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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Management Resource Solutions Plc | LSE:MRS | London | Ordinary Share | GB00B8BL4R23 | ORD EUR0.01 |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 2.30 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
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Melrose Resources PLC
29 March 2004
For Immediate Release 29 March 2004
Melrose Resources plc
Preliminary Announcement of Results for the year ended 31 December 2003
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 2003:
2003 HIGHLIGHTS
Financial
* Turnover from oil and gas activities up 59% to #7.0 million (2002:
#4.4 million);
* EBITDA up 380% to #2.4 million (2002: #0.5 million);
* Profit after taxation of #2.8 million (2002; #2.2 million loss);
* #31.6 million raised from Rights Issue and Placing and Open Offer;
* Maiden dividend expected in 2005.
Operational
* Significant exploration success on El Mansoura Concession;
* Fast track development of 3 new fields in Egypt;
* 127% increase in production to 2,600 boepd by year end;
* Galata development substantially complete with first gas scheduled for next
month;
* 46% increase in oil and gas reserves to 42 MMboe;
* 85% increase in discounted present value of oil and gas reserves.
Commenting on this, Robert Adair, Chairman, said:
"2003 was a year of major achievement for Melrose with exploration success and
development of the Galata Gas Field and I am delighted that these achievements
are starting to bring financial benefits to the Company and its shareholders.
We have an exciting drilling programme scheduled for 2004 which I believe will
deliver further excellent growth in production and which offers the potential to
significantly increase shareholder value."
For further information please contact
Melrose Resources plc
David Curry, Chief Executive 0131 221 3360
Munro Sutherland, Finance Director 0131 221 3360
Chris Thomas, Corporate Development Director 0207 462 1603
Buchanan Communications
Ben Willey/Tim Thompson 0207 466 5000
Sophie Morton
or visit our website at www.melroseresources.com.
In the last year Melrose has achieved some of its key objectives for the
development of the Group and we are now seeing tangible benefits from the
groundwork done in previous years. We are pleased that some of our achievements
are starting to bring financial benefits to the Company and its shareholders.
In Egypt, the three successive exploration successes on the El Mansoura
Concession in the first half of the year transformed the value and the
perception of our interests. We have followed upthis exploration success with
the fast track development of these fields and we now enjoy production from six
wells on five different fields. This success has established two highly
prospective exploration plays in the shallower horizons down to 10,000 ft on the
El Mansoura Concession. A further 15 drillable prospects with reserve potential
of 20-100 Bcf each have now been confirmed in these horizons by new 2-D and 3-D
seismic. In addition, large prospects and leads of Tcf potential have alsobeen
identified in the deeper horizons and these remain to be tested. Our strategy
for the El Mansoura Concession is to establish early production from lower risk
exploration drilling to maximise the area within the concession which can be
converted to development leases prior to targeting the larger, higher risk
targets that have been identified. We are now planning an aggressive drilling
programme over the remaining two and a half years of the El Mansoura exploration
concession and we expect to have three drilling rigs continuously operational by
the end of 2004. We have agreed a term sheet for debt finance for our
expenditures in Egypt and expect that the facility will be in place later in the
year.
Our main focus in Bulgaria hasbeen on the Galata development project where
first production is imminent. First production from this field will represent a
significant achievement for Melrose and we are delighted to be playing an
important role in the continuing development of the Bulgarian oil and gas
industry. Evaluation of the new seismic which we have acquired over some of our
Bulgarian acreage has yielded very interesting results. We plan to drill at
least one low risk exploration well in the same trend as the Galatafield early
in the second half of this year. Deeper, but potentially very large, structures
have been identified in a channel play to the south of Galata. Evaluation is
continuing but the upside potential here is exciting with reserve potential of
well over 1 Tcf.
In the USA, we have been able to commit additional funds to our programme of
development drilling and secondary recovery projects. This low risk drilling
programme provides a good balance within our portfolio and the results of wells
drilled in 2003 have been encouraging.
Over the last year we have made good progress towards balancing our portfolio of
interests between exploration, development and production. During the course of
2003, production more than doubled to 2,600 boepd by year end and we look
forward to seeing our production grow significantly over the coming year. In
2004 we plan to drill up to ten exploration wells - eight in Egypt and two in
Bulgaria - and up to thirty one appraisal and development wells - six in Egypt,
one in Bulgaria and twenty four in the USA. This drilling programme will shift
more of our reserves into production and will expose the Company to very
significant exploration upside. The exploration wells planned for 2004 have the
potential to more than double the Group's net reserves in Bulgaria and Egypt.
I am pleased that the Group has returned to profit and also that the value in
the Group's assets and the achievements of its management are being better
recognised in the stock market. Over the last 12 months we have completed three
share issues to provide funds for the Galata development project and to
accelerate our drilling programme in Egypt. These share issues have broadened
the Company's shareholder base, increased the public float and, together with
the appreciation in the share price, have brought a significant increase in the
market capitalisation of the Company. We now have an exciting drilling
programme scheduled for 2004 which I believe will deliver further excellent
growth in production and which offers the potential to significantly increase
shareholder value.
We intend shortly to propose to shareholders a scheme of capital reconstruction
to eliminate the current deficit on the profit and loss account of the Company.
