Final Results

RNS Number:0849J
Melrose Resources PLC
24 March 2003

FOR IMMEDIATE RELEASE

                                                                   24 March 2003

                             Melrose Resources plc

    Preliminary Announcement of Results for the year ended 31 December 2002

Melrose Resources plc, the oil and gas exploration and production company with
interests in Bulgaria, Egypt and USA, today announces its preliminary results
for the year ended 31 December 2002:

HIGHLIGHTS

Significant developments

*    Significant exploration success on El Mansoura Concession;

*    First production from South Bilqas development;

*    Galata development finance contracts signed and development underway;

*    Disposal of Wyoming Ethanol;

Financial summary

*    Turnover of #7.1 million (2001 - #14.2 million);

*    EBITDA of #0.5 million (2001 - #3.4 million);

*    Loss on ordinary activities after taxation of #2,232,000 (2001 - #415,000 
     profit);

*    Rights Issue to raise up to #14 million to reduce borrowings
     and provide additional working capital;

*    Pro-forma net asset value per share of #2.88 (2001 - #2.56).


Commenting on this, Robert Adair, Chairman, said:

"During the last year we have made significant progress both in Bulgaria and in
Egypt. Commencement of development of the Galata Gas Field is a major step
forward which will transform the Group's earnings profile from 2004 onwards and,
in Egypt, we have now established two significant exploration plays which should
start to contribute significantly to earnings this year.  The South Batra
discovery is particularly exciting and of great significance.  The current share
price represents a very substantial discount to the appraised net asset value of
the Company and, in my view, does not yet reflect any of the upside value from
these discoveries in Egypt. I am looking to the future with great confidence and
excitement."

For further information please contact

Melrose Resources plc
Robert Adair, Chairman                                         0131 225 6678
David Curry, Chief Executive                                   0131 225 6678
Chris Thomas, Corporate Development Director                   0207 462 1600

Binns & Co PR Limited
Judith Parry/Sophie Morton                                     0113 242 1171


CHAIRMAN'S STATEMENT 

Over the last 18 months we have achieved some major milestones in our objective
to firmly establish Melrose as an exploration and production company and the
future for the Group looks very exciting.

Egypt

We now have two successful exploration plays on the El Mansoura Concession.
The South Bilqas Field discovery well was drilled and tested in January 2002 and
was brought onto production in December 2002 at a rate of 12 MMcfpd.  This is
the first production from the El Mansoura Concession and established the
multi-prospect shallow Pliocene "bright spot" play.  The prospects that have
been identified are individually relatively small in the context of the Nile
Delta, but they can be developed and brought onto production quickly and for a
relatively low cost.  The South Mansoura No. 1 well was drilled in March 2003
and encountered a good pay zone in the Kafr El Sheikh, Pliocene formation, which
confirms our interpretation of this type of seismic anomaly.  Total gross
reserves from these two discoveries are estimated to be 60 Bcf.  Another 22
Pliocene prospects with significant cumulative reserve potential are now being
re-evaluated.

Perhaps even more importantly, the success of the South Batra No.1 well which
was drilled in January 2003 has now established that the prolific Abu Madi
channel sand extends into the El Mansoura Concession.  The well encountered
approximately 75 ft (net) of good quality reservoir in Level III of the Abu Madi
formation and confirmed the presence of gas and condensate.  The Level III
reservoir section has been tested and flowed at rates of up to 31.2 MMcfpd and
560 bcpd.  Approximately 110 ft (gross) of poorer gas-bearing reservoir was also
logged in Level II of the Abu Madi but this was not tested as reservoir quality
is believed to be better developed at other locations on the structure.

Well data from this discovery is now being re-integrated into the prospect
evaluation in order to establish a more precise reserve volume, but further
drilling will be required to better evaluate the full upside potential of this
accumulation. Initial estimates indicated potential of 215 Bcf GIIP, but the
Level II and Level III sands have now been mapped over much larger areas. If
further drilling confirms these areas, GIIP in the two zones combined could
exceed 600 Bcf. The South Mansoura No.1 well, currently drilling, is now being
deepened to test this formation.  A number of prospects within the Abu Madi
channel system, offsetting South Batra and elsewhere on the concession, are also
being re-evaluated.

In Qantara, we have a much better understanding of the deep Tineh and Qantara
sands following recent work and the Qantara No.7 well should be drilled this
year. This well will also test the new mid-Pliocene play established
successfully on the El Mansoura Concession.

Bulgaria

In November 2001 we entered into a gas sales contract for the Galata Gas Field
and, in November 2002, the final hurdle in the commercialisation of this
discovery was cleared when we secured project financing of $54 million for the
development of the field and for transportation infrastructure.  Development of
the field is now underway and many of the major procurement and construction
contracts have been awarded.  First gas production is scheduled for January
2004.  Bringing this field onto production will transform the Group as we have a
100% working interest in this field and average daily production is expected to
be in excess of 40 MMcfpd.

