| Thu 23 May 2002, 0:00 | | Energy Africa Limited - Preliminary Results For Th |
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Energy Africa Limited - Preliminary Results For The Year Ended 31 March 2002
ENERGY AFRICA LIMITED
Registration number: 1995/007140/06
(Incorporated in the Republic of South Africa)
JSE code : ENR
ISIN code : ZAE000010427
PRELIMINARY RESULTS FOR THE YEAR ENDED 31 MARCH 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, reports a 21% increase in average production and
substantial increase in oil reserves.
* Five significant discoveries in Equatorial Guinea to the year end and
further success thereafter
* Major potential for further discoveries
* Average production increased by 21% to 21 400 bpd
* Commercial oil reserves rose by 22% to 58 million barrels
* Potentially commercial oil reserves rose by 118% to 37 million barrels
* Cash inflow from operations was up 2% to $96 million, despite 18% lower
average oil price and planned Ceiba shut down
* Strong balance sheet to support future activity
* Important additions to exploration portfolio
* Active development program
Commenting on the results, Rhidwaan Gasant, Managing Director of Energy
Africa, said:
"This has been a highly successful year for Energy Africa. We have achieved
considerably higher production levels and had outstanding exploration
success which has all been financed out of our cash resources. We are very
confident about the future with a busy exploration and development line-up.
We look forward to an exciting and active exploration and development
program ahead."
23 May 2002
Enquiries:
Energy Africa Limited
Rhidwaan Gasant
Adrian Nel
Tel: +27 21 400 7600
Corporate Image, Cape Town
Tamra Veley
Tel: +27 21 426 1233
College Hill, London
Nicholas Williams
Tel: +44 20 7457 2020
Chairman`s statement
Since my last statement twelve months ago your Company has enjoyed
phenomenal success with its exploration drilling activities in Equatorial
Guinea. With significant additional prospectivity on Blocks F and G, the
Company is well positioned for further success there.
There has also been encouraging progress in relation to the Company`s
development project portfolio in Congo, the United Kingdom Continental
Shelf, Gabon and Equatorial Guinea. Importantly also, the Company`s
exploration portfolio has been expanded through the acquisition of new
exploration acreage in Uganda, Mauritania and Gabon. The asset base of the
Company is under constant review so that appropriate portfolio management
decisions can be made.
During the period total commercial oil reserves increased by 22% to 58
million barrels and potentially commercial oil reserves increased by 118% to
37 million barrels. Production increased by 21% to 21 400 barrels per day.
Cash flow from operations increased despite the significantly lower oil
prices ruling during the year. Your Company`s balance sheet remains strong
with net cash at the year-end, having funded an active development and
exploration program entirely from internal cash resources. The active
development program will require external funding - the $50 million limited
recourse facility secured this year will be augmented by another tranche of
debt. Additional funding will be required when the optimised development of
the Okume/Oveng complex is implemented and there is more time to consider
the available options in this regard.
Oil prices have remained strong notwithstanding a period when the demand
side has been weak, particularly after the tragic events of September 11
2001. Although short-term market fundamentals combined with continuing
political tensions in the Middle East have underpinned crude oil prices,
these are likely to remain volatile. Fortunately your company`s business
remains resilient to lower oil prices.
During the financial year, our partner and operator in Equatorial Guinea
Triton Energy, was acquired by Amerada Hess. We are pleased to report that
the very good working relationship we have had with Triton has continued
with our new partner, who brings valuable deep water operating experience to
the joint venture. It is also encouraging that Amerada and industry
analysts consider the deal to have attributed significant upside, in terms
of future discoveries and value, to Triton`s Equatorial Guinea interest.
Recent excellent performance by Exploration and Production companies in the
United Kingdom where many of your Company`s peers are domiciled, has
rekindled interest in the Exploration and Production sector there. It is
particularly encouraging that your Company is regarded as one of the pre-
eminent small cap E&P companies in that sector.
I believe that your Company is well positioned to achieve substantial future
growth in its net asset value per share.
As reported in this year`s Interim Report, Rhidwaan Gasant was appointed to
the Board as Managing Director in August 2001. At that time, he was joined
on the Board by Andrew Windham as Commercial Director, while Adrian Nel was
appointed Chief Operating Officer. Since then both Almorie Maule and Ahmad
Said have resigned from their positions as non-executive directors and I
would like to thank them both, on behalf of the Company, for their
significant contributions whilst serving on the Board.
I am very pleased to welcome in their places as non-executive directors,
George Paul, who joined the Board in March and Tunku M Fawzy bin Muhiyiddin,
the new Chief Executive of Engen Petroleum Ltd, who joined the Board in
April.
Once again I would like to record my gratitude and appreciation to the
management and staff at Energy Africa for all their hard work and commitment
during this extraordinarily successful year. Their contribution is, as you
will be well aware, vital to the continued success of your Company.