This will allow the Company to commence payment of dividends out of future
profits: we would hope to pay a first dividend in 2005 on the basis of results
in 2004.
I welcome new shareholders who have joined us over the last year and thank all
of our shareholders for their continuing support.
R F M Adair
Chairman
26 March 2004
Financial Review
Results for the year
Turnover for the year was #7.0 million which compares with turnover in 2002 of
#7.1 million, of which #4.4 million was from oil and gas. Turnover in Egypt in
2003 was #2.9 million (2002: #0.8 million) and in the USA was #4.1 million
(2002: #6.3 million). The reduction in turnover in the USA was the result of
the disposal during 2002 of Wyoming Ethanol.
Profit after tax amounted to #2,796,000 (2002: loss #2,232,000) after taking
into account a tax credit of #2,487,000 (2002: #156,000 charge). This tax
credit comprises a charge for overseas corporation tax of #835,000 (2002:
#156,000) and a net deferred tax credit of #3,322,000 (2002: #nil). The
deferred tax credit arises from the recognition of accumulated losses arising
from prior expenditures on the Group's Bulgarian interests. In view of the
imminent first production from the Galata field, the directors are of the
opinion that these are now more likely than not to be recovered from future
taxable profits. Earnings were adversely affected by the weakness in the US
dollar, which is the Group's principal operating currency and which depreciated
by approximately 10% during 2003. Also, realised foreign exchange losses of
#535,000 arose during the year (and have been included in administrative
expenses) compared with losses of #555,000 in 2002.
EBITDA for the year of #2.4 million compares with #0.5 million for the previous
year:
2003 2002
#000 #000
Operating profit/(loss) 1,220 (611)
Add back:
Depreciation 29 173
Depletion 1,161 958
_____________________________
2,410 520
_____________________________
Average prices received and unit operating costs were as follows:
Egypt USA
2003 2002 2003 2002
$ $ $ $
Oil/condensate (bbl) 29.16 23.70 27.86 23.80
Gas (Mcf) 2.74 3.21 4.97 3.18
__________________________________________________
Revenue per Boe 16.99 20.81 28.34 22.59
Production taxes - - (2.06) (1.62)
Operating costs (1.99) (5.62) (8.15) (7.99)
__________________________________________________
Net cashflow per boe 15.00 15.19 18.13 12.98
Depletion (4.24) (7.91) (4.59) (4.51)
__________________________________________________
Net profit per boe 10.76 7.28 13.54 8.47
__________________________________________________
In Egypt, the decrease in the gas price was a result of the lower price which is
receivable for production from the El Mansoura Concession compared with the
Qantara Field. Operating costs per boe reduced by approximately 65% due to
reduced production costs in the El Mansoura field and the depletion charge
decreased by 46% as a result of significant reserve additions during the year.
Additions to the oil and gas assets of the Group during the year totalled #45.3
million. This was split, geographically, #8.7 millionin respect of properties
in Egypt, #34.1 million in Bulgaria and #2.5 million in the USA.
Financing
During the year the Company completed two issues of new Ordinary Shares. In
March 2003, the Company issued 27.8 million Ordinary Shares througha Rights
Issue at 50 pence per share and raised #13.5 million net of expenses. In
August, the Company issued 18.4 million Ordinary Shares at 100 pence per share
through a Placing and Open Offer and raised #18.1 million, net of expenses.
Since the year end the Company has issued 6.25 million Ordinary Shares at 175
pence per share and raised #10.7 million net of expenses. The proceeds of all
three issues were used to meet the Group's capital expenditures, to repay debt
and to provide working capital for the Group.
At 31 December 2003, the Group had cash balances of approximately #3.4 million
and bank loans totalling #38.6 million. Available borrowing capacity under the
bank loans totalled #7.0 million.
Borrowings
In order to manage liquidity risk, the Group has put in place firm borrowing
facilities which have fixed repayment schedules. Short-term liquidity is
managed by the use of cash and short-term deposits or by bank overdraft. The
maximum loan available under the bankloans of Melrose Resources plc is #9.7
million of which #6.7 million was drawn at the year-end. A loan facility of
#2.7 million, of which #0.7 million was drawn at the year-end, is repayable on
(30 September 2004) and a loan of #6 million, which was fully drawn at the
year-end, is repayable on 31 December 2005. During the year, the Company repaid
in full loans from the Adair Trusts of #7.5 million. The borrowing base under
the bank loan of the Group's subsidiary in the USA (which, at the year-end, had
a balance outstanding of $6.7 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 2005. Subsidiaries of the Group have in place senior
loan facilities and mezzanine loan facilities in connection with the Galata
development for up to $34 million and $23 million, respectively. At the
year-end, $30.0 million and $20.0 million, respectively, had been drawn under
these facilities.
Capital expenditure budget
The budget for 2004 capital expenditures in Egypt is approximately $26 million,
of which approximately $11 million is for exploration and $15 million is for
appraisal and development. Expenditures in Egypt will be financed by cash flow
from production, existing cash resources, existing loan facilities and from a
new loan facility which is being arranged and which is expected to be in place
later in the year.
In Bulgaria, budgeted expenditures on completing the development of the Galata
gas field during the year are approximately $12 million. Budgeted firm
exploration expenditures in Bulgaria in 2004 are approximately $3.5 million. It
is expected that the Galata project loan facilities will be fully drawn and the
balance of expenditures will be met from cash resources and existing loan
facilities.
