, 2001, we had a working capital deficit of
$30.3 million and a cash balance of $7.5 million. We presently have no revolving
credit facility or source of funding our working capital needs other than cash
flows from operations.

     On April 1, 2003, the holders of the Company's NOK denominated loan in the
amount of NOK 143 million (equivalent to USD 20.6 million) voted to extend the
maturity of the loan from April, 2003 to October, 2004 subject to the following
terms and conditions:

     o    The loan is repaid on October 6, 2004 at 102.5% of face value

     o    The interest rate of the loan is increased from NIBOR plus a margin of
          4.5% to NIBOR plus a margin of 5.5%

     o    A non-recurring loan extension fee equivalent to 2.5% of the
          outstanding loan will be paid to the loan holders on April 24, 2003

     o    The extension of the loans from Avalon Holdings Ltd and Banque
          Nationale Paribas referred to below.

     The secured loan provided by BNP Paribas with a principal amount of USD 9.0
million has been extended with revised repayment maturities. The final
instalment of USD 5.5 million will be due in June 2004. The secured loan
provided by Avalon Holdings Ltd. with a principal amount of USD 11.3 million has
been extended with revised repayment maturities. The final instalment of USD 3.3
million will be due in June 2004.

     If it had not been possible for us to obtain the loan extensions discussed
above, it is unlikely that we would have been able to refinance all of these
loans. We can have no assurance that we will be able to obtain further
extensions of these loans in future or that we will be able to refinance them at
maturity.

     During 2000, our capital expenditures were approximately $12.3 million to
acquire the Discoverer I, in addition to approximately $2 million relating to
improvements to the Northern Producer.

     We have not made any other material commitments or plans for capital
expenditures in 2003 and beyond. However, in the future, any prospective
customer would likely require us to upgrade one of our vessels or make other
substantial capital expenditures as a condition to entering into a long-term
drilling or production contract which would require substantial expenditures
estimated at $6 - 10 million per vessel. In addition, we will continue to review
acquisitions of drilling and production units from time to time. To the extent
our cash flows from operations are insufficient to fund future capital
expenditures and/or future acquisitions, we may seek to raise capital through
additional debt or equity financings. We can provide no assurance that we will
be able to obtain additional capital on terms we deem acceptable or at all.

     Northern Offshore is a holding company whose only assets consist of
ownership interests in the Subsidiaries, which are organized under the laws of
the Kingdom of Norway, Liberia, Cyprus, Singapore, Malaysia, St. Vincent & the
Grenadines and the British Virgin Islands (see "Information on the Company -
Organizational Structure" in Item 4 of Part I of this report). Consequently,
Northern Offshore's ability to obtain cash from the Subsidiaries for the purpose
of meeting its debt service obligations, including the payment of principal and
interest on the 10% Senior Notes due 2005, depends on the earnings of the
Subsidiaries and Northern Offshore's ability to receive funds from the
Subsidiaries through dividends, distributions, loans, advances or other
payments. Northern Offshore's ability to obtain funds from the Subsidiaries
through dividends, distributions, loans or advances, is restricted by factors
including the following:

     o    with respect to Northern Offshore Management AS, the requirement under
          the Norwegian Public Limited Companies Act that dividends be declared
          and paid out of capital surplus only, or in case there is no capital
          surplus, declared or paid out of the net profits for the fiscal year
          in which the dividend is declared and for the preceding year;

     o    with respect to Helm Maritime Corp., Merit Maritime Limited, Monarch
          Seacarriers Inc., Katzen International Corp. and Northern Discoverer
          Inc., the requirement under the Business Corporation Act of Liberia,
          as amended, that dividends be declared and paid out of capital surplus
          only, or in case there is no capital surplus, declared or paid out of
          the net profits for the fiscal year in which the dividend is declared
          and for the preceding year;

     o    with respect to Qualimar Shipping Company Limited, the requirement
          under the Companies Law of Cyprus that dividends must be declared and
          paid out of net profits only; and

     o    with respect to Sea Production Limited, the requirement under the
          International Business Companies Ordinance of the British Virgin
          Islands, that dividends be declared and paid out of surplus and that
          immediately after the payment of the dividend the company's directors
          can determine (1) the company will be able to satisfy its liabilities
          as they become due in the ordinary course of business and (2) that the
          realizable sum of the company's assets will not be less than the sum
          of its total liabilities, other than deferred taxes, as shown in its
          books of account, and its capital.

     o    with respect to Jet Drilling (S) Pte. Ltd, the requirement under the
          Singapore Companies Act that no dividend shall be payable to the
          shareholders except out of profit.

     o    with respect to Jet Shipping Ltd and Jet Holding Ltd, the requirement
          under the St. Vincent and the Grenadines International Companies Act
          that no dividend shall be payable except out of profit arising from
          the business of the company.

     o    With respect to Jet Shipping Ltd. and Jet Holding Ltd., the
          restriction that surplus cash flow generated by contract earnings of
          the Energy Searcher be reserved to secure interest and repayments due
          on the loan from BNP Paribas.

     As at the date of this report the only subsidiaries with the ability to pay
dividends, distributions, loans or advances to us are Qualimar Shipping Company
Ltd. and Sea Production Ltd.

     Based on the budget and projected cash flow prepared under current
conditions, the company will be unable to meet a substantial part of its
obligations falling due in 2004 and 2005. Management hopes to find employment
for one or more of its four units, which are currently laid up, although this
would require substantial expenditures estimated at $6 - 10 million per vessel.
We believe any meaningful contribution resulting from employment of units
currently laid up would significantly improve the Company's ability to repay its
debt obligations falling due in 2004 and 2005.

     If it is not possible to generate sufficient cash flow or to raise
additional capital to pay these debt obligations as they fall due then the
Company will be forced to sell assets to meet its obligations. There is no
guarantee that the Company would be able to raise sufficient capital through
asset sales to meet its debt obligations. These conditions give rise to
substantial doubt as to the ability of the Company to continue to operate as a
going concern.

     At December 31, 2002, our total debt was approximately $187.6 million of
which $10.6 million is due in 2003, $33.8 million is due in 2004 and $143.2
million is due in 2005. Our total assets were approximately $170.3 million and
our shareholders' deficit was approximately $27.1 million. We also had a working
capital deficit at December 31, 2002. Subject to the restrictions in the
indenture relating to our outstanding 10% Senior Notes due 2005, we may incur
additional indebtedness from time to time to provide working capital, to finance
acquisitions or capital expenditures and for other purposes, although we are
unaware of presently available sources for additional indebtedness. The level of
our indebtedness will have several important effects on our future operations,
including, without limitation:

     o    substantially all of our cash flows from operations must be dedicated
          to the payment of interest and principal on our indebtedness;

     o    our debt service requirements limit our resources for capital
          expenditures, as well as upgrades and refurbishments of our vessels.

     o    our increased leveraged position will substantially increase our
          vulnerability to adverse changes in general economic and industry
          conditions; and

     o    our ability to obtain additional financing for working capital,
          capital expenditures, acquisitions, general corporate and other
          purposes may be limited.

     In this connection, the indenture relating to our outstanding 10% Senior
Notes due 2005 contains certain restrictive covenants that, among other things,
limit our ability and the ability of certain of our subsidiaries to incur
additional indebtedness and engage in sale-and-leaseback and other financing
transactions. We presently have no revolving credit facility or other sources of
liquidity except cash flow from operations. Most of our subsidiaries have
guaranteed our 10% Senior Notes. Such obligations may inhibit their ability to
obtain future financing for upgrades, refurbishments or other requirements.

     Even though most of our drilling units are currently laid up, we are
currently generating sufficient earnings under the Texaco Contract and contracts
performed by the Energy Searcher to cover our daily operating expenses and
interest expense on our indebtedness. However, we have experienced short-term
liquidity deficiencies which have resulted in our inability to pay interest
payments on our 10% Senior Notes due 2005 on the due dates. To date, we have
been able to fund these payments within the available 30-day grace period as
granted under the terms of the Notes Indenture. The minimum rate payments under
the Texaco Contract currently amount to approximately $43.8 million per year.
The Energy Searcher is currently earning a day-rate of $57,000 under its current
contract with Daewoo, which is expected to end in January 2004. Lay-up costs for
the four drilling units that are currently laid up amounts to approximately $3.5
million per year, and interest on our indebtedness (after giving effect to our
repurchases of our 10% Senior Notes due 2005) amounts to approximately $18.9
million per year. As of December 31, 2002, our cash and cash equivalents
amounted to approximately $3.3 million.

     We are not currently generating sufficient cash flows from operations to
pay our existing indebtedness, including the 10% Senior Notes due 2005, at
maturity. Accordingly, if current market conditions persist for an extended
period of time, we would have to obtain new debt or equity financing to
refinance our indebtedness at maturity, or to sell selected assets. In April
2003 we arranged extensions of maturities of 3 loans totalling $20.3 million and
NOK 143.0 million (equivalent to $20.6 million) which were originally due to be
repaid in March and April 2003. These loans now have final maturities between
June and October 2004. In the absence of these loan extensions it is unlikely
that we would have been able to refinance this indebtedness. We are unaware of
any sources that would be available to us to refinance this indebtedness.

     Our Board of Directors is currently considering a proposal whereby the
Company's unsecured creditors would be asked to convert their claims into an
equity stake in the Company. We can give no assurance that any proposed debt to
equity conversion would be accepted by creditors.

D.   Research and Development, Patents and Licenses, Etc.

     Not applicable

E.   Trend Information

     See "--Overview" above.

Item 6. Directors, Senior Management and Employees

A.   Directors and Senior Management

     In accordance with Bermudian law, Northern Offshore's affairs are managed
by its Board of Directors, which is also vested with overall control of our
policy and management. The members of Northern Offshore's Board of Directors (1)
are elected by its shareholders and (2) serve one-year terms. There is no
limitation on the number of terms that directors may serve.

     In addition to reviewing and monitoring our business, the powers generally
held by the Board of Directors include the preparation of our year-end financial
statements, the presentation of the financial statements to the shareholders and
the convening of shareholders' meetings.

     The following table sets forth certain information regarding our directors
and senior management (ages are as of June, 2003):

Name                      Age            Position

Jon Aksel Torgersen        51            Chairman and Director
Tor Olav Tr0im             40            Chief Executive Officer and Director
Dimitris Hannas            55            Director
Kate Blankenship           38            Resident Representative
Iain Cawte                 36            Chief Financial Officer
Jill Paynter               41            Secretary

     Jon Aksel Torgersen has been Chairman of the Board and a director of
Northern Offshore since December 1997. For more than the past five years, he has
been a managing director of Astrup Fearnley A.S., a Norwegian investment company
focused on shipping and other industries. Mr. Torgersen is also a member of the
boards of directors of Atlantic Container Line, Northern Oil ASA and I.M Skaugen
ASA.

     Tor Olav Tr0im has been a director of Northern Offshore since December
1997. He has been Vice-President and a director of Frontline Ltd, a publicly
listed international shipping company affiliated with Greenwich Holdings
Limited, since November 3, 1997 and an advisor to Greenwich Holdings Limited
since May 1995. He has also been the chief executive officer of Golar LNG
Limited, a publicly listed shipping company, since May 2001. Prior to his
service with us, he served as Managing Director and a member of the board of
directors of DNO AS, a Norwegian oil company. Mr. Tr0im also serves as a
director of Northern Oil ASA. and Aktiv Inkasso ASA.

     Dimitris Hannas has been a director of Northern Offshore since June 17,
1999. He has been the General Manager and a director of Seatankers Management
Co. Ltd. in Cyprus for more than the past five years. Mr. Hannas is also a
member of the board of directors of Sea Production Ltd. Mr. Hannas has more than
25 years of experience in the shipping industry.

     Kate Blankenship has served as our resident representative since our
relocation to Bermuda in May 2000. She has been the chief accounting officer and
secretary of Frontline Ltd since 1994, of Knightsbridge Tankers since 2000 and
of Golar LNG Limited since May 2001. Prior to 1994, she was a manager with KPMG
Peat Marwick in Bermuda. She is a member of the Institute of Chartered
Accountants in England and Wales.

