| Mon 26 May 2003, 9:38 | | Energy Africa Limited - Audited Preliminary Result |
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ENERGY AFRICA LIMITED - AUDITED PRELIMINARY RESULTS FOR THE YEAR ENDED 31 MARCH
2003
Energy Africa Limited
Registration number: 1995/007140/06
(Incorporated in the Republic of South Africa)
JSE code: ENR ISIN code: ZAE000010427
Audited Preliminary Results for the year ended 31 March 2003
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 record production cash flow and profits.
Net cash inflow from operations up 32% to $126.3 million (2002: $95.5 million)
Production up by 4% to 22 240 bpd (2002: 21 430 bpd)
Net profit up 23% to $25.4 million (2002: $20.6 million)
Continued exploration and appraisal success - four new discoveries
Major progress in development projects - four new fields commenced production
Strong balance sheet maintained with higher net cash at year end
Additional loan facility of $75 million agreed
Active exploration and development program continues
Further additions to exploration portfolio
Commenting on the results, Rhidwaan Gasant, Managing Director of Energy Africa,
said:
"The Company is delighted to report record production, cash flow and profits.
We have had further exploration successes in Equatorial Guinea and Gabon and
have brought new fields into production in Gabon and the UK. We are well placed
to continue our active exploration and development program and to deliver
further value to shareholders through growth in net asset value per share."
26 May 2003
Enquiries:
Energy Africa Limited
Rhidwaan Gasant +27 21 400 7600
College Hill
Nicholas Williams (SA) +27 11 447 3030
+27 83 607 0761
Matthew Gregorowski (UK) +44 207457 2020
Chairman"s statement
On behalf of the Board, I am pleased to present the annual results of Energy
Africa Limited for the financial year ended 31 March 2003.
The year just ended has seen a period of continued growth for the Company,
highlighted by the record achievements in turnover and production levels.
Significantly, this financial performance was achieved amid an increasingly
challenging business and operating environment, and lower than targeted increase
in production. The improved financial performance of the Company has been
positively influenced by gains from the stronger than expected crude oil prices.
During the period, the Company chalked up further exploration successes in
Equatorial Guinea and Gabon, and made significant progress with plans for the
first phase development of the Northern Block G complex there. In addition,
three new Production Sharing Contracts were signed for Akoum in Gabon,
Mauritania"s Block 1 and Block L in Equatorial Guinea, further expanding the
Company"s exploration asset portfolio.
The balance sheet position remains robust on the back of the approximate 30%
increase in turnover and net cash inflow from operations. This has enabled the
Company to be in a position to finance its substantial development and
exploration program for the year entirely from internally generated funds.
During the period, four new fields came on stream, which contributed to the 4%
increase in production to 22 240 barrels a day. Production was lower than
advised at this time last year, largely due to the deferral of production and
the adoption of a more conservative reservoir management philosophy for the
Ceiba field in Equatorial Guinea.
Despite the record 8 million barrels of production during the period, the
Company"s commercial and potentially commercial oil reserves were maintained
close to last year"s level at 93 million barrels. The Company"s continued
exploration success should lead to future growth in reserves.
As you are aware, in September 2002, PETRONAS made a cash offer of R43.75 for
the shares of Energy Africa not already owned by Engen. PETRONAS is the
majority shareholder of Engen, which in turn is the parent company of Energy
Africa. Subsequent to the cash offer, PETRONAS and Engen now together own 65.2%
of Energy Africa"s shares.
During the year, the Company has continued with efforts to expand its asset
portfolio with a view to maximizing prospects of increasing net asset value per
share. In this regard, the objective will be to have a balanced portfolio of
low and high-risk assets, biased in favour of those offering higher reward
potential. While Africa remains a key focus area in pursuing this objective,
the Company is nevertheless actively seeking participation in exploration
ventures in the UK Continental Shelf as attractive opportunities emerge.
Looking ahead, the Company expects continued volatility and uncertainty in the
global oil market. The Company"s financial performance is increasingly
sensitive to the movements in crude oil price and changes in demand, in view of
the growing production profile and significant investments planned for new
development programs over the coming period. In order to ensure that the
Company"s financial position remains resilient, limited oil price hedging has
been implemented and a new $75 million credit facility has been secured to
provide the necessary funding for future development expenditure requirements.
As such, I am confident that your company remains well placed to achieve further
growth towards enhancing its net asset value per share.
Finally, on behalf of the Board, I would like to thank the management and staff
for their contribution to the success of the Company over the past year, and
look forward to their continued dedication, professionalism and hard work in the
years ahead.
Dato" M Idris Mansor
Chairman
22 May 2003
Managing Director"s review
I am delighted to present another outstanding set of results for Energy Africa.
Record production, cash flow from operations and net income were achieved, while
the Company"s success with the drill bit has continued.