Budgeted capital expenditures in 2004 in the USA are approximately $8 million.
This budget will be increased if oil prices stay at their current levels. These
expenditures will be financed from cash flow in the USA and from the bank
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.
Going concern
Aftermaking 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.
REVIEW OF OPERATIONS
BULGARIA
The interests of Melrose in Bulgaria are located offshore in the shallow waters
of the western Black Sea. Melrose owns a 100% interest in each of the three
concessions, the Galata Production Concession and two exploration concessions,
Block 91-III and Block Kaliakra 99. The Galata Gas Field is located 23 km
offshore to the east of Varna and is contained within the area of the Galata
Production Concession.
Galata Production Concession
The Galata Gas Field development is now mechanically complete. The jacket and
topsides were floated out of the Varna shipyard and were positioned on the
seabed in October 2003. The 58 km onshore pipeline was complete by the end of
December and the onshore process plant by the end of February 2004. However,
first production from the field was delayed until April 2004 due to storm damage
in December to the barge which was laying the offshore pipeline: the pipeline
was finally completed on 12 March 2004. As of 26 March, the system has now been
built and final tests are being completed.
The two Galata production wells (GP1 and GP2) were drilled and successfully
completed in November and December. Both wells were completed as gas producers
and tested at rates of approximately 30 MMcfpd and flowing wellhead pressures of
1,500 psi. First system gas is now being produced into the 71 km pipeline which
links into the Bulgarian gas distribution system at Provadia. First gas sales
are expected to be delivered to Bulgargaz inearly April 2004.
The GP2 production well confirmed the extension of the productive gas reservoir
into the northern fault block of the Galata structure. This has resulted in a
significant increase in the proven and probable reservoir volume and field
reserves. Based on an evaluation of the original production test and the new
well pressure data, it now seems highly probable that there is pressure
connection between the northern and southern fault blocks of the Galata
structure. Proved reserves are now estimated to be 65 Bcf compared with 49 Bcf
carried previously and estimated proved plus probable reserves have increased
from 80 Bcf to 90 Bcf. A third development well may be drilled to the
downthrown fault block to the south-east during 2004/5. The Galata reservoir is
highly suited for use as a storage facility and, after a period of production,
further evaluation will be done of the potential for the conversion of the field
for this purpose.
Block 91-III
The remaining area of Block 91-III is 1,690 km(2). The block encompasses, but
does not include, the Galata Production Concession. There is clear evidence of
an active petroleum system in this area of the Black Sea and the block contains
a number of prospects and leads which offer significant exploration upside.
Melrose is interested in three plays: structures adjacent and analogous to the
Galata Field; multi-reservoir targets in the northern part of the block; and
larger and deeper targets in the Oligocene horizon to the south of Galata. In
2003 Melrose acquired and interpreted 366 km of 2-D infill seismic in the
southern part of the block.
Interpretation of the new seismic has identified seven structures, three of
which may be analogues of Galata and which have potential reserves of 40-100 Bcf
each. These prospects are currently being re-evaluated and the interpretation
integrated with the results of the Bogdanov North No.1 well. Enhanced seismic
processing is being carried out on these structures prior to selecting a
drilling location. It is expected that an exploration well on one of the
structures will be drilled in the summer of 2004. The economics of any
discovery would be enhanced by the ability to use the Galata Field production
facilities and associated infrastructure in any development.
The new seismic has confirmed the large east-west trending Oligocene channel
fill play which lies in the south of Block 91-III and runs into Block Kaliakra
99 and which may have potential upside reserves in excess of 1 Tcf. A well may
be drilled on this trend later in the year. In addition, there may be a number
of large stratigraphically defined structures developed on the margins of this
channel.
The exploration potential of a number of multi-reservoir targets (from the
Devonian to the Oligocene) in the northern part of the Block, identified from
the 729 km of 2-D seismic acquired in 2001, is currently being re-evaluated. At
least two of these, offsetting the onshoreTulenovo oilfield, are regarded as
drillable prospects. The oil charging the Tulenovo structure is believed to
have migrated from a deep "kitchen" area offshore to the southeast and this
could also have charged the Block 91-III northern prospects.
Block Kaliakra 99
Block Kaliakra 99 is contiguous with Block 91-III to the east and south and
covers an area of 2,601 km(2). The initial period of the Prospecting and
Exploration Permit expires in May 2004 and all the work programme obligations
have been fulfilled, including the acquisition of 120 km of infill 2-D seismic
over the southern part of the Block. A two-year extension has been applied for.
During the next exploration phase, additional seismic will be acquired in the
southernpart of the Block, particularly over the high risk, potentially high
reward stratigraphic plays in the Oligocene channel fill and over the
structurally complicated, hydrocarbon-bearing, Samotino More structure. In the
northern area of Block Kaliakra 99, Palaeocene clastics and Late Jurassic /
Early Cretaceous carbonates (analogous to the producing reservoir in the
Tulenovo oil field) constitute the primary reservoir objectives with oil the
most likely hydrocarbon charge for the structures identified. Additional 2-D
and 3-D seismic will be required to further evaluate these structures.