Our exploration efforts on Exploration Block 91-III to identify additional gas
reserves to produce through the Galata facilities are ongoing.  The Bogdanov
North exploration well drilled in January 2003 encountered a thicker reservoir
section than that encountered in the Galata Gas Field, but there were no gas
shows and the well was plugged and abandoned.  There is clear evidence of an
active hydrocarbon system in this area of the Black Sea and the remaining Galata
"look-a-like" prospects are now being re-evaluated in the light of the thicker
than expected reservoir encountered.   In the northern area of the Block, seven
shallow prospects have been identified on seismic with up to four zones on each
structure and these are being evaluated.

On Exploration Block Kaliakra 99 a number of promising structures have been
identified and the acquisition of additional seismic data is currently being
considered.

USA

Development activity in the USA during 2002 was restricted to workovers, with
the emphasis on improving field operations and reducing operating costs.  No new
wells were drilled during the year, but the workover programme generated
incremental reserves at a low replacement cost and operating costs also reduced
by 10% compared to 2001.  A further drilling programme is being scheduled for
2003.  The non-core ethanol production and distribution business was disposed of
during the year for a deferred consideration of $3.625 million.

Rights Issue

With funding for the Galata project secured, in January 2003 we announced a
discounted rights issue at 50 pence per share to raise up to #14 million.  My
family trusts agreed to take up their entitlement of approximately #9.3 million
and, as at 21 March 2003, a further #2.0 million of rights had been taken up by
other shareholders.

Outlook for 2003 and beyond

I am looking to the future with great confidence and excitement.

Development of the Galata Gas Field is a major step forward for the Company and
it will transform the Group's earnings profile from 2004 onwards.  Surplus cash
flow generated from this project will be available to continue to develop the
Group's other core assets.  We expect that the South Batra No.1 and South
Mansoura No.1 wells can be brought onto production during 2003 and our efforts
in Egypt will concentrate on these established Pliocene and Abu Madi plays.  As
indicated in the Rights Issue document we hope to commence payment of dividends
in 2005 based on the results for the 2004 financial year.

The current share price represents a very substantial discount to the appraised
net asset value of the Company and, in my view, does not reflect any of the
upside value from exploration potential, especially the two significant
exploration plays recently established in Egypt.  Once the rights issue has
closed, I would hope that the increase in underlying asset value and our further
upside potential will start to be reflected in the share price, but in the
meantime we will continue with our efforts to enhance shareholder value.


R F M Adair
Chairman
24 March 2003


REVIEW OF OPERATIONS

Egypt

The Group's interests in Egypt are located onshore in the Nile Delta area, which
is emerging as a highly productive and prospective hydrocarbon province.

El Mansoura Concession

The exploration focus on this concession has been on the multi-prospect shallow
Pliocene play and the extension of the late-Miocene, Abu Madi channel sand
system from the north.  Significant progress has been made on both fronts over
the last 12 months.

South Bilqas Field development  The South Bilqas Field was discovered in January
2002 by the El Mansoura No.3 exploration well which was drilled to test a
Pliocene seismic "bright spot".  The well reached a total depth of 6,497 ft and
encountered 37 ft of good quality reservoir sand in the Kafr El Sheikh
formation.  The well was successfully tested and flowed dry gas at a rate of
22.8 MMcfpd on a 48/64ths fixed choke with a surface flowing pressure of 1,580
psi. A Development Lease was approved by EGPC in October 2002 and production
commenced in December 2002 at a rate of approximately 12 MMcfpd. The gas is
transported to a valve station on the nearby national trunk line by a newly
constructed 22 inch, 2.5 km pipeline.  The Field is currently producing at a
rate of 11.3 MMcfpd (2.7 MMcfpd net to Melrose). The structure will be depleted
by the El Mansoura No.3 well and no further appraisal drilling will be
necessary. .

Pliocene prospectivity  The South Bilqas Field has confirmed the existence and
commerciality of the Pliocene "bright spot" play on this concession and seismic
reprocessing, in association with the calibration of the seismic interpretation
following the drilling of the North Talkha No.1 and Dikirnis No.1 wells in 2002,
has further enhanced the understanding of this play.

The North Talkha No.1 well, which encountered significant gas shows, was drilled
on a saddle between two structural highs and it is believed that these highs may
be separate gas accumulations. There is also a deeper structure at 7,000 ft
analogous to the South Bilqas discovery, which could not be tested by the
shallow drilling unit being used. The well has been suspended pending further
operations in the future. The Dikirnis No.1 well, which was drilled to define
the hydrocarbon potential of a strong seismic anomaly within the Pliocene Kafr
El Sheikh/El Wastani sequence, was plugged and abandoned as a dry hole. Analysis
of the results of these two wells combined with the El Mansoura No.3 discovery
well has provided the means to distinguish between gas-generated seismic
anomalies and anomalies due to lithology and a complete re-interpretation of the
Pliocene prospect inventory is being undertaken.