Dato` M Idris Mansor
Chairman
Managing director`s review
It gives me great pleasure to present my first review as Managing Director
at a time when Energy Africa has enjoyed the most successful period in its
history.
The Company has achieved almost continuous success with its exploration
drilling activities in Equatorial Guinea - its last six exploration and four
of five appraisal wells there have been successful. What is even more
encouraging is that there is still significant additional prospectivity on
the Blocks and several exploration wells are expected to be drilled there in
the next twelve months.
In total, nine exploration wells and nine appraisal wells were drilled, 13
of which were successful and one of which has been suspended as a potential
water injection well. This excellent level of performance with the drill bit
has deservedly attracted most attention, but there has been considerable
activity elsewhere in the business.
In the Congo, following the successful Bilondo appraisal well, development
of the field is likely to proceed if the tendering process results in an
acceptable capex profile. The successful test of the Nkossa South South
prospect has also added significant incremental reserves to the Nkossa
field. On the UK Continental Shelf, the Alba Extreme South and Caledonia
developments were approved and are on schedule for first oil production in
October 2002. As a consequence of the additional discoveries close to Okume
and Oveng in Equatorial Guinea, the opportunity to optimise the development
of the whole complex is being pursued in order to minimise development cost
through economies of scale.
As reported at the Interim stage we have acquired new exploration acreage in
Uganda and drilling on one of the licences is expected to take place later
this year. Since then we have also acquired a new exploration interest
offshore Mauritania and have recently announced the acquisition of a new,
operated, exploration block named Akoum, offshore Gabon in the area
surrounding our existing producing Tchatamba fields.
The result of the Kudu-6 exploration well in Namibia, drilled at a location
some 27km north of the Kudu main field to achieve the magnitude of
additional reserves required for an LNG project, proved disappointing. The
well failed to intersect the aeolian (dune) sand reservoir present in the
main field, and the floating LNG project has therefore been shelved for the
immediate future. An appraisal well, Kudu-7, sited to prove additional
reserves for the South African market, is currently being drilled.
Commercial oil reserves have increased from 47 million to 58 million barrels
after production during the period of 8 million barrels. Potentially
commercial oil reserves have increased from 17 million to over 37 million
barrels. Gas reserves have remained unchanged.
Notwithstanding the anticipated temporary reduction in production levels
from Equatorial Guinea, which resulted from declining reservoir pressure
prior to the installation of water injection and the 14 day shutdown during
the successful changeout of the FPSO at Ceiba, average production for the
year increased by 21% to 21 400 barrels per day, exceeding our forecast.
Since the resumption of production at Ceiba, the Company`s share of
production has increased to over 9 000 barrels per day, lifting March 2002
average production for the Company to around 24 000 barrels per day. We
expect average production for the financial year 2003 to approximate 25 000
barrels per day.
The higher production was offset by the significantly lower average oil
price for the current year and the higher per barrel cost of production at
Ceiba (partially as a result of the temporary decline in production)
limiting the increase in net cash inflow from operations of $96 million, to
2%. We expect that cash operating costs per barrel will decline in the year
ahead.
The Company is well placed to pursue growth opportunities in the future with
the strong balance sheet reflecting net cash (after deducting borrowings) of
almost
$9 million at the year-end, having funded the continuing active development
and exploration program from internal cash resources. During the year we
secured a $50 million limited recourse revolving facility based on the Alba
oil field, to fund our development cost program. To date we have drawn $10
million of this facility. We are currently negotiating a further tranche of
debt, which is likely to be completed by the end of the calendar year.
Additional funding will also be required when the optimised development of
the Okume/Oveng complex is implemented, although, as the Chairman has
stated, there is now more time for consideration to be given to the question
of our funding options.
Crude oil prices are, as the Chairman says in his Statement, likely to
remain volatile. Although our business remains resilient to lower oil
prices, we are considering the possibility of some limited form of
protection for the Company from the downside of significantly lower oil
prices, during a period when our active development program is being funded
by increased borrowings.
Turning to the year ahead, we again have a very active development program.
In addition to the Alba Extreme South, Caledonia and Moho-Bilondo
developments, which I have already mentioned, the current phase of the Ceiba
development will be completed with the drilling of three further production
wells and two additional water injectors. Installation of multi-phase subsea
pumps will also commence. In Gabon the onshore Niungo field should come
onstream in September as should the offshore Etame field in which EAGSA has
an option to participate. Further development drilling is also planned for
the Turnix and Limande fields. Development of the complex of fields in the
Okume/Oveng area referred to above, is still in the planning and design
phase but it is anticipated that some development activity will occur in the
current year, in addition to a number of appraisal wells which are planned
to determine reserves and field boundaries more accurately.