The operators of the two deepwater concessions located to the east and south of
Block Kaliakra 99 have acquired extensive 2-D seismic data, including several
lines which, by mutual agreement, extended into the Group's acreage. Technical
data is being traded and further technical cooperation is possible.
EGYPT
The interests of Melrose in Egypt comprise a 50% interest in the El Mansoura
Concession and a 46% interest in the Qantara Concession. Both concessions are
located onshore in the highly prospective and productive Nile Delta. The
operator of both concessions is Merlon Petroleum Company.
In 2003 Melrose enjoyed substantial exploration success on the El Mansoura
Concession. Production has now been established on both concessions and Melrose
currently has production from six wells in five fields. A very active drilling
programme is planned for the current year with a total of six appraisal and
development wells and up to eight exploration wells planned.
El Mansoura Concession
The El Mansoura Concession covers an area of 1,368 km(2) and is located in the
northern part of the Nile Delta to the north of Mansoura City. The concession
surrounds (but does not include) the producing East Delta Gas Field. All three
exploration wells drilled on the concession in 2003 were commercial discoveries
- the South Batra No.1, South Mansoura No.1 and Mansouriya No.1 wells. These
wells have established two highly prospective exploration plays; the shallow,
Pliocene horizon and the deeper, Miocene, Abu Madi channel system. In addition,
several large prospects and leads have been identified in the deep, Lower
Miocene, Sidi Salim and late Oligocene, Tineh formations.
The El Mansoura exploration concession expires in mid-2006 but areas surrounding
discoveries will be converted to long-term development leases. The strategy for
the El Mansoura Concession throughout 2003has been to continue to establish
early production from lower risk exploration drilling of prospects of Pliocene
age, and to test the potential of the deeper Miocene reservoirs of the
productive Abu Madi section. The objective over the next two anda half years
is to follow an aggressive drilling programme in order to maximise the area
within the concession which can be converted to development leases.
Production and development
South Batra field
The South Batra No.1 well was drilled in January 2003 and the Abu Madi Level III
reservoir section was tested successfully. The late Miocene, Abu Madi channel
sand reservoir is a regional play which was 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 confirmed the extension of this play
south. Current estimates indicate most likely reserves in the South Batra Field
of 499 Bcfe gross. A development area which covers an area of 76.5 km(2) has
been granted, which also incorporates the area of the Pliocene, Mansouriya
Field. The South Batra No.1 discovery well was brought on production on 5
December 2003 at 30 MMcfpd gross plus 500 bcpd. Gas is produced via a 2 km, 8
inch pipeline to the national trunk line.
The appraisal/development programme over the South Batra Field is underway with
the successful drilling of the South Batra No.2 appraisal well, which reached a
total depth of 10,190 ft in the Upper Miocene, Qawasim formation. As expected,
the well encountered a good section of Abu Madi Level II reservoir. Following a
short "clean up" test, which flowed 15 MMcfpd on a 1/2 inch choke with a flowing
tubing pressure of 2,900 psi, the well started production on 26 February 2004.
The South Batra No.3 appraisal well, intended to probe the northern edge of the
structure, was spudded in January 2004 and is now being completed. The well was
sidetracked to a bottom hole location which was 53 ft structurally higher than
the original location in order to test the Abu Madi Level IIIA formation at a
location where better reservoir quality and hydrocarbon-bearing reservoirs have
been encountered. 3-D seismic data has just been acquired over the whole of the
development area and all future development locations will be based on this new
3-D data.
South Mansoura Field
The South Mansoura No.1 well, located to the south of the South Batra discovery,
was drilled in February 2003 and reached a total depth of 9,715 ft in the middle
Miocene, Sidi Salim formation. Wire-line logs indicate a mid-Pliocene gross
reservoir interval of over 200 ft, with 31 ft of good quality reservoir. The
remaining section, comprising interbedded sands and shales, is alsoexpected to
contribute to reserves and production. A total of 46 ft was perforated in the
mid-Pliocene, Kafr El Sheikh formation. The well flowed at 17.7 MMcfpd on a 3/4
inch choke at a flowing pressure of 1,255 psi at surface. The well was logged
to this Pliocene interval and then deepened to test the late Miocene, Abu Madi
formation.
The top of the Abu Madi was encountered at 7,995 ft and very high background gas
readings were observed drilling the interval 8,190-8,350 ft. It is believed
that this corresponds to the Abu Madi Level III channel interval encountered in
the South Batra No.1 well. While the zone is below the water contact at this
location, there are strong indications from sidewall core and pressure data that
there may be gas and condensate updip on what appears to be a large structure.
A location for an appraisal well, to further evaluate both the Kafr El Sheikh
and the Abu Madi intervals, has been selected and will be drilled in 2004. The
well proved the Miocene, Abu Madi channel system to be developed 18 km to the
south of the South Batra discovery.
Current estimates indicate most likely reserves of 18.8 Bcfe gross. The field
came on production in March 2004 at a rate of 10 MMcfpd gross. Gas is produced
via an 11km, 8 inch pipeline to the national trunk line.
Mansouriya Field
The Mansouriya No.1 exploration well was drilled in April 2003 and reached a
total depth of 10,530 ft in the late Miocene, Qawasim formation, encountering a
gross reservoir interval of 130 ft in the middle Pliocene, Kafr el Sheikh. A
section of this interval was flow tested at 16.8 MMcfpd on a restricted choke.
