| Mon 14 Oct 2002, 10:07 | | Energy Africa Limited - Interim Results For The Si |
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Energy Africa Limited - Interim Results for the six months ended 30 September
2002
Energy Africa Limited
Registration number: 1995/007140/06
(Incorporated in the Republic of South Africa)
JSE code: ENR ISIN code: ZAE000010427
Interim Results for the six months ended 30 September 2002
Energy Africa, the South African-based international oil and gas exploration and
production company which is listed on the Johannesburg and Luxembourg Stock
Exchanges, today reports an increase in cash flows to $61 million and increased
average production to 22 540 bpd.
Discovery of the Abang field, and of an extension to the Elon field
Excellent results from two appraisal wells in the Elon field
Successful development of Alba Extreme South, Niungo and Etame fields, adding
significantly to current capacity
Average production increased to 22 540 bpd
Cash inflow from operations increased by 4% to $61 million
Strong balance sheet maintained, with net cash position at period end
Significant progress in formulating phased development plans for the Northern
Block G fields
Key terms of additional $75 million credit facilities agreed
Commenting on the results, Rhidwaan Gasant, Managing Director of Energy Africa
said:
"These excellent results further accentuate our remarkably successful track
record over the last few years. With our continued increases in cash flows, our
strong balance sheet and our prospects for the future, we are well positioned to
grow our active exploration and development programme."
14 October 2002
Enquiries:
Energy Africa +27 21 400 7600
Rhidwaan Gasant
College Hill
Nicholas Williams +27 11 447 3030
Matthew Gregorowski +44 20 7457 2020
Overview
In the six month period to September 2002 a high level of development, appraisal
and exploration activity was sustained. Development drilling continued
throughout the period in our main producing fields, Ceiba in Equatorial Guinea
and Alba in the UK North Sea where the first phase of the Alba Extreme South
development was successfully completed. Additionally the Niungo field onshore
Gabon was brought onstream and the production well for the Caledonia field in
the North Sea was completed. The benefit of most of these development
activities will only be seen in the second half of the year. In line with our
forecasts, oil production at 22 500 bpd, was virtually the same as for the
comparable period in 2001, and 10% above the 20 500 bpd recorded in the previous
six months. Realised oil prices showed a small increase relative to the
comparable period in 2001, resulting in a 13% increase in turnover to $89.4
million and a 4% increase in cash inflow from operations to $60.7 million. The
high level of exploration activity and Energy Africa`s accounting treatment
thereof resulted in net profit of $15.5 million compared with $22.1 million in
2001.
The five exploration wells completed in the period yielded two oil discoveries -
the Elon Extension and Abang field in Block G in Equatorial Guinea. These
discoveries, in shallow water, significantly enhance the economics of the
phased, integrated development of the fields in Northern Block G, which provide
the major platform for the continued growth of the company. Three successful
appraisal wells including one in the Oveng field and two in the Elon field were
drilled in the period and development plans for the three fields comprising the
first phase of the envisaged integrated development are scheduled to be
submitted for approval by first quarter 2003.
An unsuccessful appraisal well was drilled in the Kudu field in Namibia.
Producible reservoir facies was not encountered but it is nevertheless
considered that sufficient reserves are present to support an export project to
the Western Cape. Following the operator`s withdrawal, Energy Africa`s interest
will increase to 40% and, together with the new operator, ChevronTexaco, we are
re-evaluating all aspects of the project.
The coming six months will see a continuation of a high level of development and
exploration activity. Development drilling will continue in the Ceiba and Alba
fields and we expect to complete 12 exploration wells, two of which are
currently in progress. Production is set to increase substantially and we
expect an average of some 27 000 bpd in the next six months resulting in an
average of about 25 000 bpd for the full financial year. This is in line with
our forecast made at the time of our year end results announcement, despite a
subsequent minor reduction in Ceiba production estimates for the 2002 calendar
year. This level of production will result in a significant improvement in our
financial performance, assuming oil prices remain at the first half levels.
This, together with the loan facilities in place and agreed in principle, will
enable our planned developments to be financed without recourse to equity
funding.
As you are aware, an offer by Petronas International Corporation Limited for the
shares in the company not held by Engen Limited was made in September, and the
bid process is continuing.
Financial review
Summary
Energy Africa reports yet another set of solid financial results. Cash flow
increases and our strong balance sheet enable the Company to pursue its active
reinvestment program without recourse to the equity markets.