     Iain Cawte has served as chief financial officer since January 1, 2002. He
has been chief accountant of Golden Ocean Group Limited since September 1997.
Prior to 1997, he worked for Moore Stephens Chartered Accountants in their
general business department. He is a member of the Institute of Chartered
Accountants in England and Wales.

     Jill Paynter has served as secretary since our relocation to Bermuda in May
2000. She has been employed by Frontline Management (Bermuda) Ltd. since
December 1999.

     Kate Blankenship, Iain Cawte and Jill Paynter are employed by Frontline
Management (Bermuda) Ltd, an affiliated third party. Their services as officers
are provided under the terms of a management agreement between Northern Offshore
and Frontline Management (Bermuda) Ltd. They are not directly remunerated by us
and do not work full time for us. See "Related Party Transactions" in Item 7 of
Part I of this report.

     Dimitris Hannas is employed by Seatankers Management Co. Ltd, an affiliated
third party. His services as Director are provided under the terms of a
management agreement between Northern Offshore and Seatankers Management Co.
Ltd. He is not directly remunerated by us and does not work full time for us.
See "Related Party Transactions" in Item 7 of Part I of this report.

     Jon Aksel Torgersen and Tor Olav Troim are directly employed by us under
the terms of Directors' service contracts.

     Our operations depend on the continuing efforts of our executive officers.
Our business and prospects could be affected adversely if these persons do not
continue in their management roles unless replaced by qualified personnel. We do
not maintain key employee insurance.

B.   Compensation

     During 2002 we paid an aggregate of $nil in cash compensation to our
directors and executive officers. In June 2003 we paid an amount of $13,500 in
cash compensation to one of our directors in respect of his service during the
year ended December 31, 2002.

     We paid Frontline Management (Bermuda) Ltd a management fee of $120,000 in
the year ended December 31, 2002. Frontline provides the services of- Kate
Blankenship, Iain Cawte and Jill Paynter as officers of Northern Offshore.

     We paid Seatankers Management Co. Ltd a management fee of $100,000 in the
year ended December 31, 2002 which includes payment for the provision of the
services of Dimitris Hannas as a director.

     During 2001, we paid an aggregate of approximately $493,000 in cash
compensation to our directors and executive officers, including approximately
$144,000 that we paid to our former President. In addition, we paid
approximately $126,000 in 2001 for pension and retirement benefits for our
current directors and executive officers.

     As part of our relocation to Bermuda, the Oslo office of Northern Offshore
Management AS was closed in January 2002, and we terminated all of the then
current executive officers. Termination payments to directors and executive
officers incurred as part of the closure of this office amounted to
approximately $426,000, including $144,000 paid to our former President. All
termination payments were included in administrative expenses for 2001.

     The defined benefit pension plan for employees of Northern Offshore
Management AS and the Stock Option Plan were both terminated effective January
1, 2002, and we have no remaining liability under these plans.

C.   Board Practices

     In accordance with our bye-laws, the number of directors shall be such
number not less than two as we determine by ordinary resolution from time to
time. Each director shall hold office until the next annual general meeting
following his election or until his successor is elected. We currently have four
directors.

     Our officers are elected by the Board of Directors as soon as possible
following each Annual General Meeting and shall hold office for such period and
on such terms as the Board may determine.

     There are no service contracts between us and any of our directors
providing benefits upon termination of their employment or service.

     We do not have audit or remuneration or other committees.

D.   Employees

     Northern Offshore and its subsidiaries employed approximately 63 people as
of December 31, 2002. These employees were located at the office of our
subsidiary, Jet Drilling (S) PTE Ltd in Singapore and includes personnel
employed onboard our vessels.. Although we retain the ability to direct the
management of the operations of our vessels, we also rely on the services of
PFM, Frontline Management (Bermuda) Ltd and other third parties to operate the
Northern Producer and for the performance of certain administrative functions.
See "Information on the Company - Business Overview - Contracts, Marketing and
Customers" in Item 4 of Part I of this report. From time to time, we may operate
in countries that require operating under industry-wide collective bargaining
arrangements. We believe our relationship with PFM and its employees is
satisfactory.

     The offshore contract drilling and production business is characterized by,
among other things, high turnover rates among offshore personnel. We seek to
(and retain management companies who seek to) attract and retain qualified
offshore personnel by paying competitive wages. Although we do not currently
anticipate a shortage of qualified personnel in our operations, if demand for
offshore contract drilling and production services were to increase
significantly above current levels, retention of qualified personnel could
become difficult without significant increases in compensation.

E.   Share Ownership

     The beneficial interests of our directors and officers in the Common Shares
of the Company as of November 30, 2003, were as follows:

Name                                                    Common shares

Jon Aksel Torgersen                                               nil
Tor Olav Tr0im                                              1,000,000
Dimitris Hannas                                                   nil
Kate Blankenship                                                  nil
Iain Cawte                                                        nil
Jill Paynter                                                      nil

     None of our directors holds one percent or more of the Common Shares
outstanding. As of November 30, 2003, there were no outstanding options to
purchase Common Shares.

Item 7. Major Shareholders and Related Party Transactions

A.   Major Shareholders

     Northern Offshore is controlled by World Shipholding Ltd., which owns
53,813,342, or 51.41% of the outstanding Common Shares, par value $0.25 per
share, of Northern Offshore ("Common Shares"). To our knowledge, as of March 15,
2003, no other person beneficially owns more than 5% of the outstanding Common
Shares. World Shipholding Ltd. is indirectly controlled by Greenwich Holdings,
Ltd, which is indirectly controlled by John Fredriksen, a resident of Cyprus.
World Shipholding Ltd.'s voting rights do not differ from those of Northern
Offshore's other shareholders. As of June 18, 2003 there were 9 holders of
record in the United States holding a total of 87,169 shares.

     Northern Offshore conducts all of its operations in U.S. dollars or U.K
pounds sterling, except in certain limited circumstances. We conduct our
operations in offshore locations around the world. As a result, substantially
all of our revenue is generated outside Bermuda.

B.   Related Party Transactions

     NOASA formed Northern Offshore in May 2000 as part of a series of
transactions that resulted in the separation of NOASA's business of providing
oil and gas drilling and production services from its ownership and operation of
oilfields. On May 31, 2000, NOASA transferred all its operating assets and
liabilities to Northern Offshore in exchange for 79 million Common Shares of
Northern Offshore. On September 20, 2000, NOASA spun off Northern Offshore by
distributing all those shares to the shareholders of NOASA. Northern Offshore
sold its majority ownership interests in Naftex and Petrolex back to NOASA on
September 4, 2000 for $6.4 million. On September 6, 2000, NOASA bought the
drillship Discoverer I for $12.3 million, which it then sold to Northern
Offshore on September 20, 2000 for the same price. Northern Offshore increased
its authorized capital and authorized shares on September 12, 2000 to $24
million and 96,000,000 shares, respectively, and issued 14,905,660 shares to
NOASA in final settlement of the net amounts it owed to NOASA after those two
transactions. NOASA subsequently sold those Common Shares to its shareholders.
In October 2000, NOASA changed its name to Northern Oil ASA. The Common Shares
of both Northern Offshore and NOASA are listed on the Oslo Stock Exchange.
Northern Offshore uses the ticker symbol NOF and NOASA uses the ticker symbol
NOI.

     See "Operating and Financial Review and Prospects--Liquidity and Capital
Resources" in Item 5 of this report for a discussion of a $30 million loan we
obtained from Avalon Holdings Ltd., an affiliate of Greenwich Holdings Ltd. and
World Shipholding Ltd. and a discussion of a loan guarantee provided to us by
Greenwich Holdings, Ltd.

     Effective as of January 1, 2002, we entered into an agreement with
Frontline Management (Bermuda) Ltd. ("Frontline") for administrative services.
Under the management agreement, Frontline provides management support, budgetary
and accounting support services, maintains our corporate records, ensures our
compliance with applicable laws and requirements, and assists us with corporate
finance matters. The fee payable for the year ended December 31, 2002 was USD
120,000 (2001 - nil, 2000 - nil). The Company also pays a fee to Frontline
Management (Bermuda) Ltd for administration of the Company's contract with
Texaco and for corporate reporting in the UK for the Company's subsidiary Sea
Production Ltd. The fee payable for each of the three years ended December 31,
2002 was GBP 36,000 (equivalent to USD 57,917 at December 31, 2002). Frontline
Management (Bermuda) Ltd. is a subsidiary of Frontline Ltd., a publicly listed
company that is affiliated with Greenwich Holdings Ltd.

     The Company previously leased its executive offices from a company
affiliated with Hemen Holdings. Rental for 2001 and 2000 amounted to USD 121,000
and USD 119,000, respectively. The lease contract was terminated on December 31,
2001.

     The Company pays a fee to Seatankers Management Co. Ltd to negotiate and
manage the Company's insurances. The fee payable for the year ended December 31,
2002 was USD 20,000 (2001 - nil, 2000 - nil).

     The Company also pays a fee to Seatankers Management Co. Ltd for marketing,
technical advice and the provision of Directors. The fee payable for the year
ended December 31, 2002 was USD 100,000 (2001 - USD 75,000, 2000 - USD 75,000).

     The Company previously paid a loan guarantee fee to Greenwich Holdings Ltd
amounting to 4% of the outstanding balance on a loan from Den norske Bank. This
loan was fully repaid as at December 31, 2002.

     The Company previously performed certain management and accounting duties
for Northern Oil ASA based on a management service agreement. The Company
charged a total of approximately USD 115,000 in 2001 (USD 106,000 in 2000) for
these services.

     Northern Offshore Ltd, Northern Oil ASA, Frontline Management (Bermuda) Ltd
and Seatankers Management Co. Ltd are related parties through common control.
The Company believes that the fees it pays to and receives from related parties
represent reasonable compensation for the services provided.

     We may enter into material transactions and agreements with World
Shipholding Ltd. or its affiliates in the future. However, any such transaction
or agreement would be subject to the restrictions contained in the Indenture
with respect to transactions with affiliates.

C.   Interests of Experts and Counsel

     Not applicable

Item 8. Financial Information

A.   Consolidated Statements and Other Financial Information

Financial Statements

     See "Financial Statements" in Item 18 of Part III of this report.

Legal Proceedings

Northern Offshore is not currently party to any material legal proceedings.

Dividend Policy

     Our board of directors may from time to time declare cash dividends or
distributions out of contributed surplus to be paid to the shareholders
according to their rights and interests including interim dividends as appear to
the board of directors to be justified by our financial position and within the
limitations of the Indenture and the other financial restrictions imposed by our
loan agreements. We do not expect to pay dividends for the foreseeable future.

B.   Significant Changes

     See "Information on the Company--History and Development of the Company" in
Item 3 in Part I of this report and "Operating and Financial Review and
Prospects" in Item 5 of Part I of this report.

Item 9. The Offer and Listing

     Not applicable

Item 10. Additional Information

A.   Share Capital

     Not applicable

B.   Memorandum and Articles of Incorporation

     We were registered with the Registrar of Companies in Bermuda under
Registration No. 28861. Our Memorandum of Association, which is filed as an
exhibit hereto, provides that our objects and purposes are as set forth in
paragraphs (b) through (n) and (p) through (u), inclusive, of the Second
Schedule to The Companies Act of 1981 of Bermuda.

     Our Bye-laws, which are filed as an exhibit hereto, provide that:

     (a) A director who to his knowledge is in any way, whether directly or
indirectly, interested in a contract or proposed contract, transaction or
arrangement with Northern Offshore and has complied with the provisions of the
Bermuda Companies Act of 1981 and the Bye-laws with regard to disclosure of his
interest shall be entitled to vote in respect of any contract, transaction or
arrangement in which he is so interested and if he shall do so his vote shall be
counted, and he shall be taken into account in ascertaining whether a quorum is
present.