Our planned exploration program for the coming twelve months includes at
least eight exploration wells in Blocks F and G in Equatorial Guinea, mainly
to test play fairways away from the area of the current discoveries and a
number of appraisal wells. Additionally we plan two exploration wells in the
recently acquired Akoum permit in Gabon, one in Egypt, one in Uganda and one
or two in the Congo joint development area. We also anticipate that at
least two wells will be drilled in permits in Gabon where EAGSA has the
option to participate in the event of success. An appraisal well is also
currently being drilled in the Kudu licence in Namibia.
Further appraisal drilling may be required in the event of exploration
success elsewhere.
Total development expenditure for the year ahead is estimated at
approximately $85 million, while exploration expenditure is projected at
approximately $35-$45 million. We expect that strong internally generated
cash flows, augmented by appropriate credit facilities will provide the
funding for another active year ahead.
Rhidwaan Gasant
Managing Director
Financial and operating review
Results for the year ended 31 March 2002
In order to reflect Energy Africa`s financial results in a more meaningful
way, the Directors have decided to change the Group reporting currency from
Rands to US dollars. All revenues and almost all costs are US dollar
denominated. The assets and liabilities are also principally in US dollars.
This change brings the company into line with the oil exploration and
production industry worldwide. The comparatives have accordingly been
restated to US dollars.
Summary
Energy Africa reports another set of solid financial results. The group`s
financial performance reflects its sustained growth in production offset by
the significantly lower oil prices over the year. The strong cash
generation, demonstrated in the increase of 2% in cash flow from operations,
enables the group to continue to aggressively pursue its reinvestment plans.
Cash flow
Net cash inflow from operations was $95.5 million (2001: $93.7 million), a
2% increase from 2001. This increase reflects the increase in production of
21% from 17 700 bbl per day in 2001 to 21 400 bbl per day in 2002. Average
oil prices for 2002, however declined by 18% compared to 2001.
Exploration expenditure amounted to $31.2 million (2001: $39.5 million).
Development expenditure comprised $69.3 million (2001: $71.5 million), of
which $46.9 million was in Equatorial Guinea on the development of the Ceiba
field. Net cash outflow before financing was $17.4 million (2001: $31.5
million).
Financing activities resulted in a net cash inflow of $7.1 million (2001:
outflow $3.0 million). Proceeds from the issue of shares was $1.7 million
(2001: $1.3 million). Loan drawings on the $50 million revolving credit
facility amounted to $10.0 million. Loan repayments, comprising mainly the
final repayments on the Nkossa project loans, were $4.6 million (2001: $5.3
million). The resulting net cash outflow after financing was $10.3 million
(2001: $34.5 million).
Income statement
Turnover for the year increased by 4% to $144.0 million from $138.5 million
in 2001. Production sold during the year was 7.1 MMbbl (2001: 5.5 MMbbl),
an increase of 28%, which was largely offset by the 18% decline in the
average realised oil price per barrel to $20.56 from $25.16 in 2001.
Turnover is reflected after delivering 0.7 MMbbl (2001: 0.9 MMbbl) of
hydrocarbons to host governments under the terms of Production Sharing
Agreements.
Cost of production was $74.8 million compared to $50.8 million in 2001. On
a per barrel basis, total cost of production was $9.56 per barrel (2001:
$7.86 per bbl). Cash operating cost increased to $4.49 per bbl from $3.87
per bbl in 2001 mainly as a result of the shut down of Ceiba for the
commissioning of the new FPSO, the Sendje Ceiba, and the decline in
production prior to the shut down. This per bbl operating cost is expected
to decline toward historic levels in the future. Depletion also increased
to $4.53 per bbl from $3.60 per bbl in 2001. This increase reflects the
greater contribution of the deep water Ceiba field and Gabon, both of which
have higher costs per bbl.
Exploration/appraisal costs written off in the year decreased to $26.8
million (2001: $35.7 million) reflecting the capitalisation during the year
of $10.6 million of successful appraisal drilling in Equatorial Guinea and
Congo. After administration charges of $7.9 million in the year (2001:
$10.6 million), operating profit in 2001 was $34.4 million (2001: $43.2
million).
Taxation decreased to $12.6 million in 2002 from $20.0 million in 2001
mainly due to lower revenues in the UK and South Africa. The decrease in
the effective tax rate was primarily due to the lower exploration
expenditures in jurisdictions which do not have corporation tax regimes or
those areas in which exploration expenditure could not be set off against
income from producing assets.
Profit after taxation was $20.6 million for 2002 compared to $25.1 million
in 2001.
Balance sheet
Fixed assets at year end were $199.2 million (2001: $142.6 million) and
comprise mainly the net book values of the producing assets.