Cash flows
Net cash inflow from operations increased 4% to $60.7 million from $58.3 million
in 2001.
Exploration expenditure increased to $19.4 million compared to $8.9 million in
2001 reflecting the higher level of drilling activity. Development expenditure
was $41.3 million, most of which was spent in Equatorial Guinea and the UK North
Sea (2001: $41.6 million).
Loan drawdowns during the period amounted to $10.0 million (2001: repayments of
$4.6 million). The resulting net cash inflow after financing was $5.6 million
(2001: outflow of $0.4 million).
Income statement
Turnover increased by 13% from $79.4 million in 2001 to $89.4 million reflecting
a 7% increase in volumes sold and a 5% increase in the realised oil price,
despite a 1% reduction in the average Brent oil price over the period. Turnover
is reflected after delivering 0.5 MMbbl (2001: 0.4 MMbbl) of hydrocarbons to
host governments in terms of Production Sharing Agreements.
Cost of production was $42.3 million compared to $34.2 million in 2001. On a
per barrel basis, operating costs were $4.18 per bbl (2001: $3.96), the increase
being due to the Alba shut down, but this is expected to decrease in future as
Alba production increases. Depletion charge was $4.86 per bbl (2001: $4.08),
reflecting the greater contribution of the deep water Ceiba field which has a
higher cost per barrel. Total cost of production, excluding the effect of
movement in oil inventories, was $9.75 per bbl (2001: $8.80 per bbl).
The exploration charge increased to $17.1 million from $9.8 million in 2001, as
a direct result of the more active drilling program. Administration charges
increased to $7.3 million (2001: $3.3 million) mainly due to higher professional
fees. Net operating income was $22.3 million (2001: $31.8 million), the
decrease mainly due to the increase in exploration charge.
Taxation decreased to $6.1 million (2001: $9.5 million) following the lower
revenue from the Oribi field in South Africa.
Net profit after taxation was $15.5 million (2001: $22.1 million).
Balance sheet
Fixed assets were $220.3 million and comprise mainly the net book values of
producing assets. Net current assets were $24.4 million and include cash of
$23.9 million. Loans were $20.0 million resulting in a net cash position at 30
September 2002 of $3.9 million. Additional credit facilities of $75 million
have been agreed in principle and a term sheet signed.
Operating review
Production and Development
Energy Africa`s working interest share of production for the six months to 30
September 2002 was 4 125 000 bbl of oil and LPG, an average of 22 540 bpd
compared with 22 380 bpd for the same period in 2001. This 1% increase in
production reflects a 73% increase from the Ceiba field to 8 860 bpd, offset by
a short term 38% decrease in production from the Alba field in the UK North Sea
where the natural decline rate was accompanied by the planned 21 day platform
shutdown in July for installation of additional facilities ahead of Alba Extreme
South coming onstream in October 2002, when this decline in production will
reverse. There were further natural declines of the Nkossa field in the Congo
and from the Oribi field in South Africa, where production for the latter is
expected to cease in the next twelve months.
The average benchmark Brent oil price for the period was $26.00 per bbl (2001:
$26.32 per bbl). The average price realized was $23.99 per bbl (2001: 22.81 per
bbl) a discount of 8% (2001: 13%). The reduced average discount,
notwithstanding the higher proportion of lower value Ceiba crude, was due
largely to the elimination of an "introduction discount" for the Ceiba oil and
an improvement in its quality from 28x API to 30x API as wells from the northern
area of the field were brought onstream.
A high level of development activity was seen in the period, much of which will
only contribute to production in the second half of the year when Alba Extreme
South, the Niungo and Etame fields in Gabon and additional wells in the Ceiba
field will come onstream. These developments are discussed more fully in the
country reviews.
Exploration and appraisal
Since 1 April 2002, the company has participated in seven exploration wells, two
of which are still in progress. Of the five completed wells two resulted in oil
discoveries, two had good oil shows and one was dry. Four appraisal wells were
completed, of which three were successful and one unsuccessful in confirming
commercial reserves. The details of these wells are dealt with in the country
reviews.
Congo (Brazzaville)
Production from the Nkossa field (Energy Africa 4%) averaged 47 700 bpd of oil
and LPG (2001: 58 590 bpd). Development plans for the Moho-Bilondo fields were
substantially progressed although a final decision on the development plan has
not yet been made. Nevertheless it is expected that an application for an
exploitation permit will be made by end-October 2002.