     (b) The Board of Directors may vote compensation to themselves and any
members of their body in the absence of an independent quorum.

     (c) The Memorandum of Association and Bye-laws do not specifically address
the borrowing powers of the directors.

     (d) Northern Offshore does not have an age requirement for directors.

     (e) Directors are not required to hold any shares in Northern Offshore.

     Northern Offshore only issues one class of shares. However, Northern
Offshore may issue preference shares on terms:

     (a) that they are to be redeemed on the happening of a specified event or
on a given date; and/or

     (b) that they are liable to be redeemed at the option of Northern Offshore;
and/or

     (c) if authorized by the Memorandum of Association, that they are liable to
be redeemed at the option of the holder.

     Northern Offshore has one class of common stock outstanding. The Board of
Directors may declare such dividends to the shareholders as appear to the Board
to be justified. Any dividend or distribution unclaimed for a period of six
years from the date of declaration of such dividend or distribution will be
forfeited and will revert back to Northern Offshore. Each issued and outstanding
share is entitled to one vote. Directors stand for election at each annual
meeting. Upon a liquidation of Northern Offshore, the liquidator may divide
among the shareholders the whole or any part of the assets of Northern Offshore,
and may determine how such division shall be carried out as between the
shareholders or different classes of shareholders, if any.

     To modify the right of any class of shares, prior approval of shareholders
holding at least 50% of the total issued and outstanding shares must be
obtained. The Bermuda Companies Act of 1981 provides prior approval of the
holders of at least 75% of the issued and outstanding shares for such
modification.

     Annual general meetings are held at the time and place designated by the
Board, other than Norway, not less than once in every year. The Board may
convene a special general meeting whenever it thinks fit. A special general
meeting shall also be convened upon written request of shareholders of Northern
Offshore holding at the date of the request not less than 5% of the paid-up
voting share capital of Northern Offshore that as of such date has the right to
vote at a general meeting of Northern Offshore. A general meeting shall be
called with at least 14 full days notice in writing to be given to each
shareholder entitled to vote. No shareholder is entitled to attend any general
meeting unless notice in writing of the intention to attend and vote in person
or by proxy signed by or on behalf of the shareholder is deposited at the
registered office at least 48 hours before the time appointed for holding the
general meeting.

     No meeting may proceed unless a quorum of shareholders holding in the
aggregate at least 33 1/3% of the total number of votes entitled to be exercised
at such meeting. The meetings can be held by means of telephone, electronic or
other communication facilities. Shareholders may attend either in person or by
proxy and resolutions put to the vote of the meeting are decided on a show of
hands unless a poll is demanded. If for any reason it is impracticable to call a
meeting of Northern Offshore in any manner, or to conduct the meeting of
Northern Offshore in the manner prescribed by the Bye-laws or the Bermuda
Companies Act of 1981, a court may either on its own motion, or on the
application of any director of Northern Offshore or any shareholder of Northern
Offshore entitled to vote at general meetings of Northern Offshore, order a
meeting of Northern Offshore to be called. Such meetings shall be held at a time
and place designated by the Board or the Chairman. There is no limitation on the
right to own the securities of Northern Offshore. Northern Offshore's corporate
documents do not contain any provision that would have the effect of delaying,
deferring or preventing a change in the control of Northern Offshore and that
could operate only with respect to a merger, acquisition or corporate
restructuring involving Northern Offshore or any of its subsidiaries. No
ownership threshold above which share ownership must be disclosed is established
under Northern Offshore's Bye-laws.

C.   Material Contracts

     See "Information on the Company-Contracts, Marketing and Customers" in Item
4 of Part I of this report for a description of the Texaco Contract. See
"Information on the Company--History and Development of the Company" in Item 4
of Part I of this report for a discussion of the arrangements we entered into
with NOASA in connection with our formation.

D.   Exchange Controls

     Northern Offshore is classified by the Bermuda Monetary Authority as a
non-resident of Bermuda for exchange control purposes.

     The transfer of ordinary shares between persons regarded as resident
outside Bermuda for exchange control purposes may be effected without specific
consent under the Exchange Control Act of 1972 and regulations thereunder and
the issuance of ordinary shares to persons regarded as resident outside Bermuda
for exchange control purposes may be effected without specific consent under the
Exchange Control Act of 1972 and regulations thereunder. Issues and transfers of
ordinary shares involving any person regarded as resident in Bermuda for
exchange control purposes require specific prior approval under the Exchange
Control Act of 1972.

     The owners of ordinary shares who are ordinarily resident outside Bermuda
are not subject to any restrictions on their rights to hold or vote their
shares. Because Northern Offshore has been designated as a non-resident for
Bermuda exchange control purposes, there are no restrictions on its ability to
transfer funds in and out of Bermuda or to pay dividends or interest or make
other payments to non-resident holders of its securities, other than in respect
of local Bermuda currency.

     As an "exempted company," Northern Offshore is exempt from Bermuda laws,
which restrict the percentage of share capital that may be held by
non-Bermudians.

E.   Taxation

     Bermuda currently imposes no tax (including a tax in the nature of an
income, estate duty, inheritance, capital transfer or withholding tax) on
profits, income, capital gains or appreciations derived by, or dividends or
other distributions paid to U.S. shareholders of ordinary shares. Bermuda has
undertaken not to impose any such Bermuda taxes on U.S. shareholders of ordinary
shares prior to the year 2016 except in so far as such tax applies to persons
ordinarily resident in Bermuda.

     There is no income tax treaty between the United States and Bermuda
pertaining to the taxation of income except in the case of insurance
enterprises. There also is no estate tax treaty between the United States and
Bermuda.

F.   Dividends and Paying Agents

     Not applicable

G.   Statements by Experts

     Not applicable

H.   Documents on Display

     We file periodic reports and other information with the SEC. You may read
and copy any reports, statements or other information we file at the S.E.C.'s
public reference rooms maintained by the Commission at 450 Fifth Street, N.W.,
Room 1024, 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. 20549. In addition, documents
referred to in this report may be inspected at our registered office at
Par-la-Ville Place, 4th Floor, 14 Par-la-Ville Road, Hamilton HM 08, Bermuda.

I.   Subsidiary Information

     Not applicable

Item 11. Quantitative and Qualitative Disclosures About Market Risk

     We are exposed to market risk principally through movements in foreign
currency exchange rates and interest rates relating to our outstanding floating
rate debt. We manage these risks by way of our risk management policies and
through the use of derivative financial instruments from time to time. We only
use conventional derivative instruments such as forward contracts and interest
rate swap contracts to manage these risks. See Note 20 to our consolidated
financial statements included in Item 18 of this annual report for more
information.

     We do not enter into any derivatives for trading purposes. Counterparties
selected by us for these transactions are generally highly rated international
financial institutions.

     See Notes 14 and 18 to our consolidated financial statements included in
Item 18 of this annual report for additional disclosure on foreign currency and
interest rate risk profile and fair value of financial instruments.

Interest Rate Risk

     We have floating rate loans totalling $18.8 million and NOK 143 million
(equivalent to $20.6 million) as of the date of this report. Accordingly, a 1%
increase or decrease in interest rates would result in a corresponding increase
or decrease in our interest expense of $394,000, on an annualised after-tax
basis. We are currently not party to any interest rate swaps or any other
hedging arrangements with respect to our debt obligations. See "Operating and
Financial Review and Prospects - Liquidity and Capital Resources" in Item 5 of
Part I of this report and Note 21 of the notes to the consolidated financial
statements included in Item 18 of Part III of this report for certain
information regarding estimates of the fair value of each class of our financial
instruments.

Exchange Rate Risk

     Most of the Company's revenues, expenses and liabilities are denominated in
U.S. Dollars. In addition, production and drilling vessels are normally valued
and traded in U.S. Dollars. Therefore, the Company's functional currency is the
U.S. dollar and the Company's reporting currency is also the U.S. Dollar.

     Certain rate elements in the Company's contract with Texaco are denominated
in GBP and a majority of the expenses paid by our subsidiary Sea Production Ltd.
are denominated in GBP. We also have interest bearing NOK denominated debt
totalling NOK 143,000,000 (equivalent to $20.6 million). Certain expenses as
well as receivables and liabilities in the countries in which the vessels are
operated or laid-up will be denominated in the local currency. Therefore changes
in exchange rates may have a material impact on our cash flows or results of
operations. In broad terms, a weakening of the U.S. Dollar against the NOK, GBP
or local currency in which we pay expenses will have a negative impact on our
cash flows, results of operations and while a strengthening of the U.S. Dollar
against those currencies will have a corresponding positive impact.

     We have NOK denominated loans totalling NOK 143 million (equivalent to
$20.6 million). Accordingly a change of 1% in the exchange rate for NOK would
result in a change in our liabilities of $206,000.

     As of the date of this report we are not party to any foreign currency
swaps or any other hedging arrangements with respect to the risk of loss due to
changes in exchange rates.

Item 12. Description of Securities Other than Equity Securities

     Not applicable

                                     PART II

Item 13. Defaults, Dividend Arrearages and Delinquencies

     None. We paid interest on our 10% Senior Notes during the 30-day grace
period provided in our Indenture, and extended maturities on our other debt as
discussed in Item 5 - "Operating Review and Prospects".

Item 14. Material Modifications to the Rights of Security Holders and Use of
         Proceeds

     None.

Item 15. Controls and Procedures

Evaluation of disclosure controls and procedures.

     Within the 90 days prior to the date of this report, the Company carried
out an evaluation of the effectiveness of the design and operation of the
Company's disclosure controls and procedures pursuant to Exchange Act Rule
13a-14. Based upon that evaluation, the principal executive officers and
principal financial officers concluded that the Company's disclosure controls
and procedures are effective in alerting them to material information relating
to the Company required to be included in the Company's periodic SEC filings.

Changes in internal controls

     None.

Item 16. Reserved

Item 16A. Audit Committee Financial Expert

     We are not required to file reports with the SEC pursuant to Section 15(d)
of the Exchange Act because we have less than 300 U.S. holders of any class of
our outstanding securities. We do not presently have an audit committee. This
item is not mandatory for foreign private issuers such as Northern Offshore
until fiscal years beginning in 2005.

Item 16B. Code of Ethics

     We are not required to file reports with the SEC pursuant to Section 15(d)
of the Exchange Act because we have less than 300 U.S. holders of any class of
our outstanding securities. We do not presently have a formalised code of
ethics. This item is not mandatory for foreign private issuers such as Northern
Offshore until fiscal years beginning in 2005.

Item 16C. Principal Accountant Fees and Services

Audit Fees

     Audit fees charged during the year ended December 31, 2002 amounted to
$118,000 (2001 - $62,000).

Audit related Fees

     Not applicable

Tax Fees

     Tax fees charged during the year ended December 31, 2002 amounted to
$10,000 (2001 - $nil).

All Other Fees

     Not applicable

Item 16D. Exemptions from the Listing Rules for Audit Committees

     Not applicable

                                    PART III

Item 17. Financial Statements

     Not applicable

Item 18. Financial Statements

Index to Consolidated Financial Statements



Consolidated Financial Statements of Northern Offshore Ltd and Subsidiaries

                                                                           Page

Independent Auditors' Report                                               F-1

Independent Auditors' Report                                               F-2

Consolidated Income Statements for the years ended
    December 31, 2002, 2001 and 2000                                       F-3

Consolidated Balance Sheets as of December 31, 2002 and 2001               F-4

Consolidated Statements of Stockholders' Equity (Deficit) for
    the years December 31, 2001, 2000 and 1999                             F-5

Consolidated Statements of Cash Flows for the years ended
    December 31, 2001, 2000 and 1999                                       F-6

Notes to Consolidated Financial Statements                                 F-7


<PAGE>


Item 19.  Exhibits

1.1*  --  Memorandum of Association (Form 20-F dated May 17, 2002 (File No.
          333-8766) Exhibit 1.1)

1.2*  --  Bye-Laws of Northern Offshore Ltd. (Form 20-F dated May 17, 2002 (File
          No. 333-8766) Exhibit 1.2)

2.1*  --  Indenture dated as of May 1, 1998 among Northern Offshore ASA, the
          guarantors list on the signature pages thereto (the "Guarantors") and
          Chase Bank of Texas, National Association, as Trustee. (Form F-4 dated
          May 15, 1998 (File No. 333-8766), Exhibit 4.1)

2.2*  --  Supplement No. 1 To Indenture dated as of February 14, 2000 among
          Northern Offshore ASA, the Guarantors and Chase Bank of Texas,
          National Association, as Trustee. (Form 20-F dated May 17, 2002 (File
          No. 333-8766) Exhibit 2.2)

2.3*  --  Supplement No. 2 To Indenture dated as of September 1, 2000 among
          Northern Offshore ASA, the Guarantors and Chase Bank of Texas,
          National Association, as Trustee. (Form 20-F dated May 17, 2002 (File
          No. 333-8766) Exhibit 2.3)

4.1*  --  Contract for the Provision and Operation of a Floating Production
          Facility, dated as of March 19, 1997, by and between Texaco North Sea
          U.K. Company and Sea Production Limited, as amended. (Amendment No. 1
          to Form F-4 dated December 22, 1998 (File No. 333-8766), Exhibit
          10.15.)