The Pliocene play enjoys a high success rate in the basin, especially the deeper
Kafr El Sheikh, with prospect reserve estimates similar to those of the South
Bilqas Field.  In addition to the South Bilqas discovery, nine El Wastani and
five Kafr El Sheikh prospects have been mapped in the early-Pliocene within the
concession and further geophysical evaluation is ongoing. Two prospects, the
South Mansoura No.1 and the Mansouriya No.1 have been identified to the south of
the South Bilqas Field.  The South Mansoura No.1 well, located 10 km south of
the South Bilqas discovery, spudded in February 2003 and has encountered a Kafr
El Sheikh section.  Wire-line logs indicate a gross mid-Pliocene reservoir
interval of over 200 ft with 31 ft of excellent quality reservoir. The remaining
section, comprising interbedded sands and shales is also expected to contribute
to reserves and production. Most recent estimates indicate most likely reserves
of 45 Bcfe gross.  As many of these Pliocene prospects are located close to the
main national gas trunk line, a low cost development plan can be employed to
achieve early production.

Two early-Pliocene prospects have been identified on the eastern part of the
concession as a result of a "missed pay" evaluation on the old electric logs.
The "K" prospect is penetrated by the Tarif-2A well drilled by Conoco in 1982 to
investigate a deeper Tineh objective. The electric logs show two 50 ft gas
bearing sand intervals in the Pliocene at around 2,800 ft and 3,050 ft depths.
The "L" prospect (now named Mit Hadid) is penetrated by the East Delta-4 well.
In this case the logs show a 23 ft gas sand interval in the Pliocene at 3,380 ft
depth. The Abu Monkar and Sherbean discoveries in the El Manzala Concession to
the east, where reserves of 110 Bcf have been proven, further enhance the
prospectivity of the Pliocene "bright spot" play on the eastern side of the El
Mansoura Concession.

South Batra discovery  The South Batra No.1 well was drilled in January 2003 to
test a prospect in the late-Miocene, Abu Madi formation offsetting a recent
discovery by Petrobel in the adjoining East Delta concession. The South Batra
No.1 well reached a TD of 10,300 ft and wireline logs indicated 151 ft gross (74
ft net) of good quality reservoir in Level III of the Abu Madi formation and
confirmed the presence of gas and condensate.  The Level III reservoir section
has been tested and flowed at three test rates from 17.8 to 31.2 MMcfpd and up
to 560 bcpd (separator restricted).

Approximately 110 ft (gross) of gas-bearing reservoir was also logged in Level
II of the Abu Madi but it was decided not to test Level II in this well, as the
better quality reservoir section is believed to be much thicker at other
locations on the structure.  The logs indicated up to 10 ft gross of clean
sandstone reservoir at the bottom of this interval and an upper shaly section
which is similar to the laminated shale/sand reservoir sections which produce in
the offshore Nile Delta fields.

Well data is being re-integrated into the prospect evaluation in order to
establish a more precise reserve volume and also to evaluate further a number of
offsetting prospects within the Abu Madi channel system.  Further drilling will
be required to better evaluate the full upside potential of the South Batra gas
and condensate accumulation. Initial estimates indicated potential reserves of
150 Bcf gross (215 Bcf GIIP) with considerable upside potential which is
currently being evaluated.  The Level III sand has now been mapped over 20 sq
km. and the Level II sand mapped over 40 sq km. If further drilling confirms the
extent of these reservoirs, GIIP in the two zones combined could exceed 600 Bcf.

An application has been made to EGAS to convert an area surrounding the South
Batra discovery into a Production Lease and negotiations are currently in
progress.

Late-Miocene, Abu Madi  prospectivity  The Abu Madi channel sand reservoir is a
regionally acknowledged play, established by the larger onshore Abu Madi field
to the north and the East Delta Field in the central part of the concession.
The South Batra  discovery now confirms the extension of this play further south
and there could be as many as another five Abu Madi prospects and leads on the
El Mansoura concession of comparable size to South Batra.  Further detailed
evaluation will require the acquisition of 3-D seismic to further delineate the
prospective channel sands.  Following the South Batra discovery, the South
Mansoura No.1 well is now being deepened to test the same Upper Miocene Abu Madi
channel play.  The well is programmed to reach a total depth of 9,800 ft in the
Miocene Sidi Salim Formation with the top of the Abu Madi expected at around
8,300 ft.

Late-Oligocene/Early-Miocene prospectivity  Three leads have now been identified
on this concession in the deeper Qantara formation, but these require additional
seismic and geological evaluation. There is demonstrable potential in the deep
Tineh Formation as the Tarif No.1 and Tarif No.2A wells, originally drilled by
Conoco, both encountered oil shows and small quantities of oil were also tested
in the Tarif No.2A well.  Like the Qantara structure, the formation is highly
over pressured in this area.

Qantara Concession

Qantara gas field  The Qantara field, located in the south-east quadrant of the
concession, is currently producing from the Qantara No.1 well. Production
commenced in March 2001 at 5.6 MMcfpd and 1,100 bcpd, but the water production
rate built up and then stabilised quickly, suggesting communication with another
water bearing formation behind the casing. Remedial work is being considered,
but in the meantime the field is providing positive cash flow, with current
production of 1.28 MMcfpd at the wellhead and sales of 1.0 MMcfpd and a
condensate yield of 140 bcpd.