It remains the intention of the parties in the Joint Development Area to drill a
well to test the potentially large Nkoumbi structure once all the outstanding
issues have been resolved with the Angolan and Congolese authorities. It is now
likely that the well will not be drilled until 2003.
Egypt
As reported at year-end the operator of the Obaiyed production area which
adjoins the Matruh exploration licence (Energy Africa 20%) drilled a well close
to the Matruh boundary. Good quality reservoir was intersected below the
regional gas-water contact. Detailed mapping of the updip extension into the
Matruh licence suggests, however, that gas volumes are sub-commercial. As
previously noted, several oil prospects have been identified in the Matruh
licence and a well is scheduled for March 2003.
Equatorial Guinea
Oil production in the Ceiba field (Energy Africa 14.25%) averaged 62 200 bpd
(2001: 35 900 bpd), a 73% increase on the comparable period. This reflects the
addition of the Ceiba -5, 8, 10 and 13 production wells, as well as the
successful implementation of the water injection programme with four injectors
being operational at the end of the period. Production, although close to
forecast, was affected by a screen failure in the Ceiba-2 well which has
resulted in Ceiba-2 and Ceiba-7, which share a flow line, being shut-in for most
of the period. Remedial action is planned for early 2003 following the
completion of the Phase1A drilling programme.
Development drilling continues and by end-2002, two further production wells and
one water injector are scheduled for completion. Additionally multi-phase
subsea pumps will be installed at the Ceiba-3 and Ceiba-4 wells in October,
which will result in a further increase in flow rates. Further production wells
are likely to be drilled in calendar year 2003. Their locations will be
dependent on reservoir performance.
As previously reported two exploration wells (G9 and G10) in Block G (Energy
Africa 15%) resulted in the Elon Extension and Abang discoveries. These were
followed by two exploration wells in Block F (Energy Africa 15%), which did not
result in commercial discoveries although the F-3 well did have good oil shows
and source rock development. In addition to the five exploration wells, three
appraisal wells were drilled in the period. Two of these successfully
delineated the Elon field, confirming the presence of a very significant reserve
base of good quality oil at shallow depths below the seafloor (800-1100m) and in
shallow water (40-70m), attributes which considerably enhance the development
economics. Successful appraisal wells were also drilled in the Oveng field.
Development plans for the Oveng, Okume and Elon fields, comprising the first
phase of the integrated development of the six Northern Block G fields, are
expected to be submitted for approval by first quarter 2003.
At the end of the period the G11 exploration well in the southern platform area,
some 20km south east of the Ceiba field, was in progress.
It is anticipated that a further seven exploration wells will be drilled by end-
March 2003 to test prospects and plays in unexplored areas of Blocks F and G,
although early drilling of low risk prospects north and south of the Elon
discovery may be advanced in the schedule.
Gabon
Energy Africa`s production in Gabon, being its equity share of production
attributable to Energy Africa Gabon SA ("EAGSA"), in which it holds a 50%
interest, averaged 6 900 bpd for the period (2001: 7 000 bpd). There was a
slower than anticipated decline in the Tchatamba complex (Marin, South and West)
and increased production from the successful step-out drilled in the Turnix
field in February. Natural production decline from the existing fields in Gabon
will be offset to some degree by new production from the Niungo (EAGSA 40%) and
Etame (EAGSA 7.5%) fields and from the development of the Azile reservoir in the
Tchatamba South field.
Three wells in the onshore Niungo field, located some 40km east of the Echira
field (EAGSA 40%) to which it is linked by oil and gas pipelines, were completed
for production and came onstream in mid-September. The production rate at month
end was 4 500 bpd and is expected to rise to over 6 000 bpd when all wells are
in production. Further development will be considered in the event that
reservoir performance confirms a larger reserve base.
Also in September, the Etame field offshore southern Gabon, was brought online
at an average oil rate of about 14 500 bpd. EAGSA will exercise its option to
take a 7.5% interest in the field and, in due course, any other developments in
the Etame permit which still has significant exploration potential. Further
development wells are planned in the Moukouti (EAGSA 40%), Echira (EAGSA 40%)
and Limande (EAGSA 20%) fields in the remainder of the year.