Current assets included cash of $18.8 million (2001: $29.3 million). In
December 2001 a $50 million limited recourse reducing revolving credit
facility was concluded and at the year end $10.0 million was drawn on the
facility. During the year the project loans to finance Nkossa were repaid
in full. At the end of the year Energy Africa had net cash of $8.8 million
(2001: $24.7 million).
Operations
Production and development
Energy Africa`s working interest share of production for the year ended 31
March 2002 was 7 823 000 bbls of oil and LPG, an average of 21 430 bpd
(2001: 17 700 bpd). Production from the Ceiba Field rose some 2 900 bpd and
together with increased production from Gabon, accounted for the 21% rise in
production. Development activities continued in the Ceiba Field in
Equatorial Guinea and in January 2002 the Sendje Berge FPSO was replaced by
the Sendje Ceiba with larger fluid handling capacity (160 000 bbls/d) and
water injection facilities. In the UK North Sea, Government approval for
the Alba Extreme South and Caledonia developments was received and in Gabon
the development of the Niungo field was initiated following the successful
Niungo-5 appraisal well.
The average Brent oil price for the year was $23.28 per bbl, an 18% decrease
relative to the $28.22 achieved in 2001. The average realised oil price
declined from $25.16 to $20.56, a decrease of 18%. The increase in the
average percentage discount is attributable to a general increase in the
discount for heavy crudes which affects the Alba field in particular,
partially offset by the elimination of the introduction discount for the
Ceiba crude.
Exploration and appraisal
Nine exploration wells were completed in the year. Six resulted in oil
discoveries, one in a sub-commercial oil discovery and two were dry. Five
of the oil discoveries were in Blocks G and F in the Rio Muni Basin in
Equatorial Guinea and one in the Haute Mer Permit in the Congo.
Seven appraisal wells were completed by year-end, and two thereafter. Of
the nine wells, five were in Equatorial Guinea, two in Gabon and one each in
the Congo and Namibia. Four of the wells in Equatorial Guinea were
successful and were suspended for possible use as production wells. In the
Congo, the Bilondo-2 well was successfully tested. In Gabon, the Turnix TUM-
B2 well was completed and brought on production and in the Niungo field the
Niungo-5 well was successful, triggering a development decision.
Numerous new opportunities were evaluated and interests were acquired in two
licences in Uganda and one in Mauritania. Shortly after year-end the Akoum
licence in Gabon was signed. In Morocco 3-D seismic surveys were acquired in
both of the company`s licence areas and a 2-D seismic survey was acquired in
the onshore area of the Uganda licences.
Reserves
At 31 March 2002, the net commercial oil reserves attributable to Energy
Africa totalled 57.9 MMbbls. This is an increase of 10.6 MMbbls (22%) over
the 47.3 MMbbls brought forward at the beginning of the year. The increase
comprises transfers from potentially commercial reserves and revisions to
reserves offset by production of 7.8 MMbbls during the year.
Oil reserves in the potentially commercial category rose from 17.1 MMbbls to
37.3 MMbbls, an increase of 118%.
Potentially commercial gas reserves remained at 210 BCF or an oil equivalent
of 35 MMbbls.
Angola
An exploration well was completed in Block 9 (Energy Africa 15%) in December
2001. The target was potential carbonate and clastic intervals of Albian
age in a rafted structure in shallow water. Only minor shows of bio-
degraded oil were encountered. As the remaining prospects were similar to
the one drilled, the exploration licence was terminated in April 2002.
Congo (Brazzaville)
Gross production from the Nkossa field (Energy Africa 4%, operator
TotalFinaElf) averaged 43 630 bpd of oil and 11 640 boepd of LPG (2001: 53
100 bpd and 12 250 boepd). The decline is in line with expectations. The
appraisal well drilled in the Nsoko satellite structure at the end of the
previous year yielded disappointing results but potential remains for
significant reserves and development options are being studied. The
exploration well drilled to test the Nkossa South South prospect was
successful, adding significant reserves which can be produced through the
Nkossa facilities. Development is likely to commence late in 2003 with
first oil in 2005.
As reported in mid-year, agreement has been reached by the Angolan and
Congolese authorities in respect of a joint development area for the Nkoumbi
Prospect which straddles the boundary between Angola Block 14 and the Haute
Mer Permit. It is anticipated that a well will be drilled by end-2002, the
costs of which will be shared by the Haute Mer/Block 14 contractor groups.
Egypt
Activity on the Matruh licence (Energy Africa 20%, operator Shell) during
the past year was focussed on prospect generation. This resulted in the
definition of three attractive prospects, one of which is likely to be
drilled early in 2003. More immediately, a well is to be drilled in the
adjacent Obaiyed Production Area to test a gas-condensate prospect which
extends into the Matruh licence. If successful, the discovery can be
produced through the Obaiyed facilities and provide early cash flow for the
Matruh partnership.