The geology of the Qantara structure has been evaluated further using the
reprocessed 3-D seismic data set and a better understanding of the structure and
distribution of the potential reservoir zones has been established.  A
multi-reservoir prospect has been identified by interpolating between the
Qantara No.2 and No.3 wells drilled by Agip in the 1970s and a well proposal is
being worked up for this multi-target prospect. Interpretation of the
reprocessed 3-D seismic also suggests that a sidetrack of the Qantara No.4 well
drilled in 2001 could establish new production for moderate incremental cost.
The Qantara reservoir section is now thought to have been faulted out in the
No.4 well bore and sidetracking the bottom-hole location to the west should
encounter the full reservoir section.

Exploration  The potential upside of the Qantara Concession is in the Pliocene,
Kafr El Sheikh formation and the deeper early-Miocene, Qantara/Tineh Formations.
The Kafr El Sheikh plays are analogous to the South Bilqas Field on the El
Mansoura Concession.  In addition, new plays in the late-Miocene, Abu Madi
formation and the deeper early-Miocene intervals have been identified.

The exploration effort is currently focused on the deeper Qantara/Tineh
formations, to identify hydrocarbon potential to provide additional
high-pressure gas and condensate to feed the Qantara production facilities, and
on the shallow Pliocene seismic "bright spot" play.

Prospects and Leads  Reprocessing of the seismic data set has better defined the
potential sandstone and carbonate reservoirs in the southern area of the
concession and four prospects and leads have been mapped in this part of the
concession where seismic quality is good.  The area around the Qantara No.1 and
No.4 wells has now been remapped in the early-Miocene, Qantara sands and a new
drilling location, the Qantara No.7, has been identified on the eastern terrace
of the Qantara structure.  A good secondary target in the well is provided by a
sand interval in the mid-Miocene which exhibits a strong seismic anomaly at
around 9,000 ft and which has been identified in the old Qantara No.2 well.  A
third target in the well is a Pliocene anomaly directly overlying both of these
zones.

The late-Miocene, Abu Madi formation may also constitute an additional
hydrocarbon play on the concession and a significant new prospect is currently
being evaluated following the South Batra discovery on the El Mansoura
concession.  Contingent upon the results of a Qantara No.7 well, a similar Tineh
prospect in a fault block to the north of Qantara No. 7, in the vicinity of the
Qantara No. 3 well, could be tested and the Abu Madi play could also be tested
at this location.

A Pliocene prospect identified by the "missed pay" analysis on the Qantara No.2
well has also been identified. The Qantara No. 2 well, located at the southeast
corner of the concession, encountered 23 ft of good quality hydrocarbon bearing
sand in the Pliocene at 2,260 ft depth and just clipped the edge of the seismic
anomaly. Average sand thickness could be as much as three times that encountered
in the No.2 well.  The Qantara No.6 well has been proposed to evaluate this
shallow prospect but will probably be drilled at a later date when a
low-pressure gas-gathering system can be justified.

The two prospects which were identified in the deeper Qantara and Tineh horizons
in the north of the concession, one of which could be up to 1 Tcf in size, were
subject to further detailed interpretation during 2002.  It is anticipated that
3-D seismic will be acquired over the northern area to better define existing
structures and high grade these to drillable prospects. In addition, 3-D seismic
would be expected to result in the identification of new shallow and deeper
prospects as has been the case in the existing southern 3-D area.

Future work programme

It is recognised that the Nile Delta onshore acreage is relatively
under-explored and that new 2-D and 3-D seismic is required.  Following the
success of the South Batra No.1 well, and the proving of an extension of the Abu
Madi channel play into the El Mansoura Concession, a three-phase programme is
being planned for the acquisition of 3-D seismic, primarily to better define the
structure and morphology of these late-Miocene channel sands.  A proposal for
the first phase of approximately 350 sq km of 3-D in the South Batra area is
currently being prepared to better define the Pliocene and Abu Madi prospects to
the west of the South Batra No.1 discovery. A location for an appraisal well to
the South Batra accumulation should also be selected before the end of 2003.

In addition, in order to further define existing leads in both the early and
late Pliocene of the Kafr El Sheikh and El Wastani formations and the deeper Abu
Madi and Qantara/Tineh Formations in the eastern part of the El Mansoura
concession, a 350 km line 2-D seismic survey is expected to be acquired.

Further drilling is dependent on the outcome of current wells but it is likely
that the Qantara No.7 well will be drilled as part of the current drilling
programme and, following the mid-Pliocene success with South Mansoura No.1, a
further mid-Pliocene prospect (the Mansouriya No.1, which is the deeper horizon
under the North Talkha well drilled last year) may also be drilled.

Bulgaria

The interests of Melrose in Bulgaria are located offshore in the shallow waters
of the western Black Sea.

Galata Production Concession

The Galata Gas Field, in which Melrose has a 100% interest, has gross proved
reserves of 49 Bcf and proved and probable reserves of 80 Bcf.  The fiscal terms
in Bulgaria are attractive with a royalty of 2.5% - 5% and corporation tax
currently at 23.5%.