An exploration well was drilled in the Limande exploitation permit (EAGSA 20%)
in April but intersected only poorly developed reservoir facies. Exploration
wells were also drilled in the deepwater areas of the Mpolo and Chaillu permits
in which EAGSA has participation rights in the event of a discovery, however
neither well was successful. Potential for oil accumulations, of the Tchatamba-
type, remains in the shallow water area of the Chaillu permit contiguous with
the Akoum permit (EAGSA 100%), which was acquired in April 2002. EAGSA intends
to drill two wells in the Akoum permit, where relatively low risk Tchatamba-type
prospects have been mapped, in April-May 2003, the timing being dependent upon
rig availability. A high resolution aeromagnetic survey was flown over an area
of some 600km in the Ofoubou-Akani permit (EAGSA 60%) but results were not
encouraging and the permit will be relinquished. Elsewhere in Gabon an
exploration well is scheduled in the onshore Nziembou permit (EAGSA 40%) in
December.
Mauritania
In September 2002, Energy Africa secured a 32% interest in the offshore Block 1,
consolidating its acreage position in this area where it also has a 20% interest
in Block 2. A 1 000 sq.km 3-D seismic survey was acquired in Block 2 in June
and July and a 1 300 sq.km survey is scheduled to commence in Block 1 in October
2002. The Mauritania salt basin has a variety of oil plays and a working
petroleum system has been proved in Block 4 to the north by Woodside`s
Chinguetti discovery and recent successful appraisal well. In the remainder of
the year, the 3-D seismic surveys in Blocks 1 and 2 will be processed and
interpreted, and given confirmation of the prospects seen on the previous 2-D
seismic surveys, drilling could commence late in 2003 or in 2004.
Morocco
As previously communicated, Energy Africa has established a large acreage
position in the Tarfaya salt basin in Morocco. In the Cap Draa concession
(Energy Africa 20%) a 2 200 sq.km 3-D seismic survey was acquired in 2001 and a
further 1 400 sq.km is currently being acquired. The datasets will be
integrated and reprocessed and interpretation is expected to commence in January
2003 with drilling likely in early 2004. In the Tiznit concession (Energy
Africa 32% and operator) the 3-D seismic data acquired in 2001 has been
interpreted and detailed work to mature several prospects is in progress.
Namibia
The Kudu-6 appraisal well in Licence 2814A (Energy Africa 40%) in Namibia was
completed in April. The well, located some 27km north of the main field area,
failed to prove the very large reserve required for a floating LNG project.
This was followed by the Kudu-7 well located on the far western flank of the
Kudu field. The well intersected only very poorly developed reservoir facies.
The primary objective of increasing proved reserves to a level that would
support gas export to the Western Cape was not achieved by that well. It is,
however, still believed that there are sufficient reserves for this purpose. In
August the operator, Shell, with a 75% interest announced its intention to
withdraw from Licence 2814A. Following the withdrawal, Shell`s interest will
accrue proportionally to the remaining partners and Energy Africa`s interest
will thus increase to 40% at no cost. ChevronTexaco with 60% will become the
operator. The partners intend to re-evaluate all the technical and commercial
aspects before making a decision on a way forward.
South Africa
Oil production from the Oribi field (Energy Africa 20%) averaged 3 700 bpd
(2001: 6 640 bpd) which was in line with the forecast and production is expected
to cease in 2003.
Uganda
Following interpretation of the newly and previously acquired 2-D seismic data
in Block 3 (Energy Africa 50%) a well location was agreed and the Turaco-1 well
commenced drilling in mid-September. The well is expected to intersect the
target intervals in late October. In Block 2 (Energy Africa 50%), a 2-D seismic
survey is expected to commence early in 2003. The prospective area in Block 2
is almost wholly overlain by Lake Albert and the survey will also cover that
portion of Block 3 which is below the lake.
United Kingdom
The Alba field in the Central North Sea (Energy Africa 8%), averaged 51 500 bpd
(2001: 82 500 bpd) which was below forecast primarily due to a longer-than-
anticipated platform shutdown (to accommodate installation of facilities for the
Alba Extreme South development) and operational problems. However, the Alba
Extreme South development has proceeded smoothly and on time and within budget.
First oil was achieved on 1 October 2002 and production is expected to be
restored to the levels achieved in 2001. The development well in the Caledonia
field (Energy Africa 10%) was completed on schedule but first oil, at a rate of
some 12 000 bpd, has been delayed, probably to early 2003, due to installation
of process and export facilities on the Britannia platform being postponed
because of operational problems on that facility.