Current estimates indicate most likely reserves of 30 Bcf of dry gas. The well
was deepened to the Abu Madi interval and gas and condensate were sampled in
this horizon, confirming the extension of the greater South Batra channel
system. The well encountered the edge of the Abu Madi channel and a further
appraisal well will be required. The fieldwent on production on 8 December
2003 at a rate of 10 MMcfpd but the rate was increased to 18 MMcfpd in January
2004 and this rate is being sustained. Gas is produced via a 5 km, 8 inch
pipeline to the national trunk line via the South Bilqas site.
South Bilqas Field
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 gas is transported to the nearby national trunk line by a 12 inch, 3 km
pipeline. The well has started to produce water but a compressor will be
installed in the near future. Proven reserves of 16.5 Bcfe gross have been
attributed to this field with 4.3 Bcf already produced by the end of 2003.
Exploration and Prospects
Further geological and geophysical evaluation of the concession is continuing
using the results of a new 253 km(2) 3-D survey which was acquired in 2003 over
the western part of the concession, focusing on the development lease areas, and
486 km of new 2-D seismic which was acquired over the eastern part of the
concession. The data from the new 3-D seismic survey over the area of the South
Mansoura and South Batra discoveries is currently being processed.
Interpretation of initial fast track processing has already confirmed a number
of Pliocene, Upper Miocene and deeper prospects and leads and there is the
potential for multiple new prospects over the 3-D seismic survey area. The
detailed image of the Abu Madi around the South Batra accumulation will assist
in the successful development of that field and will provide locations for
appraisal drilling. The 2-D seismic data which was acquired over the relatively
under-explored eastern side of the concession has in-filledthe previous grid
and resulted in identification or clarification of new prospects at various
stratigraphic levels.
Future Work Programme
Drilling plans for the current year include up to six appraisal and development
wells on South Batra and up to eight exploration wells. Interpretation of
existing seismic data and drilling results has yielded a portfolio of
approximately twenty exploration prospects. These range from analogues of the
recent Pliocene successes to Sidi Salim (just belowthe Abu Madi) and Qantara
deep tilted fault blocks with significant upside. Several leads and prospects
are at Abu Madi level, where the understanding of the detailed stratigraphy and
amplitude expression of the sands should ensure a high success-ratio. Plans are
also being prepared to extend the 3-D survey over a larger area on the western
side of the concession. In summary this concession has provided successes from
a variety of geological horizons, and indicates significant potential for the
future
Qantara Concession
The Qantara Concession covers an area of 150 km(2) in the Nile Delta basin to
the west of the Suez Canal and southwest of Port Said. The whole of the Qantara
Concession area has been converted to a development lease and all gas and
condensate produced is sold under long-term contracts.
Qantara Field
The Qantara No.1 well, which was originally drilled and completed in 1976, has
been producing large volumes of water which is channelling from a separate
aquifer and this has impaired production (currently 0.75 MMcfpd and 20 bcpd).
Remedial work has recently commenced on the well. Further development
potential exists on this structure and the field facilities will be available
for other development should discoveries be made within the concession.
During 2003 drilling activity on the concession focussed on the deeper,
early-Miocene Qantara and Tineh formations with a view to providing additional
high-pressure gas and condensate to feed the Qantara production facilities. The
Qantara No.7 was drilled to test an extension of the Qantara field in June 2003
to a total depth of 10,280 ft in the Lower Miocene Tineh formation.
Unfortunately, the well did not reach the main Qantara Tineh horizon due to
mechanical difficulties and it was not successful in two shallower Qantara sand
intervals which were tested. The Qantara No.8 well, drilled to a total depth of
10,500 ft in the late Oligocene/early Miocene Tineh formation, also targeted
multiple objectives which were defined on the 3-D data. Although the Qantara
No.7 and No.8 wells both recorded hydrocarbons, both were plugged and abandoned
as non-commercial gas wells. The Qantara formation contains good reservoir
quality sands at various levels, but their lateral extent and the migration
pathways from available local source rock are still not fully understood and not
resolved on the seismic data. The Tineh horizon, producing in the Qantara No.1
well, has provided strong hydrocarbon shows but has proved hard to test due to
drilling difficulties. While the results of the two Qantara wells were
disappointing, there is still clear potential in this formation. Further work
is necessary to identify a location to further appraise this elusive target.
The exploration focus on the concession has moved to an evaluation of the
shallow Pliocene "bright spot" plays which have been successful on El Mansoura.
Several strong Pliocene seismic anomalies, which are analogous to the productive
Kafr el Sheikh accumulations in the El Mansoura Concession, remain to be tested
and a possible Qantara No.9 location is being considered to evaluate one of
these anomalies. Further interpretation of the 3-D seismic on the Qantara
Concession has led to a better understanding of the geology of this concession
and a number of Pliocene and Miocene prospects and leads have been mapped. New
exploration interest has also been directed at the Sidi Salim formation where
complex structures and multiple amplitude anomalies require further study to
mature into drillable prospects.