The field will be developed with a simple platform located in 35 m of water, a
22 km section of 14 inch pipeline offshore and 58 km of 12 inch pipeline
onshore. The pipeline will link into the Bulgarian gas distribution system
inland from Varna to Provadia. Two production wells will be drilled during the
development phase and a third may be drilled to the downthrown fault block to
the southeast (Bogdanov East) in due course. The total capital cost for the
Galata gas field development is estimated to be approximately $52 million.
Project senior and mezzanine debt financing has been secured for the full cost
of the development.

Detailed design work on both the onshore pipeline and the offshore platform has
been completed. Contracts for the individual elements of the development project
have been put in place following final confirmation of the development financing
arrangements.  Rights of way and environmental issues have been dealt with for
all pipelines and many of the contracts which have been set up for major
materials acquisition and construction have now been entered into.  All
environmental matters have been fully addressed and the environmental programme
has been approved. The target for the first gas delivery to Bulgargaz is January
2004 at a delivery rate of up to 53 MMcfpd.

Gas production from the Galata Field is contracted to Bulgargaz, the state-owned
importer and distributor of gas in Bulgaria, who have contracted to purchase 400
million m3 (14.1 Bcf) of gas per year for a minimum of 3 years, with an annual
take-or-pay volume of 300 million m3 (10.6 Bcf).  The gas price is linked to the
prevailing gas price in the area which, in turn, is linked to the oil price.

Block 91-III

The evaluation of the hydrocarbon prospectivity of the Block 91-III remains a
major priority for the Group as any further gas discoveries could be processed
through the production and transportation facilities of the Galata gas field.

In January 2003, the Bogdanov North No.1 exploration well was drilled to test
the extent and hydrocarbon potential of the Galata reservoir section of
Maastrichtian-Palaeocene carbonates on the Bogdanov North prospect.  The
secondary objective was to explore the pre-Galata reservoir section. The well
reached a total depth of 1,030m in the Cretaceous Venchan/Russe Formation.  The
well encountered 51.8m (170 ft) of good reservoir section compared with 25m (82
ft) in the Galata Field, but there was no indication of gas and the well was
plugged and abandoned as a dry hole.

The thicker than expected reservoir section encountered in the Bogdanov North
No.1 well maintains the prospectivity of the other Galata trend prospects (Varna
East, Varna West and Bogdanov East) and these prospects are being re-assessed.
Focus will now shift to the exploration prospects in the north of the
concession, offsetting the onshore Tulenovo oil field. The 2-D seismic acquired
in 2001 confirmed a number of multi-horizon prospects and leads in the northern
part of the Block and at least two of these represent drillable prospects.

The Block 91-III Exploration Licence term has been extended for a further two
years until October 2004.  The acquisition of additional 2-D seismic, together
with the drilling of one obligation well, is currently being planned. The
geotechnical evaluation of the prospectivity of the block continues with the
integration of the results of the Bogdanov North No.1 well.

Block Kaliakra 99

Preliminary exploration activity on Block Kaliakra 99 has focused on the
reprocessing and interpretation of existing seismic which was originally
acquired in the 1990s by previous operators. 1,300 km of seismic was purchased
and reprocessed and the leads and structures previously identified on the Block
were re-evaluated.

The southern area of Kaliakra 99 has extensive Eocene flysch sediments in which
good quality sands have been proven in the wells of the area.  The Samotino More
well is thought to have tested a thin flysch sand encased in mudstone.
Evaluation of the Samotino More prospect, which lies to the south of Galata,
suggests that the interval which was tested in a previous well on the structure
is comprised of thin, lenticular sands with the risk that they may not be in
pressure communication.  The structure is complicated and additional seismic
acquisition, possibly 3-D, may be required to enhance understanding of this
area.

In the northern area of Kaliakra 99, Palaeocene clastics and Late Jurassic/Early
Cretaceous carbonates (the same reservoir as the Tulenovo Field) constitute the
primary reservoir targets.  It is clear that the northern area of Kaliakra 99
has some very interesting potential, with oil the most likely hydrocarbon charge
for the structures identified, some of which are quite large.  If initial
expectations are confirmed, Melrose may then consider the possibility of
farming-out an interest in this area, which is likely to be of interest to
larger companies.

All work obligations for the first exploration period of the Kaliakra 99 licence
have been satisfied but a need for new seismic of the quality obtained on Block
91-III has been identified and new surveys are being considered for both the
northern and southern areas of this Block.

USA

Oil and gas

The Group's interests in the US provide long life production and cashflow and
offer the potential for further exploitation.  The Group's strategy is to add
value to these interests by partial exploitation of the undeveloped reserves,
including implementation of waterflood projects where appropriate.

Development activity in the US during 2002 was restricted to workovers and
recompletions, with the emphasis on improving field operations and reducing
operating costs.  No new wells were drilled during the year, but the workover
programme generated PDP reserve replacement of approximately 340 Mboe at a cost
of $4.00 per boe.  Operating costs also reduced by 10% compared to 2001.
Average daily production declined from 880 boepd in 2001 to 687 boepd in 2002 as
expected.  The average prices received during the period were $23.80 (2001 -
$22.29) per bbl and $3.18 (2001 - $3.83) per Mcf.

During the year, regulatory approval was obtained for the Artesia Unit
waterflood and for the unitization of the Turner Gregory leases, thereby
clearing all regulatory issues on all of the Group's development projects.