Future operational activity
In the six months to 31 March 2003 Energy Africa`s net production is expected to
increase to some 27 000 bpd and average production for the full year is expected
to be approximately 25 000 bpd as forecast at year end.
Exploration and appraisal wells in the next period include one well in the
Congo, seven wells in Equatorial Guinea, three wells in Gabon (including two in
which EAGSA does not contribute to costs) and one in Egypt. Energy Africa`s
expenditure associated with this programme is estimated to be of the order of
$24 million.
This interim report is signed on behalf of the Board.
Tunku M Fawzy b.Tunku Muhiyiddin
R Gasant
11 October 2002
Directors: Dato` M Idris Mansor (Chairman) (Malaysian), R Gasant (Managing),
P J G Elwes (British), Tunku M Fawzy b.Tunku Muhiyiddin (Malaysian), W A Nel, L
M Nyhonyha, G B D Paul (Malaysian), F M J L Poimboeuf (French), A G Windham
(British)
Company Secretary: W H Torr
Group income statement
10.4412 6.2167 7.3245
Six months Six months Year ended
to to
30 Sep 2002 30 Sep 2001 31 Mar 2002
(Reviewed) (Reviewed) (Audited)
$`000 $`000 $`000
Total revenues
89,629 80,024 144,907
Turnover (note 2)
89,412 79,411 143,996
Cost of production (note 3)
(42,267) (34,207) (74,822)
Gross income
47,145 45,204 69,174
Exploration expenditure written off
(17,130) (9,771) (26,845)
Administration expenses
(7,282) (3,261) (7,869)
Other operating costs
(471) (377) (50)
Operating profit
22,262 31,795 34,410
Interest income
217 613 911
Interest expense
(872) (719) (2,162)
Profit on ordinary activities
before taxation 21,607 31,689 33,159
Taxation (note 4)
(6,063) (9,541) (12,588)
Profit on ordinary activities after
taxation and attributable to 15,544 22,148 20,571
ordinary shareholders
Earnings/headline earnings per
share - cents
Basic 15.1 21.7 20.1
Diluted 14.9 21.5 19.9
Weighted average number of ordinary
shares
in issue (`000)
Basic
103,059 101,921 102,124
Diluted
104,168 102,796 103,161
Group balance sheet
10.5850 6.5450 8.0101
30 Sep 2002 30 Sep 2001 31 Mar 2002
(Reviewed) (Reviewed) (Audited)
$000 $000 $000
Employment of assets
Fixed assets
220,345 167,641 199,198
Current assets
Inventories
3,793 6,368 5,683
Debtors
26,885 14,521 18,906
Cash and bank deposits
23,942 28,229 18,765
54,620 49,118 43,354
Current liabilities (note 5)
(30,250) (17,833) (36,163)
Net current assets
24,370 31,285 7,191
Total assets less current
liabilities 244,715 198,926 206,389
Long term loan
(20,000) - (10,000)
Deferred tax
(17,738) (11,307) (10,712)
Decommissioning provision
(21,007) (18,391) (19,059)
185,970 169,228 166,618
Capital employed
Share capital
2,645 2,635 2,642
Share premium account
101,980 100,655 101,525
Retained income
100,483 86,516 84,939
Other reserves
(19,138) (20,578) (22,488)
Shareholders` interest
185,970 169,228 166,618
Net book value per share - cents
Basic 180.1 165.7 161.9
Diluted 178.4 164.4 160.9
Number of ordinary shares in issue
at period end (`000)
Basic
103,233 102,159 102,913
Diluted 104,237
102,960 103,582
Group cash flow information
Six months Six months Year ended
to to
30 Sep 2002 30 Sep 2001 31 Mar 2002
(Reviewed) (Reviewed) (Audited)
$`000 $`000 $`000
Reconciliation of operating profit
to net cashflow from operations
Operating profit
22,262 31,795 34,410
Exploration expenditure written off
17,130 9,771 26,845
Depreciation
20,365 16,950 36,123
(Profit)/loss on disposal
(9) - 17
Exchange loss
471 378 50
Net cash inflow from operations
60,219 58,894 97,445
prior to working capital
adjustments
Working capital adjustments
445 (589) (1,909)
Net cash inflow from operations
60,664 58,305 95,536
Cash flow statement
Net cash inflow from operations
60,664 58,305 95,536
Returns on investments and
servicing of finance
Interest received