Evaluation of acreage on offer in the March 2002 bid round did not identify
attractive prospects and consequently no bids were submitted. More
attractive acreage is expected to be offered later in 2002.
Equatorial Guinea
In the Ceiba field (Energy Africa 14.25%) oil production for the full year
averaged 33 050 bpd. The change out of the Berge Hus, renamed the Sendje
Ceiba, for the Sendje Berge FPSO, was successfully achieved in January 2002
and by year-end eight production wells and two water injection wells were
online. A peak rate of over 75 000 bpd was achieved late in March. In the
remainder of 2002 it is planned to complete a previously drilled water
injection well on the western flank and to drill and complete three
additional production wells and two additional water injection wells. The
first phase of installation of subsea pumps is scheduled to commence in the
last quarter of 2002. Average production in the coming year is forecast to
exceed 60 000 bpd but rates will be strongly influenced by the results of
the drilling programme and the efficacy of the water injection in
maintaining reservoir pressure.
The exploration programme in Blocks F and G (Energy Africa 15%, operator
Amerada Hess), in contrast to the previous year, yielded outstanding
results; the five exploration wells drilled yielded a 100% success rate,
resulting in the Okume, Oveng, Ebano, Akom and Elon discoveries. Three
appraisal wells were drilled on Okume and one each on Oveng and Ebano. Four
of these have been suspended as potential production wells and one as a
potential water injection well.
The discoveries are in a fairly confined area located some 20km north east
of the Ceiba field in water depths ranging from 50m to 800m. The proximity
of the discoveries is favourable for a phased, integrated development and
various options are being evaluated with a view to achieving maximum
synergies and minimising development costs on a per barrel basis.
Consequently the possible fast-track development option for Okume, which was
being considered at mid-year, has been discarded and capital expenditures
have been delayed. First oil from this area is now likely to be achieved in
2004.
To date exploration drilling has been focussed in the central toe-thrust
area. Further prospects remain to be tested in this area but the emphasis
in the coming twelve months will be to test prospects in the other
prospective areas in both Blocks G and F.
Gabon
Energy Africa Gabon S A (EAGSA), in which Energy Africa has a 50% beneficial
interest, increased its production to 13 870 bpd (2001 : 9800 bpd). Energy
Africa`s equity share increased from 4 900 bpd to 6 940 bpd reflecting both
the increased production and the larger holding in EAGSA (which was
increased from 37.5% to 50% in March 2001 with the purchase of 12.5% from
the Gabon State).
In the Tchatamba fields (Energy African net 12.5%, operator Marathon Gabon)
production levels were maintained at approximately 41 000 bpd (2001 : 37 000
bpd) by development of the shallower Cap Lopez reservoir in the Tchatamba
South field. The Azile reservoir, also in the Tchatamba South field, will
be brought into production in 2002 and will mitigate the natural decline in
production from the Madiela Formation which is the main producing reservoir
in the Tchatamba fields. Subsequent to year-end, EAGSA signed for a 100%
interest in the Akoum Permit which surrounds the Tchatamba fields. A number
of structures similar to the producing fields remain to be tested and two
wells are planned in late 2002 / early 2003.
In the Turnix field (Energy Africa net 13.75%, operator Perenco Gabon),
reservoir performance was well below expectation and the field average for
the year was 4 260 bpd. A successful appraisal well was drilled in a
southern extension to the field and came online late in March 2002.
Depending on the well performance, a further well may be drilled later in
the year.
The Limande field (Energy Africa net 10%, operator Agip) averaged
approximately 2 620 bpd for the year. An additional production well is
scheduled later in the year and should result in a marginal increase in
production levels. Subsequent to year-end, an exploration well was drilled
in the Limande North prospect. Good oil shows were recorded but reservoir
development in the target intervals was very poor.
Two development wells were drilled in the onshore Echira field (Energy
Africa net 20%, operator Perenco Gabon). Mechanical problems resulted in
inadequate reservoir intersections and flow rates have been disappointing.
The field average for the year was 2 790 bpd, marginally below the level
achieved in March 2001.
The Moukouti field (EA net 20%, operator Perenco Gabon), some 10km north of
Echira, contrary to forecast, continued to produce throughout the year,
averaging 1 490 bpd. However the water cut is now in excess of 90% and the
economic cut-off is likely to occur late in 2002. In the Ganga field
(Energy Africa net 20%, operator Perenco Gabon) an extended well test
continued production at an average rate of 400 bpd but further development
of the field is unlikely.
In the Niungo field (Energy Africa net 20%, operator Perenco Gabon), located
some 40km east of Echira, the Niungo-5 well confirmed the reserve estimates
and development of the field was commenced. However delays in procuring
certain items of production equipment has delayed commencement of oil
production to September 2002.