4.2*  --  Reorganisation Agreement dated August 23, 2000 by and between Northern
          Offshore ASA and Northern Offshore Ltd. (Form 20-F dated May 17, 2002
          (File No. 333-8766) Exhibit 4.2)

4.3*  --  Employment Agreement with Kai Solberg-Hansen. (Form F-4 dated May 15,
          1998 (File No. 333-8766), Exhibit 10.2)

4.4*  --  Employment Agreement with Jan B. Usland. (Form F-4 dated May 15, 1998
          (File No. 333-8766), Exhibit 10.3)

4.5*  --  Employment Agreement with Rolf Arentz-Hansen. (Form F-4 dated May 15,
          1998 (File No. 333-8766), Exhibit 10.5)

8*    --  List of Subsidiaries (Form 20-F dated May 17, 2002 (File No. 333-8766)
          Exhibit 8)

99.1A --  Certification filed pursuant to Section 302 of the Sarbannes-Oxley Act
          of 2002

99.1B --  Certification filed pursuant to Section 302 of the Sarbannes-Oxley Act
          of 2002

99.2  --  [Certifications furnished pursuant to Section 906 of the
          Sarbannes-Oxley Act of 2002]**

----------

     *    Incorporated herein by reference to the filing indicated.

     **   This certification is not considered filed with the SEC pursuant to
          Exchange Act rules.


<PAGE>


                                   SIGNATURES

Pursuant to the requirements of Section 12 of the Securities Exchange Act of
1934, the registrant certifies that it meets all of the requirements for filing
on Form 20-F and has duly caused this annual report to be signed on its behalf
by the undersigned, thereunto duly authorised.

                                                        Northern OffshoreLtd.
                                                        ---------------------
                                                             (Registrant)

Date _____________________                        By    _____________________
                                                         Tor Olav Troim
                                                       Chief Executive Officer


<PAGE>


Northern Offshore Ltd.

Index to Consolidated Financial Statements

Report of Independent Accountants, June 24, 2003                F-1

Independent Auditor's Report, May 15, 2002                      F-2

Consolidated  Statements  of  Operations
      for the years ended  December 31, 2002, 2001 and 2000     F-3

Consolidated Balance Sheets as of December 31, 2002 and 2001    F-4

Consolidated  Statements  of Cash Flows for the years ended
      December  31,  2002, 2001 and 2000                        F-5

Consolidated  Statements  Changes in  Stockholders'  Equity
      for the years  ended December 31, 2002, 2001 and 2000     F-5

Notes to Consolidated Financial Statements                      F-7


<PAGE>


Report of Independent Accountants

To the Board of Directors and Shareholders

In our opinion, the accompanying consolidated balance sheet as of December 31,
2002, and the related statements of operations, changes in stockholders' deficit
and cash flows for the year then ended present fairly, in all material respects,
the financial position of Northern Offshore Ltd. and its subsidiaries at
December 31, 2002, and the results of their operations and their cash flows for
the year then ended in conformity with accounting principles generally accepted
in the United States of America. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audit. We conducted our audit
of these financial statements in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audit provides a
reasonable basis for our opinion.

The accompanying consolidated financial statements for the year ended December
31, 2002 have been prepared assuming that Northern Offshore Ltd. will continue
as a going concern. As discussed in Note 2, Northern Offshore Ltd. has a
deficiency in capital and working capital and is experiencing difficulty
generating sufficient cash flow to meet its debt obligations as they fall due,
which raises substantial doubt about its ability to continue as a going concern.
Management's plans concerning these matters are also described in Note 2. The
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.

The financial statements of Northern Offshore Limited as of December 31, 2001,
and for each of the two years in the year ended December 31, 2001, were audited
by other independent accountants. As described in Note 3, in the company has
changed its accounting principle for periodic survey and maintenance and the
financial statements as of December 31, 2001, and for each of the two years in
the year ended December 31, 2001 have been revised to include the pro forma
disclosures required by Accounting Practices Board Opinion 20. We audited these
pro forma disclosures described in Note 3. In our opinion, the pro forma
disclosures for 2001 and 2000 in Note 3 are appropriate. However, we were not
engaged to audit, review, or apply any procedures to the 2001 or 2000 financial
statements of the Company other than with respect to such disclosures and,
accordingly, we do not express an opinion or any other form of assurance on the
2001 or 2000 financial statements taken as a whole.

As discussed in note 3 to the financial statements, the Company ceased accruing
periodic survey and maintenance costs with effect from January 1, 2002.





PricewaterhouseCoopers
Hamilton, Bermuda
June 24, 2003 (except Notes 17 and 23 for which the date is July 25, 2003)


<PAGE>


Independent Auditors' Report


To the Board of Directors of
Northern Offshore Ltd.


We have audited the accompanying consolidated balance sheet of Northern Offshore
Ltd. as of December 31, 2001 and the related statements of operations,
shareholder's equity and cash flows for the years ended December 31, 2001 and
2000 prior to the inclusion of the pro forma disclosures in Note 3 to the
consolidated financial statements related to the change in accounting for
special periodic survey costs. These consolidated financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted
in the United States of America. Those standards require that we plan and
perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the financial position of Northern Offshore
Ltd. at December 31, 2001, and the results of its operations and its cash flows
for years ended December 31, 2001 and 2000 in conformity with accounting
principles generally accepted in the United States of America.

The accompanying consolidated financial statements for the year ended December
31, 2001 have been prepared assuming that Northern Offshore Ltd. will continue
as a going concern. As discussed in Note 2, Northern Offshore Ltd. has a
deficiency in capital and working capital and is experiencing difficulty
generating sufficient cash flow to meet its debt obligations due in 2002, which
raises substantial doubt about its ability to continue as a going concern.
Management's plans concerning these matters are also described in Note 2. The
consolidated financial statements do not include any adjustments that might
result from the outcome of this uncertainty.




Deloitte & Touche
Oslo, Norway
May 15, 2002


<PAGE>


Northern Offshore Ltd.
Consolidated Statements of Operations for the years ended
December 31, 2002, 2001 and 2000
(in thousands of $, except per share data)

                                                2002          2001        2000


Operating revenues                            69,299        54,027      52,419
Other revenues                                     -           120       6,104
--------------------------------------------------------------------------------
Total revenues                                69,299        54,147      58,523

Operating expenses
      Drilling,    production and lay-up      32,261        24,102      19,328
      expenses
      General and administrative expenses      3,013         4,604       2,565
      Depreciation and amortization           16,705        17,629      15,624
      Impairment losses                       21,625        31,604           -
      Other operating expenses                   896             -           -
--------------------------------------------------------------------------------
Operating profit (loss)                       (5,201)      (23,792)     21,006
Financial income (expenses)
      Interest income                             82           429         458
      Interest expense                       (18,860)      (20,394)    (22,094)
      Foreign currency exchange gain (loss)   (5,763)         (148)        268
      Gains  from early  extinguishments
      of debt                                      -         6,354      29,288
      Other financial items                    5,340           149           -
--------------------------------------------------------------------------------
      Net financial expenses                 (19,201)      (13,610)      7,920
--------------------------------------------------------------------------------
Loss before income taxes                     (24,402)      (37,402)     28,926
--------------------------------------------------------------------------------
Income taxes                                    (453)         (651)    (10,362)
--------------------------------------------------------------------------------
Loss  before  cumulative  effect of a
change  in accounting principle              (24,855)      (38,053)     18,564

Cumulative  effect of a change
in accounting principle                        6,102           682           -
--------------------------------------------------------------------------------
Net income (loss)                            (18,753)      (37,371)     18,564
================================================================================

Earnings per share:
Loss per share before  cumulative
effect of a change in accounting
principle,  basic and diluted                  (0.24)        (0.39)       0.24

Cumulative  effect of a change
in accounting principle                         0.06          0.01           -
--------------------------------------------------------------------------------
Net  income  (loss)  per  share,
basic  and diluted                             (0.18)        (0.38)       0.24
================================================================================



See accompanying Notes that are an integral part of these Consolidated Financial
Statements


<PAGE>


Northern Offshore Ltd.
Consolidated Balance Sheets as of December 31, 2002 and 2001
(in thousands of $)

                                                    2002           2001
ASSETS
Current Assets
      Cash and cash equivalents                       3,291          7,537
      Trade accounts receivable                       9,669          6,560
      Amounts due from related parties                  327            196
      Prepaid expenses and deferred charges           1,289            608
      Derivative instruments                          5,489            149
      Other current assets                              363            209
--------------------------------------------------------------------------------
      Total current assets                           20,428         15,259
Non Current Assets
      Capitalised loan fees, net                        823          1,391
      Furniture and equipment                            13            109
      Production and drilling vessels               149,071        187,368
--------------------------------------------------------------------------------
      Total non current assets                      149,907        188,868
--------------------------------------------------------------------------------
      Total assets                                  170,335        204,127
================================================================================

LIABILITIES AND STOCKHOLDERS' EQUITY (DEFICIT)
Current liabilities
      Trade accounts payable                          5,152          5,547
      Accrued expenses                                3,459          4,640
      Taxes payable                                     750            741
      Amounts due to related parties                    481              -
      Current portion of long-term debt              10,593         34,500
--------------------------------------------------------------------------------
      Total current liabilities                      20,435         45,428
Long-term liabilities
      Long-term debt                                177,046        161,872
      Accrued special periodic survey expenses            -          6,079
--------------------------------------------------------------------------------
      Total long-term liabilities                   177,046        167,951
Commitments and contingencies
Stockholders' deficit
      Share capital                                  26,170         26,170
      Additional paid-in capital                    (48,041)       (48,189)
      Accumulated other comprehensive loss           (6,986)        (7,697)
      Retained earnings                               1,711         20,464
--------------------------------------------------------------------------------
      Total stockholders' deficit                   (27,146)        (9,252)
--------------------------------------------------------------------------------
      Total liabilities and stockholders' deficit   170,335        204,127
================================================================================



See accompanying Notes that are an integral part of these Consolidated Financial
Statements


<PAGE>



Northern Offshore Ltd.
Consolidated Statements of Changes in Stockholders' Equity (Deficit)
for the years ended December 31, 2002, 2001 and 2000
(in thousands of $ except number of shares)

                                        2002          2001           2000

Number of Shares Outstanding
Balance at beginning of year            104,680,660    93,905,660   72,000,000
Effect of spin-off                                -             -    7,000,000
New shares issued                                 -     9,500,000   14,905,660
Exercise of options                               -     1,275,000            -
--------------------------------------------------------------------------------
Balance at end of year                  104,680,660   104,680,660   93,905,660
--------------------------------------------------------------------------------

Share capital
Balance at beginning of year                 26,170        23,476      102,224
Effect of spin-off                                -             -      (82,474)
New shares issued                                 -         2,375        3,726
Exercise of options                               -           319            -
--------------------------------------------------------------------------------
Balance at end of year                       26,170        26,170       23,476
--------------------------------------------------------------------------------