217 621 919
Interest paid
(351) (344) (1,287)
Tax paid
(4,654) (4,678) (12,062)
Investing activities
Exploration expenditure
(19,432) (8,910) (31,241)
Payments to acquire tangible
assets (41,340) (41,630) (69,305)
Proceeds from sale of fixed
assets 18 - 15
Net cash (outflow)/inflow before
financing (4,878) 3,364 (17,425)
Financing
Issue of ordinary shares
458 837 1,714
Increase in bank loan
10,000 - 10,000
Repayment of loans
- (4,591) (4,591)
Net cash inflow/(outflow) after
financing 5,580 (390) (10,302)
Cash flow from operations per share
-cents
Basic
58.9 57.2 93.5
Diluted
58.2 56.7 92.6
Group statement of changes
in equity
Share Exchange
Share premium Retained translation
capital account income reserve Total
$`000 $`000 $`000 $`000 $`000
Group
At 30 September 2001
2,635 100,655 86,516 (20,578) 169,22
Loss attributable to
ordinary shareholders - - (1,577) - (1,57
Exchange adjustment
- - - (1,910) (1,910
Arising on issue of shares
7 870 - - 877
At 31 March 2002
2,642 101,525 84,939 (22,488) 166,61
Profit attributable to
ordinary shareholders - - 15,544 - 15,54
Exchange adjustment
- - - 3,350 3,350
Arising on issue of shares
3 455 - - 458
At 30 September 2002
2,645 101,980 100,483 (19,138) 185,97
Auditors Report
The financial information for the six months ended 30 September 2002 set out
from and including the Group income statement up to and including the notes has
been reviewed, but not audited, by the Company`s auditors, Ernst & Young. The
review report is unqualified and is available for inspection at the Company`s
registered office.
Notes
1. Accounting policies
The financial information is expressed in United States Dollars and has been
prepared in accordance with accounting policies which conform with International
Accounting Standards and South African Statements of Generally Accepted
Accounting Practice. These accounting policies are consistent with those stated
in the annual report for the year ended 31 March 2002.
Six months Six months Year ended
to to
30 Sep 2002 30 Sep 2001 31 Mar 2002
(Reviewed) (Reviewed) (Audited)
$`000 $`000 $`000
2. Turnover
Africa
70 352 53 796 99 621
Non-Africa
19 060 25 615 44 375
89 412 79 411 143 996
3. Cost of production
Operating costs
17 244 16 232 35 147
Movement in underlift
2 033 (1 844) (1 039)
Royalty paid in cash
2 948 3 103 5 240
Depreciation
20 042 16 716 35 474
42 267 34 207 74 822
4. Taxation
Corporation tax - current
680 6 727 10 694
- prior
( 399) ( 7) ( 686)
Deferred tax - current
5 038 2 821 2 580
- rate change
744 - -
6 063 9 541 12 588
5. Current liabilities
Corporation tax payable
1 748 9 560 245
Other creditors and accruals
28 502 8 273 35 918
30 250 17 833 36 163
6. Capital commitments
Contracted and approved
22 304 34 213 42 861
7. Production MMbbl MMbbl MMbbl
Group share of production
4.1 4.1 7.8
Delivered to host governments
( 0.5) ( 0.4) ( 0.7)
Movements in underlift
0.2 ( 0.2) -
Group production sold
3.8 3.5 7.1
Summary Rand convenience translation
Six months Six months Year ended
to to
30 Sep 2002 30 Sep 2001 31 Mar 2002
R million R million R million
Income statement
Turnover
934 652 1 374
Operating profit
232 261 328
Net profit
162 182 196
Earnings / headline earnings per
share - cents 158 178 192
Cash flow
Cash flow from operations
633 479 912
Exploration expenditure
203 73 298
Development expenditure
432 342 661
Cash inflow from operations per
share - cents 615 470 893
Balance sheet
Fixed assets
2 332 1 510 2 264
Cash
253 254 214
Loans
212 - 114
Net cash
41 254 100
Net assets
1 969 1 524 1 894
Net book value per share - cents
1 907 1 492 1 840
R/$ exchange rate (period average) 10.44 8.21 9.54
R/$ exchange rate (period end) 10.59 9.01 11.37
Date: 14/10/2002 07:12:04 AM Produced by the JSE SENS Department