With the benefit of high commodity prices, a limited drilling programme is now
planned for the Jalmat Unit in 2003 and, depending upon available cashflow, a
phased implementation of the Artesia Unit and the Turner Gregory Unit waterflood
projects will commence.

Ethanol production and distribution

Wyoming Ethanol was disposed of with effect from 30 June 2002 for a
consideration of $3.625 million which is payable in instalments over a 7 year
period.  Wyoming Ethanol is dependent upon a production incentive received from
the State of Wyoming which was due to expire in July 2003.  An extension of this
incentive was granted in March 2003 for a further period of at least 6 years,
securing the long term viability of this business.  Melrose has also retained a
19% equity interest in this business.

OIL AND GAS RESERVES

At 31 December 2002 the Group's proved and probable reserves, calculated on an
entitlement basis, comprised:


                                        Egypt         Bulgaria               USA             Total
                                    Oil       Gas          Gas         Oil         Gas
                                   Mbbl      MMcf         MMcf        Mbbl        MMcf        Mboe

Proved developed                    150      2,715           -       2,060       6,353       3,721
Proved undeveloped                    -        -        49,193       9,747       8,350      19,337
Proved                              150      2,715      49,193      11,807      14,703      23,058

Probable developed                    -      2,775           -           -           -         463
Probable undeveloped                  -      7,093      24,587           -           -       5,280
Probable                              -      9,868      24,587           -           -       5,743

Developed                           150      5,490           -       2,060       6,353       4,184
Undeveloped                           -      7,093      73,780       9,747       8,350      24,617
Proved and probable                 150     12,583      73,780      11,807      14,703      28,801



Proved and probable reserves in Bulgaria and the USA are based upon evaluations
by independent petroleum engineers and in Egypt are based upon directors'
estimates.



Movements in the Group's proved and probable reserves during the year were as
follows:

                                   
Changes in reserves              Egypt      Bulgaria          USA          Total                                     
                             Oil      Gas        Gas      Oil      Gas         
                            Mbbl     MMcf       MMcf     Mbbl     MMcf      Mboe 
                                                                                                     
At 1 January 2002            185   11,758     80,340   11,911   14,375    29,841
Disposals                      -        -    (6,560)        -        -   (1,093)
Extensions and discoveries     -        -          -        -        -         -
Revisions                   (17)    1,027          -       83      713       355
Production                  (18)    (202)          -    (187)    (385)     (302)
At 31 December 2002          150   12,583     73,780   11,807   14,703    28,801


The disposal in Bulgaria is the estimated effect of the revenue sharing
arrangement which was entered into as part of the mezzanine financing of the
Galata field development.

Discounted Net Present Value

The discounted net present value (at 10% per annum) of the Group's proved and
probable reserves at 31 December 2002 was as follows:


                                     Egypt    Bulgaria      USA     Total 
Discounted present value (PV10)       $000        $000     $000      $000 
Proved developed                     6,671           -   21,963    28,634
Proved undeveloped                       -      23,891   72,452    96,343
Proved                               6,671      23,891   94,415   124,977
Probable developed                   4,392           -        -     4,392
Probable undeveloped                 6,417      28,211        -    34,628
Probable                            10,809      28,211        -    39,020
Proved and probable                 17,480      52,102   94,415   163,997


The discounted net present value is based upon the following pricing
assumptions:

*    USA:                        $24 per barrel of oil and $4.00 per Mcf
*    Bulgaria:                   $2.55 per Mcf
*    Egypt:                      $24 per barrel of condensate and $3.60 per Mcf 
                                 and $2.50 per Mcf

Reserve additions since the year end

Since the year-end, the Company has announced the successful result of the South
Batra No.1 well and of the South Mansoura No. 1 well (in the Miocene horizon
only).  The South Mansoura No.1 is now being drilled to a deeper Pliocene
target. Based on evaluations of the well results by an independent petroleum
engineer and by the operator, the Directors estimate that the gross proved and
probable reserves in these two discoveries are approximately 187 Bcfe and 45
Bcfe respectively. This is equivalent to net reserves to the Group on an
entitlement basis of 26 Bcfe with a discounted present value (PV10) of $33.8
million.

FINANCIAL REVIEW 

Turnover for the year was #7.1 million compared with #14.2 million in the
previous year.  Turnover derived #4.4 million from the Group's oil and gas
production activities in Egypt and the USA and #2.7 million from the production
and distribution of ethanol. The reduction in turnover reflects the disposal of
Wyoming Ethanol with effect from 30 June 2002 and reduced oil and gas production
in Egypt and the USA.

The results for the year show a loss on ordinary activities after taxation of
#2,232,000 compared with a profit of #415,000 for the year ended 31 December
2001.  Earnings were adversely affected by the weakness in the US dollar, which
is the Group's principal operating currency.  Furthermore, realised foreign
exchange losses of #555,000 arose during the year (and have been included in
administrative expenses) compared with gains of #129,000 in the previous year.

EBITDA for the year of #0.5 million compares with #3.4 million for the previous
year.   Net cash inflow from operating activities during the period of #0.9
million compared with #3.4 million in the previous year.