In the ten offshore licences in which EAGSA retains options to acquire
various levels of interest in the event of discovery or is carried through
exploration expenditures, wells were completed in the Tolo permit (EAGSA
10%) where the results were negative, and in the Kenguerie permit (EAGSA
15%) where the Kenpil-1 well was sufficiently encouraging to suggest that
the structure may contain commercial reserves although the intersection in
the well itself was sub-commercial. Additionally a third successful
appraisal well was completed on the discovery in the Etame permit (EAGSA
7.5%) and first oil from a fast-track development is expected in August
2002. Oil production net to EAGSA is expected to be of the order of 1 000
bpd.
The wells planned for the Agip-operated Chaillu and Mpolo permits (EAGSA 10%-
25%) were again delayed due to rig availability and are now scheduled to be
drilled in the third quarter of 2002. The prospects to be drilled are both
in water depths in excess of 1 000m and in the event of success, EAGSA`s
options will be limited to 10% participations in terms of the production
sharing contracts.
Libya
Energy Africa retains a 20% interest in Blocks NC184/185 in the onshore
Sirte Basin and has an obligation to drill one further well. In the absence
of viable prospects negotiations are in progress for the transfer of the
commitment to more prospective acreage. In the event that agreement cannot
be reached, Energy Africa will have a liability of $800 000 in lieu of
drilling the well.
Mauritania
In February 2002, Energy Africa finalised the acquisition of a 20% interest
in Block 2, (operator Woodside) offshore Mauritania from the contractor
group comprising Woodside Petroleum, Hardman Resources and Roc Oil. The
acreage lies in a salt basin, south of the potentially significant
Chinguetti discovery in Block 4 but, being on the periphery of the basin,
has a higher risk profile than that area. Acquisition of a 1 000km} 3-D
seismic survey is planned for the third quarter of 2002 whereafter the
contractor group will be required to commit to drilling a well should it
wish to proceed into the second term of the licence.
Morocco
Energy Africa reduced its holding in the Tiznit licence from 63.75% to
31.875% by farming out half its interest to Petronas Carigali. Energy
Africa has retained operatorship and in August-September completed a 1000
sq.km 3-D seismic survey over the most prospective area. Prior to that
Enterprise Oil, operator of the Cap Draa licence (Energy Africa 20%) had
acquired some 2 000 sq.km of 3-D seismic data in the outboard area of the
salt basin. Both surveys are currently being interpreted and drilling is
expected to commence in 2003.
Namibia
As reported at half-year, Shell, the operator of the Kudu field (Energy
Africa 10%) identified an attractive opportunity to market LNG into the
Atlantic Basin markets in circa 2006. Provided reserves in excess of 5 TCF
could be proved at a reasonable confidence level, production of LNG from a
floating facility on the Kudu field was considered a viable option. Given
the short timeframe for committing to gas sales agreements, an appraisal
well, Kudu-6, to achieve the required additional reserves was drilled at a
location some 27km north of the Kudu main field. This proved overly
ambitious and the well failed to intersect the Aeolian (dune) sand reservoir
present in the main field. The floating LNG project has therefore been
shelved for the immediate future, and an appraisal well, Kudu-7, sited to
prove additional reserves for the South African market, is currently being
drilled on the west flank of the Kudu main field.
South Africa
Production from the Oribi field (Energy Africa 20%, operator PetroSA),
offshore Mossel Bay, averaged 6120 bpd (2001 : 12 000 bpd), somewhat above
the rate forecast for the period. However the decline rate is expected to
accelerate and it is anticipated that production will cease in 2003. The
Company continues to monitor opportunities in South Africa but has thus far
failed to identify projects meeting its risk-reward criteria.
Uganda
As recorded in the Interim Report, Energy Africa secured 50% interests in
Blocks 2 and 3 in the Albertine Graben. Some 228km of additional 2-D
seismic was acquired in the onshore area of Block 3 in late-2001 and the
processed data is currently being interpreted. A well is planned for August
2002. Additionally a 2-D seismic survey over the areas in Lake Albert is
being planned, with acquisition expected to commence in late 2002.
United Kingdom
Production in the Alba field in the central North Sea (Energy Africa 8%,
operator Chevron Texaco) averaged 79 300 bpd (2001 : 74 800 bpd) continuing
an exceptional period of plateau production. Development plans for the Alba
Extreme South area and the Caledonia field were approved by the Government
authorities and development of both have proceeded within budget and on
schedule for first oil production in October 2002. In the six months to
September 2002, production from the Alba field is expected to be well below
previous levels, reflecting both declining deliverability and a 3-week
platform shutdown in June when upgrades, required for the Extreme South
development, will be done.