Additional Paid in Capital
Balance at beginning of year                (48,189)      (62,883)    (147,593)
Effect of spin-off                                -             -       82,474
New shares issued                                 -        14,424        2,236
Exercise of options                               -           270            -
Adjustment to prior year share
issue proceeds                                  148             -            -
--------------------------------------------------------------------------------
Balance at end of year                      (48,041)      (48,189)     (62,883)
--------------------------------------------------------------------------------

Accumulated Other Comprehensive Income
Balance at beginning of year                 (7,697)       (7,713)      (7,875)
Foreign currency translation effect             711            16          162
--------------------------------------------------------------------------------
Balance at end of year                       (6,986)       (7,697)      (7,713)
--------------------------------------------------------------------------------

Retained Earnings
Balance at beginning of year                 20,464        57,835       39,271
Net income/(loss)                           (18,753)      (37,371)      18,564
--------------------------------------------------------------------------------
Balance at end of year                        1,711        20,464       57,835
--------------------------------------------------------------------------------
Total Stockholders' Equity/ (Deficit)       (27,146)       (9,252)      10,715
--------------------------------------------------------------------------------

Comprehensive (Loss) / Income
Net income/(loss)                           (18,753)      (37,371)      18,564
Other comprehensive income:
Foreign currency translation effect             711            16          162
--------------------------------------------------------------------------------
Comprehensive income                        (18,042)      (37,355)      18,762
--------------------------------------------------------------------------------


See accompanying Notes that are an integral part of these Consolidated Financial
Statements


<PAGE>


Northern Offshore Ltd.
Consolidated Statements of Cash Flows for the years ended
December 31, 2002, 2001 and 2000
(in thousands of $)

                                                   2002       2001     2000

Operating activities
Net income (loss)                                  (18,753)   (37,371)   18,564
Adjustments to reconcile net income (loss) to net
cash provided by operating activities:
      Depreciation and amortisation                 16,705     17,629    15,624
      Amortization of capitalised loan fees            568        506     1,125
      Impairment loss                               21,625     31,604         -
      Assets received in lieu of cash                    -          -    (6,000)
      Gains from early extinguishments of debt           -     (6,354)  (29,288)
      Cumulative effect of a change in
      accounting principle                          (6,102)      (682)        -
      Unrealised foreign currency exchange loss      6,238        847         -
      Change in fair value of derivative
      instruments                                   (5,340)      (149)        -
      Deferred income tax charge                         -          -    10,362
Changes in operating assets and liabilities:
      (Increase)/decrease in trade accounts
      receivable                                    (3,109)     4,333     7,768
      (Decrease)/increase in trade accounts
      payable                                         (395)     3,848      (308)
      Increase in net amounts due to and from
      related parties                                  350        639       505
      Other working capital items                   (1,748)     1,386     2,297
--------------------------------------------------------------------------------
      Net cash provided by operating activities     10,039     16,236    20,649
--------------------------------------------------------------------------------
Investing activities
      Purchase and upgrading of production
      and drilling vessels                               -    (41,391)   (2,352)
      Purchases of furniture and equipment             (49)        (2)      (10)
--------------------------------------------------------------------------------
      Net cash used in investing activities            (49)   (41,393)   (2,362)
--------------------------------------------------------------------------------
Financing activities
      Proceeds from exercise of share options            -        589         -
      Proceeds from issuance of shares                   -     16,799         -
      Repurchases of notes                               -    (17,062)  (50,230)
      Proceeds from issuance of loans               10,000     38,494    30,000
      Repayment of loans                           (24,236)   (10,500)   (5,000)
--------------------------------------------------------------------------------
      Net cash (used in) provided by
      financing activities                         (14,236)    28,320   (25,230)
--------------------------------------------------------------------------------
Net (decrease) increase in cash                     (4,246)     3,163    (6,943)
Cash and cash equivalents at beginning of year       7,537      4,374    11,317
--------------------------------------------------------------------------------
Cash and cash equivalents at end of year             3,291      7,537     4,374
================================================================================

Cash paid for interest                              19,262     20,166    21,619
Cash paid for income taxes                             444        125         -
Supplemental non cash information:                       -          -     5,962
Non  cash  investing  and  financing
activity - issuance  of  shares  to
acquire production  and drilling vessels
--------------------------------------------------------------------------------


See accompanying Notes that are an integral part of these Consolidated Financial
Statements


<PAGE>


                     NORTHERN OFFSHORE LTD. AND SUBSIDIARIES
                 NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1                BACKGROUND AND BASIS OF PRESENTATION

Northern Offshore Ltd. ('The Company') is a public limited company registered in
Bermuda. The Company's shares are traded on the Oslo Stock Exchange. The Company
was founded in May 2000 and is primarily engaged in providing drilling and
production services to the offshore oil and gas industry.

Northern Offshore's largest shareholder is Osprey Maritime Ltd, which owns
approximately 51.4% of the outstanding common shares. To the Company's
knowledge, no other shareholder or group of shareholders holds 5% or more of the
Company's outstanding common shares.

Northern Offshore Ltd. is a continuation of the offshore drilling and production
business of Northern Offshore ASA ("NOASA"), a public limited company
established under the laws of the Kingdom of Norway. In May 2000, the Company
acquired all of the operating assets and liabilities of NOASA in exchange for an
issue of 79,000,000 shares. In September 2000, NOASA spun off its shares in the
Company to its shareholders. The Company concurrently sold its non-offshore
drilling and production assets back to NOASA and acquired a further drillship,
Discoverer I from NOASA. The Company settled its net liability for these
transactions by the issue of a further 14,905,660 shares to NOASA. NOASA sold
these shares to its shareholders. The net result of these transactions was for
NOASA to split its offshore drilling and production operations from its
non-offshore operations.

The above transactions represent an exchange between entities under common
control and accordingly the assets and liabilities transferred were recorded at
historical cost in a manner similar to a pooling of interests. The consolidated
financial statements include the historical results of operations transferred to
the Company by NOASA. The consolidated statements of changes in stockholders'
equity include the share capital of NOASA of 72,000,000 shares prior to the date
of the spin off transaction described above and the share capital of the Company
thereafter. The net increase of 7,000,000 issued shares is recorded as the
effect of the spin off transaction in 2000. Intercompany transactions have been
eliminated.

The Company's accounts have been prepared in accordance with accounting
principles generally accepted in the United States of America ("U.S. GAAP") and
are presented in U.S. dollars (USD) unless otherwise stated. Certain of the
comparative figures have been reclassified to conform to the presentation
adopted in the current period.

Preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions that
affect the reported amounts of (i) assets and liabilities and disclosure of
contingent assets and liabilities at the date of the balance sheet and (ii)
revenues and expenses during the reporting period. Actual results might differ
from those estimates.

NOTE 2                            GOING CONCERN

The Company had loan repayments of USD 10.6 million falling due in 2003 (USD 5.1
million in March, USD 4.5 million in June, USD 0.5 million in September and USD
0.5 million in December), USD 33.8 million falling due in 2004 and USD143.2
million falling due in 2005. These repayment maturities take account of the
effects of a refinancing, which is discussed in note 23, "Subsequent Events".

As of December 31, 2002, and as of June 23, 2003, the Company had both a
deficiency in stockholders equity and working capital and is not generating
sufficient cash flow to meet all of these obligations as they fall due.

Based on the budget and projected cash flow prepared under current conditions,
the company will be unable to meet a substantial part of its obligations falling
due in 2004 and 2005. Management hopes to find employment for one or more of its
four units, which are currently laid up. Any contribution resulting from
employment of units currently laid up will significantly improve the Company's
ability to repay its debt obligations falling due in 2004 and 2005.

If it is not possible to generate sufficient cash flow or to raise additional
capital to pay these debt obligations as they fall due then the Company will be
forced to sell assets to meet its obligations. There is no guarantee that the
Company would be able to raise sufficient capital through asset sales to meet
its debt obligations. These conditions give rise to substantial doubt as to the
ability of the Company to continue to operate as a going concern.

No adjustments have been made to these financial statements relating to the
recoverability and classification of recorded amounts for assets and liabilities
that may be necessary should the Company be unable to continue as a going
concern.

NOTE 3                        ACCOUNTING PRINCIPLES

Consolidation

Acquired companies have been accounted for using the purchase method, in which
the purchase price for the shares is allocated to the acquired company's assets
and liabilities based on their estimated fair values at the date of purchase.

All significant intercompany balances and transactions have been eliminated.

Foreign currencies

The majority of the Company's monetary assets and liabilities are denominated in
U.S. dollars. In addition, the majority of the Company's revenues and a
significant portion of operating costs are also denominated in U.S. dollars.
Therefore, in the opinion of management, the Company's functional currency is
the U.S. dollar.

Transactions denominated in foreign currencies are translated into the
functional currency at the exchange rate in effect when the transactions
occurred.

Assets and liabilities denominated in foreign currencies are translated at the
exchange rates in effect at the balance sheet date. Unrealized gains and losses
are included as financial income or expenses in the income statement.

All assets and liabilities of operations not reporting in U.S. dollars are
translated into U.S. dollars using exchange rates as of the end of each fiscal
period. Income and expense items are translated at average exchange rates
prevailing during each fiscal period. The resulting translation adjustments are
recorded as a component of other comprehensive income. Gains and losses from
foreign currency transactions are included in net income.

Capitalised loan fees

Costs associated with obtaining loans are capitalised and amortised over the
respective terms of the loans. In the case of early repayment or repurchase, the
remaining capitalised amount relating to the repaid loan is expensed and
presented net, in gains from early extinguishments of debt.

The costs of raising equity are recorded as an offset against proceeds received
and included in shareholders' equity.

Accounts receivable

Accounts receivable are included in the balance sheet at their full amount less
any allowance for expected losses.

Property and equipment

Property and equipment is reflected in the balance sheet at its historical cost
less accumulated depreciation and any write-downs. Cost of assets includes the
interest cost capitalised for assets that have been upgraded or reactivated.
Depreciation is recorded on a straight-line basis in accordance with the
estimated useful lives of the assets.

Significant investments are capitalised 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 capitalised and depreciated over
the remaining life of the asset.

Costs of property and equipment sold or retired, with the related accumulated
depreciation and write-downs, are removed from the balance sheet, and resulting
gains or losses are included in the income statement.

Property and equipment - impairment of long-lived assets

Long-lived assets and certain identifiable intangibles held and used by the
Company are required to be reviewed for impairment whenever events or a change
in circumstances indicate that the carrying amount of an asset may not be
recoverable. In performing the review for recoverability, the Company estimates
the future cash flows expected to result from the use of the asset and its
eventual disposition. If the undiscounted future cash flows are less than the
carrying amount of the asset, the asset is deemed impaired. The amount of
impairment is measured as the difference between the carrying amount and the
fair value of the asset. Long-lived assets and certain intangibles to be
disposed of are reported at the lower of their carrying amount or their fair
value less selling costs.

Property and equipment - Transfers of non-monetary assets by shareholders

Assets transferred in exchange for common shares at the time of Northern
Offshore's initial public offering of shares were recorded at the transferor's
historical cost, see Note 9 - Related party information - Transactions with
related parties, for further details regarding purchase of assets in exchange
for shares.

Revenue and expense recognition

Revenues and expenses related to contracts that extend beyond the end of an
accounting period are recognized on a straight-line basis over the contract
term.

Periodic survey and maintenance

Each of the Company's production and drilling units is subject to a special
periodic survey ("SPS"). An SPS primarily represents periodic inspection and
repairs and must be carried out to maintain the unit's certifications. Expenses
in connection with an SPS comprise periodic maintenance and repairs in addition
to inspection fees.