Additions to the oil and gas assets of the Group during the period totalled #7.5
million.  This was split, geographically, #3.6 million in respect of properties
in Egypt, #2.9 million in Bulgaria and #1.0 million in the USA.  Additions to
plant and equipment, mostly Bulgaria, amounted to #0.4 million.

At 31 December 2002, the Group had cash balances of approximately #0.5 million,
bank loans totalling #13.3 million and other loans of #11.8 million.  Available
borrowing capacity under the loans totalled #1.9 million.  The maximum loan
available under the bank loans of Melrose Resources plc is #9.0 million and this
amount was fully drawn at the year-end.  These bank loans are repayable on 31
December 2005.  The loan available under the Loan Note with the Adair Trusts was
fully drawn at year-end at #7.5 million.  This loan is repayable in four
instalments between 30 April 2003 and 31 December 2005. The repayment of #3.0
million of this loan, which is due on 30 April 2003, will be repaid from the
proceeds of the Rights Issue and the balance of the loan is repayable in three
instalments between 30 April 2004 and 31 December 2005.  At the year-end Melrose
had, in addition, borrowed #4.2 million under a short-term loan from a company
which is connected with the Chairman.  This loan will also be repaid from the
proceeds of the Rights Issue. The borrowing base under the bank loan of the
Group's oil and gas subsidiary in the USA (which, at the year-end, had a balance
outstanding of $7.0 million) is re-determined bi-annually and no repayments are
currently due during the next 12 months.  This facility is due for renewal in
September 2004.

The current budget for 2003 capital expenditures in Egypt is $3 million, but
this will be kept under review following the recent exploration success.
Expenditures in Egypt will be financed by cash flow from production and from
existing cash resources and corporate debt facilities. During the year, and
depending on the results of the planned exploration programme, the availability
of debt finance to assist with the funding of the Group's activities in Egypt
will be investigated.

In Bulgaria, expenditures on the development of the Galata gas field during the
year are budgeted at approximately $40 million and it is expected that these
will be financed entirely from the senior and mezzanine debt which has been
arranged for the project.  Budgeted exploration expenditures in Bulgaria are
approximately $3 million, principally in respect of the Bogdanov North
exploration well that was drilled in January 2003.

Planned capital expenditures in 2003 on the Group's oil and gas activities in
the USA amount to approximately $3.8 million. These expenditures will be
financed from cash flow in the USA and from the bank loan facility which is in
place. Under the terms of this bank loan, the remittance of funds from the USA
to the UK is subject to the approval of the lender.

On 24 February 2003, at an EGM of the Company shareholders approved a Rights
Issue by the Company which will raise up to #13.9 million, net of expenses. The
latest time for acceptance and payment under the Rights Issue is 3.00 pm on
Monday 24 March.

After making enquiries, the directors have a reasonable expectation that the
Group has adequate resources to continue to operate for the foreseeable future.
For this reason, the accounts have been prepared on the going concern basis.



Consolidated summarised profit and loss account

Year ended 31 December


                                                                                2002                     2001
                                                       Note     #000            #000      #000           #000
Turnover
Continuing activities                                          4,375                     6,606
Discontinued activities                                        2,749                     7,549
                                                                               7,124                   14,155
Cost of sales                                                                (4,135)                  (8,633)
Depletion                                                                      (958)                  (1,517)

Gross profit                                                                   2,031                    4,005

Administrative expenses                                                      (2,642)                  (2,516)

Operating (loss)/profit
Continuing activities                                          (437)                     1,554
Discontinued activities                                        (174)                      (65)
                                                                               (611)                    1,489
Net interest payable                                                         (1,465)                  (1,068)

(Loss)/profit on ordinary activities before taxation                         (2,076)                      421

Taxation on profit on ordinary activities                                      (156)                      (6)

(Loss)/profit for the period transferred to reserves                         (2,232)                      415

(Loss)/earnings per share (p)                           (3)                  (13.62)                     2.53
                                                                             


Consolidated summarised balance sheet

As at 31 December


                                                                               2002                2001
                                                                               #000                #000

Fixed assets
Intangible                                                                    5,297               3,441
Tangible                                                                     40,410              43,030
Investments                                                                       7                  10
                                                                             45,714              46,481
Current assets
Stock                                                                             -               1,050
Debtors: Amount falling due after more than one year                2,181                   -
               Amount falling due within one year                     900               1,187
                                                                              3,081               1,187
Cash at bank and in hand                                                        460               1,310
                                                                              3,541               3,547

Creditors: amounts falling due within one year                              (9,257)             (4,131)

Net current liabilities                                                     (5,716)               (584)

Total assets less current liabilities                                        39,998              45,897

Creditors: amounts falling due after more                                  (17,875)            (17,956)
than one year

Provision for liabilities and charges                                             -               (121)

                                                                             22,123              27,820
Capital and reserves
Called up share capital                                                       1,639               1,639
Share premium account                                                        21,660              21,660
Other reserves                                                                  197               3,662
Profit and loss account                                                     (1,373)                 859