Future Work Programme
Planned work includes further 3-D seismic acquisition over the northern portion
of this block where both shallow Pliocene and deep Qantara/Tineh leads need
better definition than is possible from the current 2-D data. 3-D seismic will
better define existing leads and high grade these to drillable prospects, in
addition to identifying new shallow or deeper prospects as demonstrated in El
Mansoura. Further interpretation work is underway to integrate the results of
the recent drilling. In summary, despite the disappointment of the recent
wells, there is significant remaining potential on this block.
USA
The Group's interests in the USA comprise approximately 25,000 gross acres,
concentrated in the Permian Basin in Eddy and Lea Counties, New Mexico, and
Mitchell County, Texas. Melrose has approximately 100% working interests in,
and is operator of, the majority ofthese properties. The properties are
characterised as shallow oil production with substantial, low-risk development
upside.
The Group has established a track record of successful exploitation of these
reserves. The strategy now is to step up development activity over the next two
to three years to add value through exploitation of the undeveloped reserves.
This offers very attractive returns on investment.
Development programme
During 2003, eight wells were drilled on leases in which Melrose has a 100%
working interest. In the first three months of 2004 a further 4 wells have been
drilled. In 2003, Melrose also participated in the drilling of 10 wells in
which it has a minority working interest.
Jalmat field interests
In total, eight wells were successfully drilled during 2003, with 400 Mboe of
reserves being converted to PDP reserves at a cost of $4.41 per boe. Initial
production rates from these wells ranged from 50 boepd to in excess of 200
boepd, exceeding expectations. The most encouraging results were obtained from
the JU No. 192 which was a "step out" well drilled on the western flank of the
Jalmat Unit. This well encountered reservoir with high porosity and pressure in
the Yates Sand interval at approximately 4,000 ft and was brought onto
production at rates of in excess of 200 boepd. As a result of this successful
drilling programme, a further ten infill locations have been identified and an
additional 500 Mboe of PUD reserves have been booked.Net daily production from
the Jalmat field interests increased by 95%, from 200 boepd at the end of 2002,
to 390 boepd at 31 December 2003.
Artesia field interests
Daily production from the Group's interests in the Artesia field increased by
32% during 2003 to 197 boepd by December 2003. This was principally as a result
of participation in 10 new wells on the non-operated State D lease in a deeper
horizon in the Artesia field. In addition, work on the secondary recovery
project on the Artesia Unit continued with the workover of the AU Pilot No.1
waterflood. There are in excess of thirty drilling locations on the Artesia
Unit that are scheduled to be developed over the next three years as part of
this enhanced recovery project.
Turner Gregory field interests
The unitisation of the Turner Gregory leases was completed in December 2002 and
the 2003 development effort concentrated on rationalization of the surface
facilities in preparation for commencement of the secondary recovery programme
in 2004. This exercise also had the benefit of reducing operating costs by in
excess of 20%. Average daily production declined in line with expectations by
14% during 2003 to 118 boepd. The Turner Gregory Unit is on trend with two
large secondary recovery projects to the north east and south west. Full
implementation of this waterflood over the next three years is expected to
increase attributable production by 500 boepd.
Other interests
Average daily production from the Group's other interests in the USA during 2003
was unchanged at 161 boepd. During the year, net proceeds of $497,000 were
realised from the sale of mineral rights covering approximately 3,800 acres in
Parker County, Texas. Melrose has retained a royalty interest and an option to
participate in any wells drilled on this acreage.
Production
Overall, production increased by 22% from 651 boepd in December 2002 to 797
boepd in December 2003, with full production potential at year end estimated to
be approximately 1,000 boepd. Average daily production of 702 boepd in 2003 was
unchanged compared with 2002.
Production of 3,000 boepd is being targeted by the end of 2006. It is expected
that the capital expenditure required to achievethis target can be financed
through re-investment of cashflow and the use of existing borrowing facilities.
Oil and gas reserves
Total oil and gas reserves attributable to the Group's interests in the USA
increased to 14.4 MMboe (2002: 14.2 MMboe). Proved developed reserves increased
by 6% to 2.8 MMboe, which represents replacement of 180% of 2003 production. In
aggregate, 500 Mboe of reserves were developed at a cost of $5.46/boe.
2004 development plan
A significant increase in development activity is planned for 2004 with 24 new
infill wells currently scheduled, including twelve wells in the Jalmat field and
eight wells in the Artesia field. Secondary recovery projects on the Jalmat
Unit and the Turner Gregory Unit are also scheduled to commence in 2004 and the
Artesia Unit pilot waterflood will be expanded during 2004. The capital
expenditure budget for the US for 2004 is $8 million, but this may be increased
if oil prices continue to stay strong into the second half of the year.