Prior to January 1, 2002, provisions for future special periodic surveys were
accrued on a vessel by vessel basis and charged to expense on a pro-rata basis
over the period to the next scheduled special periodic survey. Effective January
1, 2002 the Company will recognise the cost of special periodic surveys at the
time the survey takes place, i.e. it will apply the "expense as incurred"
method. The expense as incurred method is considered by management to be a more
reliable method of recognising special periodic survey costs as it eliminates
the uncertainty associated with estimating the cost and timing of future
surveys.

The cumulative effect of this change in accounting principle is shown separately
in the consolidated statement of operations for the year ended December 31, 2002
and resulted in a credit to income of USD 6.1 million in 2002. The cumulative
effect of this change as of January 1, 2002 on the Company's consolidated
balance sheet was to reduce total liabilities by USD 6.1 million.

Assuming the "expense as incurred" method had been applied retroactively, the
pro forma income and earnings per share before cumulative effect of change in
accounting principle for 2001 and 2000 would have been as follows:

                                                      2001           2000

Net income (loss) as reported                      (37,371)        18,564
Pro forma  effect of retroactive application
of change in accounting principle                    1,656          1,924
--------------------------------------------------------------------------------
Pro forma net income (loss)                        (35,715)        20,488
--------------------------------------------------------------------------------

Basic and diluted earnings per share as reported     (0.38)          0.24
Pro forma effect of retroactive application
of change in accounting principle                     0.02           0.02
--------------------------------------------------------------------------------
Pro forma basic and diluted earnings per share       (0.36)          0.26
--------------------------------------------------------------------------------

Earnings per share

Basic earnings per share ("Basic EPS") is calculated as net income or loss for
the period divided by the weighted average number of shares outstanding during
the period. Diluted earnings per share ("Diluted EPS") includes the effect of
potential common shares using the treasury stock method when dilutive.

Stock Options

The Company uses the intrinsic value method to account for options granted to
employees for the purchase of common stock. Had the Company recognized
compensation cost for its stock option plans based on the fair value at the
grant dates for options consistent with the method prescribed by FAS 123, there
would have been no impact to the Company's net income or earnings per share for
the periods presented.

Weighted-average grant-date fair value of options granted was NOK 7.65 in 2000,
based on the Black-Scholes option-pricing model and assuming a 6% risk-free
interest rate, a volatility of 77.5 %, zero dividends and expected life of 0.83
years.

Cash and cash equivalents

Cash and cash equivalents consist of cash, demand deposits and highly liquid
financial instruments purchased with original maturities of three months or
less.

Derivative instruments

Derivative instruments are recorded as assets or liabilities, measured at fair
value. Derivatives that are not hedges are adjusted to fair value through
earnings. If the derivative is a hedge, depending upon the nature of the hedge,
changes in the fair value of the derivative are either offset against the change
in fair value of assets, liabilities or firm commitments through earnings, or
recognized in other comprehensive income until the hedged item is recognised
through earnings. The ineffective portion of a derivative's change in fair value
is immediately recognised through earnings.

On January 1, 2001 the Company adopted SFAS 133, "Accounting for Derivatives and
Hedging Activities" which required that all derivative instruments be recorded
on the balance sheet at their fair value.

The cumulative effect of this change in accounting principle is shown separately
in the consolidated statement of operations for the year ended December 31, 2001
and resulted in a credit to income of USD 0.7 million in 2001. The cumulative
effect of this change as of January 1, 2001 on the Company's consolidated
balance sheet was to increase total assets by USD 0.7 million.

Financial Instruments

In determining fair value of its financial instruments, the company uses a
variety of methods and assumptions that are based on market conditions and risks
existing at each balance sheet date. For the majority of financial instruments
including most derivatives and long-term debt, standard market conventions and
techniques such as options pricing models are used to determine fair value. All
methods of assessing fair value result in a general approximation of value, and
such value may never actually be realised.

Comprehensive income

Comprehensive income is defined as the change in the Company's equity during the
year from transactions and other events and circumstances from non-owner
sources. Comprehensive income of the Company includes not only net income (loss)
but also currency translation adjustments. Such items are reported as
accumulated other comprehensive income, a separate component of shareholders'
equity.

New accounting standards

In April 2002, the FASB issued Statement of Financial Accounting Standards No.
145, ("SFAS 145"), "Rescission of FASB Statements No. 4, 44, and 64, Amendment
of FASB Statement No. 13, and Technical Corrections". This Statement rescinds
FASB Statement No. 4, Reporting Gains and Losses from Extinguishments of Debt,
and an amendment of that Statement, FASB Statement No. 64, Extinguishments of
Debt Made to Satisfy Sinking-Fund Requirements. This Statement also rescinds
FASB Statement No. 44, Accounting for Intangible Assets of Motor Carriers. This
Statement amends FASB Statement No. 13, Accounting for Leases, to eliminate an
inconsistency between the required accounting for sale-leaseback transactions
and the required accounting for certain lease modifications that have economic
effects that are similar to sale-leaseback transactions. This Statement also
amends other existing authoritative pronouncements to make various technical
corrections, clarify meanings, or describe their applicability under changed
conditions. This statement is generally for transactions occurring after May 15,
2002. The adoption of SFAS 145 caused the Company to reclassify gains on
extinguishments of debt of USD 6.4 million in 2001 and USD 29.3 million in 2000,
which had previously been reported as extraordinary items.

In December 2002, the FASB issued Interpretation No. 45, ("FIN 45"),
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others", which elaborates on the
disclosures to be made by a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued.
The initial recognition and initial measurement provisions of FIN 45 are
applicable on a prospective basis to guarantees issued or modified after
December 31, 2002, irrespective of the guarantor's fiscal year-end. The
disclosure requirements in FIN 45 are effective for financial statements of
interim or annual periods ending after December 15, 2002. Management anticipates
that the adoption of this interpretation will not have a significant impact on
the Company's consolidated financial position or results of operations.

In February 2003, the FASB issued Interpretation No. 46, ("FIN 46"),
"Consolidation of Variable Interest Entities", which addresses consolidation by
business enterprises of certain variable interest entities. FIN 46 became
effective immediately to variable interest entities created after January 31,
2003, and to variable interest entities in which an enterprise obtains an
interest after that date. It applies in the first fiscal year or interim period
beginning after June 15, 2003, to variable interest entities in which an
enterprise holds a variable interest that it acquired before February 1, 2003.
Management anticipates that the adoption of this interpretation will not have a
significant impact on the Company's consolidated financial position or results
of operations.

NOTE 4                      OTHER OPERATING EXPENSES

Other operating expenses comprise a claim against the Company for losses caused
by damaged equipment belonging to the Energy Searcher. This claim is more fully
explained in Note 17 - Legal Proceedings.

NOTE 5                           INCOME TAXES

Under current Bermuda law, the Company is not required to pay taxes in Bermuda
on either income or capital gains. Certain of the Company's subsidiaries in
other jurisdictions including Norway, Singapore and the United Kingdom are
subject to taxation in their respective jurisdictions. In some jurisdictions in
which the Company's vessels operate income is subject to withholding taxes.

Prior to the relocation, the Company was subject to taxes on its consolidated
taxable income in Norway. Certain deferred tax assets were recorded in the
Company's balance sheet as of December 31, 1999 relating to the difference
between the carrying value and the tax value under Norwegian tax rules for the
Company's offshore units. These deferred tax assets were written off when the
Company became tax resident in Bermuda in 2000.

The tax charge for the year comprises the following:

                                        2002         2001           2000

Current tax                              453          651              -
Deferred tax assets written off            -            -         10,362
--------------------------------------------------------------------------------
Total                                    453          651         10,362
--------------------------------------------------------------------------------

NOTE 6                        EARNINGS PER SHARE

The computation of Basic EPS is based on the weighted average number of shares
outstanding during the year. The computation of Diluted EPS assumes the
foregoing and the exercise of stock options using the treasury stock method.

The components of the numerators of the calculations of Basic EPS and Diluted
EPS are as follows:

                                        2002          2001           2000

Loss before cumulative effect of
a change in accounting principle     (24,855)     (38,053)         18,564
Cumulative effect of a change
in accounting principle                6,102          682               -
--------------------------------------------------------------------------------
Net income (loss)                    (18,753)     (37,371)         18,564
--------------------------------------------------------------------------------

The components of the denominator of the calculation of Basic EPS and Diluted
EPS are as follows:

                                        2002          2001           2000
Basic earnings per share:
Weighted average number of
common shares outstanding            104,681       99,293          78,218

Diluted earnings per share:
Weighted average number of
common shares outstanding            104,681       99,293          78,218
Dilutive effect of stock options           -            -             374
--------------------------------------------------------------------------------
Total                                104,681       99,293          78,592
--------------------------------------------------------------------------------

NOTE 7                     CASH AND CASH EQUIVALENTS

Cash and cash equivalents at December 31, 2001 included restricted bank deposits
of NOK 0.4 million (USD 42,000). This amount consists of employee tax
withholdings.

NOTE 8                     TRADE ACCOUNTS RECEIVABLE

Trade accounts receivable are presented net of allowances for doubtful
recoveries amounting to nil as at December 31, 2002 (December 31, 2001 - nil).

NOTE 9                      RELATED PARTY INFORMATION

Transactions with related parties

The Company leased its executive offices from a company affiliated with Hemen
Holdings. Rental for 2001 and 2000 amounted to USD 121,000 and USD 119,000,
respectively. The lease contract was terminated on December 31, 2001.

The Company pays a fee to Frontline Management (Bermuda) Ltd for administration
of the Company's contract with Chevron-Texaco and for corporate reporting in the
UK for the Company's subsidiary Sea Production Ltd. The fee payable for each of
the three years ended December 31, 2002 was GBP 36,000 (equivalent to USD 57,917
at December 31, 2002).

The Company pays a fee to Frontline Management (Bermuda) Ltd for accounting,
corporate reporting, secretarial services and cash management. The fee payable
for the year ended December 31, 2002 was USD 120,000 (2001 - nil, 2000 - nil).

The Company pays a fee to Seatankers Management Co. Ltd to negotiate and manage
the Company's insurances. The fee payable for the year ended December 31, 2002
was USD 20,000 (2001 - nil, 2000 - nil).

The Company pays a fee to Seatankers Management Co. Ltd for marketing, technical
advice and the provision of Directors. The fee payable for the year ended
December 31, 2002 was USD 100,000 (2001 - USD 75,000, 2000 - USD 75,000).

The Company paid a loan guarantee fee to Greenwich Holdings Ltd amounting to 4%
of the outstanding balance on a loan from Den norske Bank. The loan was fully
repaid as at December 31, 2002.

The Company performed certain management and accounting duties for Northern Oil
ASA based on a management service agreement. The Company charged a total of
approximately USD 115,000 in 2001 (USD 106,000 in 2000) for these services.

Northern Offshore Ltd, Northern Oil ASA, Frontline Management (Bermuda) Ltd and
Seatankers Management Co. Ltd are related parties through common control. The
Company believes that the fees it pays to and receives from related parties
represent reasonable compensation for the services provided.

NOTE 10                       OTHER CURRENT ASSETS

Other current assets comprises the following:

                                        2002           2001

Other receivables                        163            154
Other assets                             200             55
--------------------------------------------------------------------------------
Total                                    363            209
--------------------------------------------------------------------------------

NOTE 11                             SHARES IN SUBSIDIARIES

The following wholly owned subsidiaries of Northern Offshore Ltd are included in
the consolidated financial statements:

     -    Sea Production Limited, British Virgin Islands, charterer of the FPF
          Northern Producer

     -    Qualimar Shipping Company Limited, Cyprus, owner of the FPF Northern
          Producer

     -    Northern Discoverer Inc., Liberia, owner of the drillship Discoverer I

     -    Monarch Seacarriers Inc., Liberia, owner of the drillship Northern
          Explorer II

     -    Merit Maritime Limited, Liberia, owner of the drillship Northern
          Explorer III

     -    Helm Maritime Corp., Liberia, owner of the drilling rig Galaxy Driller

     -    Katzen International Corp., Liberia, investment company

     -    Splendour III Corporation, Liberia, investment company

     -    Northern Offshore Management AS, Norway, management company

     -    Jet Drilling (S) PTE Ltd., Singapore, management company

     -    Jet Shipping Limited, St Vincent and the Grenadines, charterer of the
          drillship Energy Searcher

     -    Jet Holding Limited, St Vincent and the Grenadines, owner of the
          drillship Energy Searcher

     -    Northern Offshore Leasing Ltd, Malaysia, drilling contractor


NOTE 12                            PROPERTIES AND EQUIPMENT

The Company owned the following production and drilling vessels at December 31,
2002.