Future Activity
In the year to March 2003, Energy Africa`s net production is expected to
exceed 25 000 bpd reflecting mainly the increased production from the Ceiba
field. The completion of the Alba Extreme South and Caledonia fields will
maintain production from the North Sea at previous levels. In Gabon
production from the Niungo and Etame fields should offset declines at
Moukouti and Echira.
Nineteen exploration wells are scheduled of which seven are in the
contingent category. Eleven of these are in Equatorial Guinea, three in
Gabon, two in Congo, two in Uganda and one in Egypt. In addition to three
appraisal wells already completed, it is likely that five further wells will
be drilled by March 2003.
In line with our objective of maintaining an exploration portfolio with
potential to add significant value, new opportunities are continuously
reviewed and it is anticipated that two or three new ventures will be added
in the year.
For and on behalf of the Board
Dato` M Idris Mansor
R Gasant
22 May 2002
Directors:
Dato` M Idris Mansor (Chairman) (Malaysian), R Gasant (Managing Director),
P J G Elwes (British), Tunku Mahmood Fawzy b. Tunku Muhiyiddin (Malaysian),
W A Nel (Chief Operating Officer), L M Nyhonyha, G D B Paul (Malaysian),
F M J L Poimboeuf (French), A G Windham (British)
Group income statements
Year Year
ended ended
31 March 31 March
2002 2001
Notes $`000 $`000
Total revenues 144 907 141 987
Turnover 143 996 138 512
Cost of production 2 (74 822) (50 784)
Gross income 69 174 87 728
Exploration expenditure written off (26 845) (35 683)
Administration expenses (7 869) (10 572)
Other operating (expenses)/income (50) 1 742
Operating profit 34 410 43 215
Interest income 911 3 475
Interest expense 3 (2 162) (1 545)
Profit on ordinary activities
before taxation 33 159 45 145
Taxation 4 (12 588) (20 030)
Profit on ordinary activities
after taxation and attributable
to ordinary shareholders 20 571 25 115
Earnings/headline earnings
per share - cents
Basic 20.1 24.9
Diluted 19.9 24.7
Weighted average number of ordinary
shares in issue (`000)
Basic 102 124 101 056
Diluted 103 164 101 698
Group balance sheets
31 March 31 March
2002 2001
Notes $`000 $`000
Employment of capital
Fixed assets 199 198 142 591
Current assets
Inventories 5 683 4 638
Debtors 18 906 18 663
Cash and bank deposits 18 765 29 325
43 354 52 626
Current liabilities 5 (36 163) (24 980)
Net current assets 7 191 27 646
Total assets less current liabilities 206 389 170 237
Long term interest bearing project loan 6 (10 000) -
Deferred taxation (10 712) (8 132)
Decommissioning provision (19 059) (16 648)
166 618 145 457
Capital employed
Share capital 2 642 2 630
Share premium account 101 525 99 823
Other reserves 62 451 43 004
Shareholders` interest 166 618 145 457
Net book value per share - cents
Basic 161.9 143.0
Diluted 160.9 142.4
Number of ordinary shares in issue at
year end (`000)
Basic 102 913 101 726
Diluted 103 586 102 171
Group cash flow information
Year Year
ended ended
31 March 31 March
2002 2001
Notes $`000 $`000
Reconciliation of operating profit
to net cash flow from operations
Operating profit 34 410 43 215
Exploration expenditure written off 26 845 35 683
Depreciation 36 123 23 619
Loss/(profit) on disposal of fixed assets 17 (3)
Exchange loss/(gain) 50 (1 742)
Net cash inflow from operations prior
to working capital adjustments 97 445 100 772
Working capital adjustments (1 909) (7 108)
Net cash inflow from operations 95 536 93 664
Cash flow statements
Net cash inflow from operations 95 536 93 664
Returns on investments and servicing of finance
Interest received 919 3 526
Interest paid (1 287) (848)
Tax paid (12 062) (16 829)
Investing activities
Exploration expenditure (31 241) (39 504)
Payments to acquire tangible assets (69 305) (71 477)
Proceeds from sale of fixed assets 15 4
Net cash outflow before financing (17 425) (31 464)
Financing
Issue of ordinary shares 1 714 1 325
Increase in bank and other loans 10 000 917
Repayment of loans (4 591) (5 284)
Net cash outflow after financing (10 302) (34 506)
Cash flow from operations
per share - cents
Basic 93.5 92.7
Diluted 92.6 92.1
Group Statement of changes in equity
Share
Share premium Other
Capital account reserves Total
$`000 $`000 $`000 $`000
At 1 April 2000 2 618 98 510 24 404 125 532
Profit attributable
to ordinary
shareholders - - 25 115 25 115
Exchange adjustment - - (6 515) (6 515)
Arising on issue
of shares 12 1 313 - 1 325
At 31 March 2001 2 630 99 823 43 004 145 457
Profit attributable to
ordinary shareholders - - 20 571 20 571
Exchange adjustment - - (1 124) (1 124)
Arising on issue
of shares 12 1 702 - 1 714
At 31 March 2002 2 642 101 525 62 451 166 618
Share premium account is not distributable other than as contemplated in the
Companies Act.