OIL AND GAS RESERVES
Proved and Probable Reserves
At 31 December 2003 the Group's proved and probable reserves, calculated on an
entitlement basis, comprised:
Egypt Bulgaria USA Total
Oil Gas Gas Oil Gas Oil Gas
Mbbl MMcf MMcf Mbbl MMcf Mbbl MMcf
______________________________________________________________________________________________________
Proved developed 120 13,480 - 2,335 6,033 2,455 19,513
Proved undeveloped 307 18,491 61,541 9,658 8,271 9,965 88,303
_____________________________________________________________________________
Proved 427 31,971 61,541 11,993 14,304 12,420 107,816
_____________________________________________________________________________
Probable developed - 2,037 - - - - 2,037
Probable undeveloped 561 42,090 21,884 - - 561 63,974
_____________________________________________________________________________
Probable 561 44,127 21,884 - - 561 66,011
_____________________________________________________________________________
Developed 120 15,517 - 2,335 6,033 2,455 21,550
Undeveloped 86860,581 83,425 9,658 8,271 10,526 152,277
_____________________________________________________________________________
Proved and probable 988 76,098 83,425 11,993 14,304 12,981 173,827
_____________________________________________________________________________
Proven and probable reserves are the estimated quantities of crude oil, natural
gas and natural gas liquids which geological, geophysical and engineering data
demonstrate with a specified degree of certainty to be recoverable in future
years from known reservoirs and which are considered commercially producible.
The figures are estimated on the basis that there should bea 90% probability
that the actual quantity of recoverable reserves will be more than the amount
estimated as proven and there should be a 50% probability that the actual
quantity of recoverable reserves will be more than the amount estimated as
proven and probable.
Proved reserves in the USA are as evaluated by independent petroleum engineers.
Proved and probable reserves in Bulgaria and Egypt are directors' estimates
based upon evaluations by independent petroleum engineers.
Movements inthe Group's proved and probable reserves during the year were as
follows:
Egypt Bulgaria USA Total
Oil Gas Gas Oil Gas Mboe MMcfe
Mbbl MMcf MMcf Mbbl MMcf
______________________________________________________________________________________________________
At 1 January 2003 150 12,583 73,780 11,807 14,702 28,801 172,806
Extensions and 959 65,549 - 455 273 12,384 74,306
discoveries
Revisions (112) (840) 9,645 (76) (294) 1,231 7,383
Production (9) (1,194) - (193) (377) (464) (2,783)
_____________________________________________________________________________
At 31 December 2003 988 76,098 83,425 11,993 14,304 41,952 251,712
_____________________________________________________________________________
Reserves in Bulgaria are net of 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 net present value of the Group's proved and probable reserves as at 31
December 2003 was as follows:
Egypt Bulgaria USA Total
Discounted net present value (NPV10) $000 $000 $000 $000
__________________________________________________________________________________________________________
Proved developed 26,548 - 25,723 52,271
Proved undeveloped 26,720 80,863 66,099 173,682
__________________________________________________
Proved 53,268 80,863 91,822 225,953
__________________________________________________
Probable developed 2,778 - - 2,778
Probable undeveloped 48,321 25,739 - 74,060
__________________________________________________
Probable 51,099 25,739 - 76,838
__________________________________________________
__________________________________________________
Proved and probable 104,367 106,602 91,822 302,791
__________________________________________________
The discounted net present value is based upon the following pricing
assumptions:
USA: $24.00 per barrel of oil and $4.00 per Mcf
Bulgaria: $2.55 per Mcf
Egypt: $25.00 per barrel of condensate and $3.78 per Mcf (Qantara) and $2.50 per
Mcf (El Mansoura)
The discounted net present value is calculated on the basis of these commodity
prices and of estimates of capital and operating costs at current prices with
the resulting net cashflows being discounted at 10% per annum. The discounted
net present value valuation is not necessarily an indication of realisable
market value.
Consolidated summarised profit and loss account
Year ended 31 December 2003
2003 2002
Note #000 #000 #000 #000
Turnover
Continuing activities 6,955 4,375
Discontinued activities - 2,749
_________ _________
6,955 7,124
Cost of sales (1,713) (4,135)
Depletion (1,161) (958)
_________ _________
Gross profit 4,081 2,031
Administrative expenses (2,861) (2,642)
_________ _________
Operating profit/(loss)
Continuing activities 1,220 (437)
Discontinued activities - (174)
_________ _________
1,220 (611)
Net interest payable (911) (1,465)
_________ _________
Profit/(loss) on ordinary activities before taxation 309 (2,076)
Taxation on profit on ordinary activities 3 2,487 (156)
_________ _________
Profit/(loss) for the year transferred to reserves 2,796 (2,232)
_________ _________
Earnings/(loss) per share (p) 4 6.3 (13.6)
_________ _________
Diluted earnings per share (p) 4 6.0 n/a
_________ _________
Consolidated summarised balance sheet
As at 31 December 2003
2003 2002
#000 #000
Fixed assets
Intangible assets 6,264 5,297
Tangible assets 82,397 40,410
Investments - 7
_________ _________
88,661 45,714
_________ _________
Current assets
Debtors: Amount falling due after more than one year 4,519 2,181
Amount falling due within one year 5,946 900
_________ _________
10,465 3,081
Cash at bank and in hand 3,425 460
_________ _________
13,890 3,541
Creditors: amounts falling due within one year (15,148) (9,257)
_________ _________
Net current liabilities (1,258) (5,716)
_________ _________
Total assets less current liabilities 87,403 39,998
Creditors: amounts falling due after more than one year (32,095) (17,875)
Provision for liabilities and charges (4,127) -
_________ _________
51,181 22,123
_________ _________
Capital and reserves
Called up share capital 6,260 1,639
Share premium account 48,58921,660
Other reserves (5,091) 197
Profit and loss account 1,423 (1,373)