                                                         Estimated     Book
                                                         useful life   Value (in
                                            Date of      at date of    thousands
Name                    Type of Unit        purchase     purchase      of USD)
--------------------------------------------------------------------------------

Northern Producer       Semi submersible
                        production platform   Dec 1997   15 years       68,736
Discover I              Drillship            Sept 2000   15 years       11,163
Northern Explorer II    Drillship             Dec 1997   12 years        7,349
Northern Explorer III   Drillship             Dec 1997   15 years       15,000
Galaxy Driller          Semi submersible
                        drilling rig          May 1998   15 years       10,000
Energy Searcher         Drillship            June 2001   15 years       36,823
--------------------------------------------------------------------------------
Total                                                                  149,071
--------------------------------------------------------------------------------

The Company also owns office furniture and equipment with a carrying value of
USD 13,000 (2001 - USD 109,000).

The following tables discloses cost and accumulated depreciation of the
Company's production and drilling vessels and furniture and equipment:

                                                     2002           2001
Production and drilling vessels:
Cost                                              279,480        279,591
Accumulated impairment losses                     (53,229)       (31,604)
Accumulated depreciation                          (77,180)       (60,619)
--------------------------------------------------------------------------------
Net book value                                    149,071        187,368
--------------------------------------------------------------------------------


Furniture and equipment:
Cost                                                  114            263
Accumulated depreciation                             (101)          (154)
--------------------------------------------------------------------------------
Net book value                                         13            109
--------------------------------------------------------------------------------

The continued difficulty in finding appropriate employment opportunities for the
Company's vessels, including its laid up vessels has led management to review
their carrying values for impairment. The review for impairment involved
comparing estimated undiscounted future cash flows to carrying values on a
vessel-by-vessel basis. Where the review indicated impairment, the vessel was
written down to its fair value. Fair value was determined within a range of two
independent broker's valuations. The fair value of vessels determined by brokers
is a subjective estimate based on the broker's assessment of the current market
for vessels of the age and type owned by the company. Due to the nature of the
market for these vessels, estimates are necessarily subject to material
variation in the short term.

In assessing whether a vessel's carrying value is impaired, the Company must
make assumptions regarding estimated future cash flows. These assumptions
include assumptions about market rates for chartering our vessels, operating
costs for our vessels, the estimated economic useful life of our vessels and the
number of days per year we can charter our vessels for. In making these
assumptions the Company refers to historical trends and performance as well as
any known future factors. Factors we consider important which could affect
future cash flows and trigger impairment include significant underperformance
relative to expected operating results, new regulations that change the
estimated useful economic life of our vessels and significant negative industry
or economic trends. Our assumptions are subject to variation in the short term,
and as such the Company's assessment as to whether a vessel is impaired is also
subject to variation in the short term and this may have a material impact on
our financial position.

As a result of the reviews discussed above, the carrying values of the Galaxy
Driller and Northern Explorer III have been written down to USD 15.0 million and
USD 10.0 million respectively. The total write-down due to impairment of USD
21.6 million is shown under the caption 'write-down of vessels' in the statement
of operations for the year ended December 31, 2002. Both affected vessels
operate in the Australasia geographical business segment.

The Energy Searcher with a carrying value of USD 36.8 million is pledged as
security for a bank loan of USD 9.0 million. The Galaxy Driller, with a carrying
value of USD 10.0 million, has been pledged as collateral for a performance bond
issued by Nordea Bank Norge ASA.

NOTE 13                         ACCRUED EXPENSES

Accrued expenses comprises the following:

                                                     2002           2001

Accrued interest                                    2,417          2,819
Accrued drilling, production and lay-up expenses      879          1,376
Accrued general and administrative expenses           163            445
--------------------------------------------------------------------------------
Total                                               3,459          4,640
--------------------------------------------------------------------------------

NOTE 14                          LONG-TERM DEBT

On May 8, 1998, the Company's predecessor company NOASA issued notes in an
aggregate principal amount of USD 340 million, bearing interest of 10% per annum
(the "Notes"). Northern Offshore succeeded to NOASA's obligations under the
Notes issue when it acquired all of NOASA's operating assets and liabilities in
May 2000 (see Note 1). The Notes, which have no sinking fund provisions, are
scheduled to mature on May 15, 2005. The use of the proceeds from the issuance
of the Notes included repayment of outstanding borrowings under a bank credit
facility of USD 145 million, purchase of the Galaxy Driller at a cost of USD 50
million, fees and expenses of approximately USD 10 million, increased working
capital of approximately USD 10 million and repayment of approximately USD 125
million to the Company's shareholders. Fees and expenses related to the issuance
of the Notes have been capitalised and are being amortised over the seven-year
period to maturity.

Between 1998 and 2001, the Company and its predecessor company NOASA repurchased
Notes in an aggregate principal amount of USD 196.8 million, resulting in a net
outstanding amount at December 31, 2002 and 2001 of USD 143.2 million.

The repurchases of the Notes took place at an average price of 58%. Total gains
on repurchases of debt of USD 83.3 million have been recorded in the income
statements for the years ended December 31, 1998 - 2001 of which USD 6.4 million
and USD 29.3 million were recorded as gains in 2001 and 2000 respectively.

The Notes are unsecured, but the indenture pursuant to which the Notes were
issued restricts the ability of the Company to use its assets as collateral,
except for the mortgages over the Galaxy Driller and Energy Searcher - see Note
9. Certain of the Company's subsidiaries have fully and unconditionally
guaranteed the Company's obligations under the Notes.

The following table presents condensed consolidating financial information
relating to the guarantors and non-guarantors of the Notes as at and for the
year ended December 31, 2002.

<TABLE>

                                Parent   Guarantor    Non-guarantor  Consolidating
                                company  subsidiaries subsidiaries   adjustments      Total
                                -------  ------------ ------------   -----------      -----
<S>                             <C>      <C>          <C>            <C>              <C>
Current assets                    5,573        9,763         5,092             -        20,428
Investments  in subsidiaries    305,773            -             -      (305,773)            -
Production  and  drilling
vessels                               -      112,248        36,823             -       149,071
Other non-current assets              -       64,385            13       (63,562)          836
----------------------------------------------------------------------------------------------
Total assets                    311,346      186,396        41,928      (369,335)      170,335
----------------------------------------------------------------------------------------------
Current liabilities              27,002       15,994        11,256             -        54,252
Long-term debt                  312,664            -             -      (169,435)      143,229
Other long-term liabilities           -      183,414         8,544      (191,958)            -
Stockholders' equity           (28,320)     (13,012)        22,128        (7,942)      (27,146)
----------------------------------------------------------------------------------------------
Total liabilities and
stockholders' deficit           311,346      186,396        41,928      (369,335)      170,335
----------------------------------------------------------------------------------------------

Revenues                              -       46,796        23,463          (960)       69,299
Operating expenses               (1,163)     (91,344)      (16,840)       34,847       (74,500)
Net loss from subsidiaries       (1,850)           -             -         1,850             -
Net financial expenses          (16,914)      (1,272)       (1,015)            -       (19,201)
Taxes                                 -         (442)          (11)            -          (453)
Cumulative  effect  of  a
change in accounting principle        -        5,982           120             -         6,102
----------------------------------------------------------------------------------------------
Net loss                        (19,927)     (40,280)         5,717       35,737       (18,753)
----------------------------------------------------------------------------------------------
</TABLE>


<PAGE>


The following table presents condensed consolidating financial information
relating to the guarantors and non-guarantors of the Notes as at and for the
year ended December 31, 2001.
<TABLE>

                                Parent   Guarantor    Non-guarantor  Consolidating
                                company  subsidiaries subsidiaries   adjustments        Total
                                -------  ------------ ------------   -----------        -----
<S>                             <C>      <C>          <C>            <C>               <C>
Current assets                      149       12,045         3,380          (315)       15,259
Investments  in subsidiaries    324,661            -             -      (324,661)            -
Production  and  drilling
vessels                               -      147,371        39,997             -       187,368
Other non-current assets              -       98,459            57       (97,016)        1,500
----------------------------------------------------------------------------------------------
Total assets                    324,810      257,875        43,434      (421,992)      204,127
----------------------------------------------------------------------------------------------
Current liabilities               2,755       22,680        20,308          (315)       45,428
Long-term debt                  331,307            -             -      (169,435)      161,872
Other long-term liabilities           -      218,815        23,984      (236,720)        6,079
Stockholders' equity            (9,252)       16,380          (858)      (15,522)       (9,252)
----------------------------------------------------------------------------------------------
Total liabilities and
stockholders' deficit           324,810      257,875        43,434      (421,992)      204,127
----------------------------------------------------------------------------------------------

Revenues                          1,331       48,595         7,234        (3,013)       54,147
Operating expenses               (2,616)     (88,109)       (7,170)       19,956       (77,939)
Net loss from subsidiaries      (29,694)            -            -        29,694            -
Net financial expenses           (6,392)      (6,475)         (743)            -       (13,610)
Taxes                                 -        (651)             -             -          (651)
Cumulative effect of a
change in accounting principle        -          682             -             -          682
----------------------------------------------------------------------------------------------
Net loss                        (37,371)     (45,958)         (679)       46,637       (37,371)
----------------------------------------------------------------------------------------------
</TABLE>


Prior to 2001 all subsidiaries of Northern Offshore Ltd were guarantors of the
Notes.

To finance part of the repurchases of Notes made in year 2000, a USD 30 million
loan was obtained on April 15, 2000 from Avalon Holdings Ltd, an affiliate of
Hemen Holdings. The outstanding balance of this loan at December 31, 2002
amounts to USD 11.3 million (2001 - USD 16.0 million). The interest rate is USD
LIBOR plus a margin of 6.5% (8.36% as of December 31, 2002). The balance is
repayable in installments with the last installment of USD 3.3 million due in
June 2004. This loan is collateralized by repurchased Notes with par value USD
166.3 million.

The Company incurred loans totaling USD 20 million to partly finance the
acquisition of the vessel Energy Searcher in June 2001. At December 31, 2002 the
outstanding loan amounted to USD 9.0 million. The balance is repayable in
installments with the last installment of USD 5.5 million due in June 2004. This
loan bears interest at LIBOR plus a margin of 2.0% and is collateralized by a
mortgage over the Energy Searcher.

The Company also incurred further loans to provide working capital and fund
further acquisitions of the Company's Notes. These loans amount to NOK 168
million (equivalent to USD 24.1 million) and are all outstanding at December 31,
2002. These loans bear interest at NIBOR plus margins of between 3.5% and 4.5%.
One loan in the amount of NOK 25.0 million (equivalent to USD 3.6 million) which
was collateralized by repurchased Notes with par value USD 11.6 million was
fully repaid in April 2003. The remaining loan in the amount of NOK 143.0
million (equivalent to USD 20.6 million) is repayable in April 2004.

The outstanding debt as of December 31, 2002 is repayable as follows (in
thousands of USD):

2003                                                               10,593
2004                                                               33,817
2005                                                              143,229
--------------------------------------------------------------------------------
Total                                                             187,639
--------------------------------------------------------------------------------

NOTE 15                       STOCKHOLDERS' EQUITY

Northern Offshore's authorised share capital is USD 36,000,000, divided into
144,000,000 common shares with a par value of USD 0.25 per share. There are
104,680,660 common shares issued and outstanding, representing a share capital
of USD 26,170,165.

Northern Offshore's Board of Directors is authorized to cancel of the unissued
shares in accordance with the byelaws.