Notes to the financial statements
1. Accounting policies
Basis of preparation
The financial information is expressed in United States Dollars for the
Group and has been prepared under the historical cost convention, in
accordance with accounting policies which conform with International
Accounting Standards ("IAS") and South African Statements of Generally
Accepted Accounting Practice. These accounting policies are consistent with
those used in the previous period, other than the changes in measurement and
presentation currency.
Changes in Presentation Currency
The Group has changed its measurement and presentation currency from South
African Rand to United States Dollars to facilitate a better understanding
of its results, financial position and cash flow information, since the
majority of its revenues, costs, assets, and liabilities are transacted in
United States Dollars which is the recognised currency of the oil
exploration and production industry.
Exploration and development expenditure
The Group follows the successful efforts method of accounting for
exploration costs. Exploration costs are initially capitalised for each
prospect within other oil and gas assets pending determination. On
determination such costs are written off unless commercial reserves have
been established. As development commences such costs are transferred to
fields in production and under development.
2. Cost of production
2002 2001
$`000 $`000
Operating costs 35 147 24 993
Movement in underlift (1 039) (1 185)
Royalty paid in cash 5 240 3 714
Depreciation 35 474 23 262
74 822 50 784
3. Interest expense
2002 2001
$`000 $`000
Interest payable on loans 1 184 864
Finance charge - unwinding of discount 978 681
2 162 1 545
The finance charge represents the unwinding during the year of the discount
on the decommissioning provision.
4. Taxation
2002 2001
$`000 $`000
SA taxation
Normal - current 1 809 5 661
- prior period - (201)
Deferred - (223)
Foreign taxation
Normal - current 8 885 11 128
- prior period (686) (275)
Deferred 2 580 3 940
12 588 20 030
The foreign deferred tax charge includes provision for deferred UK Petroleum
Revenue Tax.
5. Current liabilities
2002 2001
$`000 $`000
Current portion of borrowings - 4 591
Corporation tax payable 6 018 7 278
Other taxes and social security costs 245 167
Other creditors 4 623 3 105
Accruals 25 277 9 839
36 163 24 980
6. Borrowings
2002 2001
$`000 $`000
Total interest bearing borrowings
Secured loan repayable after more
than one year 10 000 -
Secured loan repayable within one year - 4 591
10 000 4 591
7. Capital commitments
2002 2001
$`000 $`000
Contracted 42 861 50 063
8. Status of financial information
The above information does not constitute statutory financial statements. It
has been extracted from the 2002 Group financial statements that have been
approved by the directors but not yet delivered to the Registrar of
Companies.
Oil and gas reserves and production
2002 2001
Oil equivalent Oil equivalent
MMboe MMboe
Reserves
Commercial reserves
Movement in Group net remaining
Proven+Probable Reserves
At beginning of year 47.3 36.5
Revisions of previous estimates 7.3 12.9
Acquisitions of reserves in place - 4.4
Discoveries, extensions and other
additions 11.1 -
Production (7.8) (6.5)
57.9 47.3
Potentially commercial reserves
Group net remaining Proven+Probable reserves
At end of year 72.3 52.1
Summary of reserves
Commercial reserves
Oil 57.9 47.3
Gas - -
Potentially commercial reserves
Oil 37.3 17.1
Gas 35.0 35.0
Production
Group share of production 7.8 6.5
Delivered to host governments (0.7) (0.9)
Movement in underlift - (0.1)
Group production sold 7.1 5.5
Production by location of field
Africa 5.5 4.3
UK 2.3 2.2
7.8 6.5
Summary Rand convenience translation
Year ended Year ended
31 March 31 March
2002 2001
R million R million
Income statement
Turnover 1 374 1 015
Operating profit 328 317
Net profit 196 184
Earnings/ headline earnings per share (cents) 192 182
Cash flow
Cash inflow from operations 912 685
Exploration expenditure 298 289
Development expenditure 661 524
Cash inflow from operations per share (cents) 893 678
Balance Sheet
Fixed assets 2 264 1 142
Cash 213 235
Loans 114 37
Net cash 100 198
Net assets 1 894 1 165
Net book value per share (cents) 1 840 1 145
R/$ exchange rate (period average) 9.5414 7.3245
R/$ exchange rate (period end) 11.3650 8.0101
Date: 23/05/2002 08:00:22 AM Produced by the SENS Department