_________ _________
Equity shareholders' funds 51,181 22,123
_________ _________
Consolidated summarised cashflow statement
Year ended 31 December 2003
Note 2003 2002
#000 #000
_________________________________________________________________________________________________________
Net cash (outflow)/inflow from operating activities 5 (2,509) 461
_______________________________________
Returns on investments and servicing of finance
Interest paid (1,001) (1,163)
Interest paid by discontinued activity - (22)
Interest received 36 27
_______________________________________
Net cash outflow from returns on investments and (965) (1,158)
servicing of finance _______________________________________
Tax paid (835) (156)
_______________________________________
Capital expenditure and financial investment
Purchase of intangible fixed assets (7,832) (2,184)
Purchase of tangible fixed assets (30,305) (5,385)
Purchase of tangible fixed assets by discontinued - (41)
activity
Disposal of tangible fixed assets 279 122
Disposal of fixed asset investments 13 -
_______________________________________
Net cash outflow from capital expenditure and financial (37,845) (7,488)
investment _______________________________________
Financing
Borrowings raised 28,137 12,382
Repayment of borrowings (14,240) (4,956)
Issue of shares 32,306 -
Issue costs(756) -
_______________________________________
Net cash inflow from financing 45,447 7,426
_______________________________________
_______________________________________
Increase/(decrease) in cash 3,293 (915)
_______________________________________
Notes to the financial information
Year ended 31 December 2003
1. Statement of total recognised gains and losses
2003 2002
#000 #000
_____________________________________________________________________________________________________
Profit/(loss) for the year 2,796 (2,232)
Currency translation difference on foreign currency net investment (5,288) (3,465)
__________________________
(2,492) (5,697)
__________________________
2. Reconciliation of movements in shareholders' funds
2003 2002
#000 #000
Total recognised gains and losses (2,492) (5,697)
Dividends paid and proposed - -
___________________________
(2,492) (5,697)
New shares issued 31,550 -
___________________________
Net increase/(decrease) in shareholders' funds 29,058 (5,679)
Opening shareholders' funds 22,123 27,820
___________________________
Closing shareholders' funds 51,181 22,123
___________________________
3. Taxation
The taxation credit/(charge) is based on the result for the year, after taking
into account losses brought forward from previous periods, and comprises:
2003 2002
#000 #000
_____________________________________________________________________________________________________
Current tax
Overseas taxes (835) (156)
___________________________
Deferred tax
Timing differences (3,025) -
Tax losses 6,347 -
___________________________
3,322 -
___________________________
___________________________
Tax on profit on ordinary activities 2,487 (156)
___________________________
4. Earnings per share
Earnings per share has been calculated by dividing the profit after taxation for
the year ended 31 December 2003 of #2,797,000 (2002: loss of #2,232,000) by the
weighted average number of shares in issue throughout the year of 44,371,485
(2002: 16,390,765).
The calculation of fully diluted earnings per share is based on the profit after
taxation and after adding the interest income net of corporation tax which would
have arisen had all the ordinary share options granted under the Company's
various schemes been exercised on the first day of the financial year, or at the
date granted if later, and the proceeds invested in 21/2 % Consolidated Stock on
that day. The amount so derived has been divided by the number of ordinary
shares in issue at the beginning of the year together with the weighted average
number of shares assumed to have been issued as indicated above. There is no
diluted earnings per share for 2002 as the share options were anti-dilutive at
that time.
5. Net cash (outflow)/inflow from operating activities
2003 2002
#000 #000
_____________________________________________________________________________________________________
Operating profit /(loss) 1,220 (611)
Depletion and depreciation 1,190 1,131
Non-cashflow from disposal of subsidiary - 2,780
(Gain)/loss on disposal of fixed asset investment (6) 3
Decrease in stocks - 889
Increase in debtors (4,435) (1,587)
Decrease in creditors (478) (2,144)
___________________________
Net cash (outflow)/inflow from operating activities (2,509) 461
___________________________
6. 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 2002. 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 2003
will be delivered to the Registrar.
The summarised balance sheet at 31 December 2003 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 in early May 2004 and will be
available from the Company's registered office, No. 1 Portland Place, London W1B
1PN, or from the Company's website at www.melroseresources.com from that date.
Glossary
the Adair Trusts certain trusts, the beneficiaries of which are R F M Adair and
members of his immediate family
bbl barrel of oil or condensate
Bcf billion cubic feet of gas
Bcfe billion cubic feet of gas 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 Combined Code the Principles of Good Governance and Code of Best Practice as
appended to the Listing Rules of the Financial Services
Authority
the Company Melrose Resources plc
EBITDA earnings before interest, taxation, depletion, depreciation
and amortisation
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 orthe Group, as appropriate
MMbbl million barrels of oil or condensate
MMboe million barrels of oil equivalent
MMcf million cubic feet of gas
MMcfe million cubic feet of gas equivalent
MMcfpd million cubic feet of gas per day
NPV10 net present value discounted at 10% per annum
PDP proved developed producing
Petreco Petreco S.a.r.l. and/or Petreco Bulgaria EOOD as appropriate
psi pounds per square inch
PUD proved undeveloped
Tcf trillion cubic feet of gas
Wyoming Ethanol Wyoming Ethanol LLC, a former subsidiary of the Group
This information is provided by RNS
The company news service from the London Stock Exchange
END
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