As part of the initial share issuance by the Company's predecessor, Northern
Offshore ASA, 30,000,000 shares were issued to Hemen Holdings. The issuance was
in consideration, in lieu of cash, as partial payment of the purchase price for
the Northern Producer, the Northern Explorer II and the Northern Explorer III,
which were acquired from Hemen Holdings at an aggregate price of USD 386
million. Hemen Holdings is a related party through common control.

In 2000, the Company purchased all the assets, and assumed all the liabilities
and commitments of its former parent company, Northern Offshore ASA. As
consideration for this transaction, the Company issued 79,000,000 common shares
to Northern Offshore ASA. Subsequent to that transaction, Northern Offshore ASA
distributed all it's shares in Northern Offshore Ltd. to it's own shareholders.

Subsequent to the above transactions, the Company acquired the drillship
Discoverer I from Northern Offshore ASA, and sold its non-offshore drilling and
production services assets and operations to Northern Offshore ASA. As
consideration for the net payment due, the Company issued 14,905,660 common
shares to Northern Offshore ASA. All of these shares were offered for sale to
Northern Offshore ASA's shareholders. Northern Offshore ASA was later
subsequently renamed Northern Oil ASA.

The Company issued 9,500,000 shares in the year 2001 to partly finance the
acquisition of the vessel Energy Searcher. These shares were issued to
institutional investors at an average price of USD 1.77 per share.

The Company issued 1,275,000 shares in the year 2001 upon exercise of options
held under the Company's stock option program. These shares were issued at an
average price of NOK 3.86 per share (equivalent to USD 0.46 per share). At
December 31, 2002 there are no options outstanding (2001 - nil, 2000 -
1,275,000). No options have been issued since December 31, 2002.

The following gives information in respect of issued options in accordance with
SFAS 123:

Number of shares                          2002           2001          2000

At beginning of the year                     -      1,275,000     1,025,000
Granted                                      -              -       250,000
Exercised                                    -      1,275,000             -
Forfeited                                    -              -             -
--------------------------------------------------------------------------------
At end of the year                           -              -     1,275,000
--------------------------------------------------------------------------------

Exercisable at end of the year               -              -       956,250



Weighted average exercise price (in NOK)  2002           2001          2000

At beginning of the year                     -           3.72          7.32
Granted                                      -              -         13.00
Exercised                                    -           3.86             -
Forfeited                                    -              -             -
--------------------------------------------------------------------------------
At end of the year                           -              -          3.72
--------------------------------------------------------------------------------

Weighted-average grant-date fair value of options granted was NOK 7.65 in 2000,
based on the Black-Scholes option-pricing model and assuming a 6% risk-free
interest rate, a volatility of 77.5 %, zero dividends and expected life of 0.83
years.

NOTE 16                   COMMITMENTS AND CONTINGENCIES

The Company is committed to provide offshore production services utilising the
Northern Producer under a contract with Chevron-Texaco ending in January 2005.
Texaco has options to extend the contract for up to an additional three years.

The Company has entered into a management agreement with PGS Production Services
("PGS") to provide the operational and technical management of Northern
Producer. PGS is entitled to a management fee of up to approximately USD 0.5
million per year. In addition, PGS is entitled to a performance incentive,
provided certain production levels have been met.

The Galaxy Driller has been mortgaged as collateral for the performance bond
provided by Nordea Bank - see Note 12 and 14.

The Energy Searcher has been mortgaged to Banque Nationale Paribas as security
for a loan - see Notes 9 and 12.

The Company insures the legal liability risks for its drilling and production
activities with a mutual protection and indemnity association. As a member of a
mutual association, the Company is subject to calls payable to the association
based on the Company's claims record in addition to the claims records of all
other members of the association. A contingent liability exists to the extent
that the claims records of the members of the association in the aggregate show
significant deterioration, which may result in additional calls on the members.

Offshore drilling and production activities involve some risk of pollution.
Under drilling and production contracts, the risk of pollution from the field is
normally borne by the oil company, while the risk of pollution from the vessel
(or other pollution not originating from the field) is borne by the contractor.
The Company has insurance which management believes adequately covers these
risks.

NOTE 17                        LEGAL PROCEEDINGS

One of the Company's customers, INPEX, raised a claim against the Company for
losses caused by damaged equipment belonging to the Energy Searcher. In order to
secure their claim, INPEX withheld USD 2.1million of charter payments due to the
Company. The claim was settled for USD 0.9million on July 25, 2003 and INPEX
have remitted USD 1.2 million, being the amount of charter payments originally
withheld less the agreed settlement of USD 0.9 million. The agreed settlement
amount has been recorded as a charge against earnings for the year ended
December 31, 2002. The amount of INPEX's claim is recorded as an other operating
expense in the income statement.

NOTE 18                        FOREIGN EXCHANGE RISK

Most of the Company's revenues, expenses and liabilities are in USD. In
addition, production and drilling vessels are normally valued and traded in USD.
Certain rate elements in the Company's contract with Texaco are denominated in
GBP. Certain expenses as well as receivables and liabilities in the countries in
which the vessels are operated or laid-up will be denominated in the local
currency.

The Company has entered into loan currency swaps to swap certain NOK denominated
loans into USD - see note 20.

Beyond this, the Company has not hedged against the risk of loss due to changes
in exchange rates.

NOTE 19             BUSINESS AND CREDIT RISK CONCENTRATIONS

The Company markets its services to the offshore oil and gas industry, and its
customers consist primarily of major integrated international oil companies and
independent oil and gas producers. Accordingly, the Company believes it is not
exposed to any significant risk of credit loss.

At December 31, 2002, the Company had cash deposits concentrated primarily in
one major Norwegian bank. The Company believes that the credit risk for those
deposits is not material.

As a result of its relatively small fleet of drilling and production units, the
Company's revenues at any time are primarily dependent on contracts with a
limited number of customers, and its results of operations may fluctuate
depending on the termination of any of its contracts and its ability to obtain
additional contracts for its drilling and production units. In the year ended
December 31, 2002, the Company was dependent on Chevron-Texaco for approximately
68% of its operating revenues.

NOTE 20                      DERIVATIVE INSTRUMENTS

In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement
of Financial Accounting Standards No. 133 ("SFAS 133"), "Accounting for
Derivative Instruments and Hedging Activities", which established new standards
for recording derivatives in interim and annual financial statements. SFAS 133,
as amended by Statements of Financial Accounting Standards No. 137 and No. 138,
is effective for fiscal years beginning after June 15, 2000.

The Company adopted SFAS 133 on January 1, 2001. The Company recognised the fair
value of its derivatives as assets of USD 682,000 on its consolidated balance
sheet as of January 1, 2001. These amounts were recorded as a cumulative effect
of an accounting change as an adjustment to income.

The Company does not use derivative instruments for speculative purposes.

The Company has entered into foreign currency and interest rate swaps whereby
the Company will receive NOK 163 million and pay USD 17.9 million at maturity in
April 2003. Under these swaps the Company receives variable interest in NOK
based on NIBOR plus margins of between 3.5% and 4.5% and pays interest in USD
based on fixed rates between 8.81% and 11.50%.

These swaps have been entered into in order to provide an economic hedge of the
Company's NOK denominated loans (NOK 168 million), but are not designated as
hedges for accounting purposes.

The Company uses forward exchange contracts from time to time in order to offset
the effect of exchange rate fluctuations on forecasted transactions and firm
commitments.

NOTE 21                       FINANCIAL INSTRUMENTS

The following methods and assumptions were used to estimate the fair value of
each class of financial instruments for which it is practicable to estimate that
fair value:

Cash and cash equivalents

The carrying amount approximates fair value because of the short maturity of
those instruments.

Long-term debt

The Company's long-term debt as of December 31, 2002 and 2001 consisted of a net
outstanding of USD 143.2 million aggregate principal amount of Notes, in
addition to USD denominated loans of USD 20.3 million (2001 - USD 34.5 million)
and NOK denominated loans of NOK 168 million (2001 - NOK 168million),
(equivalent to USD 24.1 million) of which NOK 163 million has been swapped with
USD denominated loans of USD 17.9 million.

The fair value of the Company's 10% Notes payable is determined from open market
valuations.

Derivative instruments

The fair value of the Company's derivative instruments is the estimated amount
that the Company would receive or pay to terminate the agreements at the
reporting date.

The estimated fair values of the Company's financial instruments are as follows:

                                             December 31,
                                         2002                 2001

                               Carrying    Fair      Carrying      Fair
                               amount      Value     amount        Value

Cash and cash equivalents         3,291      3,291      7,537       7,537
Long-term debt (10% Notes)     (143,229)   (54,427)  (143,229)    (83,073)
Long-term debt (Other)          (44,410)   (44,410)   (53,143)    (53,143)
Derivative instruments            5,489      5,489        149         149

NOTE 22            INDUSTRY AND GEOGRAPHIC SEGMENT INFORMATION

From inception through December 31, 2002, the Company has been engaged in a
single business segment: providing drilling and production services to the
offshore oil industry.

In the following table disclosing geographic segment information, revenues are
allocated based on the location of each production and drilling vessel at the
time the revenue was earned and long-lived assets are allocated based on the
location of each asset at the year-end:

<TABLE>

                                                                           Other
                         United                                            foreign
                         Kingdom  Indonesia   Vietnam   Mexico  Singapore  countries  Total
                         -------  ---------   -------   ------  ---------  ---------  -----
<S>                      <C>      <C>         <C>       <C>     <C>        <C>        <C>
At and for  the  year
ended   December  31,
2000:
Revenues                 52,418        -          -          -       -     6,105       58,523
Long-lived assets        82,452        -          -     12,955  99,803       106      195,316

At and for  the  year
ended   December  31,
2001:
Revenues                 45,867    2,589      1,317          -     927     3,447       54,147
Long-lived assets        75,667        -          -     12,052  99,649       109      187,477

At and for  the  year
ended   December  31,
2002:
Revenues                 46,796   19,910      2,593          -       -         -       69,299
Long-lived assets        68,736        -          -     11,163  69,185         -      149,084
</TABLE>


During the year ended December 31, 2000, Chevron-Texaco accounted for 90% (USD
52.4 million) of the Company's consolidated net revenues. The remaining 10% (USD
6.1 million) of consolidated net revenues relates to income recognized in
connection with the settlement of a legal dispute.

During the year ended December 31, 2001, Chevron-Texaco accounted for 85% (USD
45.9 million) of the Company's consolidated net revenues. The remaining USD 15%
(USD 8.2 million) relates to various contracts performed by the Energy Searcher
since acquisition in June 2001.

During the year ended December 31, 2002, Chevron-Texaco accounted for 68% (USD
46.8 million) of the Company's consolidated net revenues. The remaining USD 32%
(USD 22.5 million) relates to various contracts performed by the Energy
Searcher.

NOTE 23                        SUBSEQUENT EVENTS

On April 1, 2003, the holders of the Company's NOK denominated loan in the
amount of NOK 143 million (equivalent to USD 20.6 million) voted to extend the
maturity of the loan from April, 2003 to October, 2004 subject to the following
terms and conditions:

     o    The loan is repaid on October 6, 2004 at 102.5% of face value

     o    The interest rate of the loan is increased from NIBOR plus a margin of
          4.5% to NIBOR plus a margin of 5.5%

     o    A non-recurring loan extension fee equivalent to 2.5% of the
          outstanding loan will be paid to the loan holders on April 24, 2003

     o    The extension of the loans from Avalon Holdings Ltd and Banque
          Nationale Paribas referred to below.

The secured loan provided by Banque Nationale Paribas with a principal amount of
USD 9.0 million has been extended with revised repayment maturities. The final
installment of USD 5.5 million will be due in June 2004.

The secured loan provided by Avalon Holdings Ltd. With a principal amount of USD
11.3 million has been extended with revised repayment maturities. The final
installment of USD 3.3 million will be due in June 2004.

On July 25, 2003 a claim against the Company for losses suffered by INPEX was
settled for an agreed amount of USD 0.9 million (see Note 17 - "Legal
Proceedings").


02936.0001 #474134