Equity shareholders' funds                                                   22,123              27,820



Consolidated summarised cashflow statement

Year ended 31 December



                                                       Note                 2002                  2001
                                                                            #000                  #000

Net cash inflow from operating activities               (4)                  461                 3,428

Returns on investments and servicing of finance
Interest paid                                                            (1,163)                 (958)
Interest paid by discontinued activity                                      (22)                     -
Interest received                                                             27                    41

Net cash outflow from returns on investments and                         (1,158)                 (917)
servicing of finance
                                                                                                 
Tax paid                                                                   (156)                   (6)

Capital expenditure and financial investment
Purchase of intangible fixed assets                                      (2,184)               (2,069)
Purchase of tangible fixed assets                                        (5,385)               (9,671)
Purchase of tangible fixed assets by discontinued                           (41)                     -
activity
Disposal of tangible fixed assets                                            122                   164

Net cash outflow from capital expenditure and                            (7,488)              (11,576)
financial investment
                                                                                              

Financing                                                                       
Borrowings raised                                                         12,382                 9,383
Repayment of borrowings                                                  (4,956)                     -

Net cash inflow from financing                                             7,426                 9,383

(Decrease)/increase in cash                                                (915)                   312




Notes


1.                  Statement of total recognised gains and losses
                                                                                  2002           2001
                                                                                  #000           #000

(Loss)/profit for the period                                                    (2,232)           415
Currency translation difference on foreign currency net                         (3,465)           725
investment

                                                                                (5,697)         1,140

2.                  Reconciliation of movements in shareholders' funds
                                                                                   2002          2001
                                                                                   #000          #000

(Loss)/profit for the period                                                    (2,232)           415
Dividends paid and proposed                                                           -             -
                                                                                (2,232)           415
Other recognised gains and losses relating to the period                        (3,465)           725

Net (decrease)/increase in shareholders' funds                                  (5,697)         1,140
Opening shareholders' funds                                                      27,820        26,680

Closing shareholders' funds                                                      22,123        27,820


3.                  Earnings per share and dividends

Earnings per share has been calculated by dividing the loss after taxation for
the year ended 31 December 2002 of #2,232,000 (2001 - profit #415,000) by the
number of shares in issue throughout the period of 16,390,765 (2001 -
16,390,765). Diluted earnings per share has not been calculated for 2001 or 2002
as the share options are anti-dilutive.

No dividend has been declared (2001 - nil).

4.                  Net cash inflow from operating activities
                                                                                   2002          2001
                                                                                   #000          #000

Operating (loss)/profit                                                           (611)         1,489
Depletion and depreciation                                                        1,131         1,918
Non cashflow from disposal of subsidiary                                          2,780             -
Loss on disposal of fixed assets                                                      -             9
Provision against value of fixed asset investment                                     3             6
Intangible fixed assets written-off                                                   -            25
Decrease/(increase) in stocks                                                       889         (296)
(Increase)/decrease in debtors                                                  (1,587)           603
Decrease in creditors                                                           (2,144)         (326)
Net cash inflow from operating activities                                           461         3,428


5.                  Financial information and annual report

The financial information set out in this preliminary announcement does not
constitute statutory accounts as defined in section 240 of the Companies Act
1985.  The comparative financial information is based on the statutory accounts
for the year ended 31 December 2001.  Those accounts, upon which the auditors
issued an unqualified opinion, have been delivered to the Registrar of
Companies.  The statutory accounts for the financial year ended 31 December 2002
will be delivered to the Registrar.

The summarised balance sheet at 31 December 2002 and the summarised profit and
loss account, summarised cash flow statement and associated notes for the year
then ended have been extracted from the Group's financial statements. Those
financial statements have not yet been delivered to the Registrar, nor have the
auditors reported on them.

Full accounts are due to be posted to shareholders by 9 May 2003 and will be
available at the Company's registered office, No. 1 Portland Place, London W1B
1PN, from that date.


Glossary of terms

bbl               barrel of oil or condensate
Bcf               billion cubic feet of gas
Bcfe              billion cubic feet equivalent
Bcpd              barrel of condensate per day
Boe               barrel of oil equivalent
Boepd             barrel of oil equivalent per day
Bopd              barrel of oil or condensate per day
the Company       Melrose Resources plc
EBITDA            Earnings before interest, taxation, depletion, depreciation 
                  and amortisation
EGPC              The Egyptian General Petroleum Corporation
GIIP              gas initially in place
the Group         the Company and its subsidiaries
Mbbl              thousand barrels of oil or condensate
Mboe              thousand barrels of oil equivalent
Mcf               thousand cubic feet of gas
Melrose           the Company or the Group, as appropriate
MMbbl             million barrels of oil or condensate
MMboe             million barrels of oil equivalent
MMcf              million cubic feet of gas
MMcfpd            million cubic feet of gas per day
PDP               proved developed producing
Petreco           Petreco S.a.r.l. and/or Petreco Bulgaria EOOD as appropriate
PUD               proved undeveloped
PV10              discounted present value at 10% per annum
Tcf               trillion cubic feet of gas




                      This information is provided by RNS
            The company news service from the London Stock Exchange
END

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