Last year, I described the additional prospectivity on our Blocks in Equatorial
Guinea. Three further discoveries have since been made there, underscoring the
potential of the region and our interest therein has been expanded through the
acquisition of another Block during the year. Prospectivity on the remainder of
Blocks F and G remains high, and we expect that several low risk targets will be
drilled in the Northern Block G area in the next twelve months.
During an active period, fifteen exploration wells and five appraisal wells were
drilled, eight of which were successful and one of which was suspended above the
target. Encouraging oil shows were encountered in three of the unsuccessful
exploration wells in Equatorial Guinea and two in Gabon.
In addition to the acquisition of a 20% interest in Block L in Equatorial
Guinea, referred to above, a 32% licence interest was acquired in Mauritania
Block 1 and our Gabon joint venture company took a 100% interest in the Akoum
permit. Numerous other opportunities were evaluated, and further acquisitions of
licence interests are expected this year.
Commercial oil reserves decreased from 58 million to 51 million barrels after
production of 8 million barrels. Potentially commercial reserves increased from
37 million to 42 million barrels reflecting the successful appraisal program in
Equatorial Guinea. Potentially commercial gas reserves, assuming a smaller power
project than previously envisaged, increased from 210 billion to 350 billion
cubic feet as a result of the increase in the Company"s interest in the Kudu gas
field in Namibia.
Development plans were progressed for the Okume, Oveng and Elon fields in
Northern Block G in Equatorial Guinea, and Government approvals are expected by
mid-2003 with first production in early 2005. Similarly in Congo Brazzaville,
development plans for the Moho-Bilondo fields have been submitted to Government.
Substantial progress was also made in relation to our production interests. Four
new fields commenced production - Alba Extreme South and Caledonia in the North
Sea and Niungo and Etame in Gabon, with some delays experienced in relation to
the commissioning of the North Sea production. As advised during the year, lower
than anticipated production has been experienced from the Ceiba field in
Equatorial Guinea and, due to the implementation of a more conservative
reservoir management philosophy, peak production from the field will be lower
than previously forecast. However, production will be sustained at this lower
plateau for a longer period.
Overall, average production for the year increased by 4% to over 22 000 barrels
per day, somewhat lower than our forecast at this time last year. We expect
average production for the financial year 2004 to remain at approximately the
same level.
The higher production was accompanied by a significantly higher average oil
price for the current year, which was further improved by a pleasing reduction
in the Company"s average discount to Brent oil. This resulted in an increase of
24% in the average price realised from the Company"s production. Consequently,
net cash inflow from operations increased by 32% to $126 million.
The high oil price ruling prior to the onset of the war in Iraq provided an
opportunity for the Company to implement limited oil price hedging to protect it
from the downside of possible significantly lower prices during a period when
our active development period will be funded by increased borrowings.
The Company remains well placed to pursue growth opportunities in the future
with the strong balance sheet still reflecting net cash (after deducting
borrowings) of $12 million after funding an active development and exploration
program entirely from internally generated cash flows. During the year the
Company"s bankers committed to provide additional credit facilities of $75
million (in addition to the $50 million Alba facility) to fund Energy Africa"s
development program. These facilities, once finalised, are expected to provide
sufficient funding to cover our development capital expenditure requirements for
the foreseeable future.
The development plan for the year ahead includes further drilling in the Alba
field and in the Niungo field in Gabon. Drilling and construction of facilities
for the Northern Block G is expected to commence in the third quarter of 2003.
Our planned exploration and appraisal program for the coming twelve months
includes ten exploration wells and further appraisal of the G-13 discovery in
Equatorial Guinea. Further appraisal drilling may be required in the event of
exploration success elsewhere.
In view of increased opportunities as major companies disengage from the UK
Continental Shelf (UKCS), Energy Africa is actively pursuing participation in
current licences and possible applications for licenses in the UK"s 21st round,
closing in May 2003. The Company is able to bring significant experience to bear
on UKCS exploration.
Total development expenditure for the year ahead is estimated at approximately
$98 million, while exploration expenditure is projected at approximately $45
million. We expect that internally generated cash flows, augmented by the credit
facilities referred to above, will provide the funding for the year ahead.
Finally, I thank my fellow executive directors and all Energy Africa staff for
their continued professionalism, dedication and support during what has proven
to be a very challenging year.
Rhidwaan Gasant
Managing Director
22 May 2003
Financial & operating review
Results for the year ended 31 March 2003
Summary
Increased production and strong oil prices resulted in an excellent financial
performance for the year. These factors have contributed to the maintenance of
a strong balance sheet at year end which provides the Group with the financial
strength to pursue its exploration and development programs.
Cash flow
Net cash inflow from operations increased by 32% to $126.3 million from $95.5
million in 2002 reflecting both the 4% increase in production to 22 240 bbl per
day from 21 430 bbl in 2002 and the 24% increase in average oil prices during
the year compared to 2002.
Exploration expenditure increased to $38.3 million from $31.2 million in 2002
due to the more active exploration program. Development expenditure also
increased to $77.1 million from $69.3 million in 2002 due to the continuing
development of Ceiba and appraisal of Northern Block G in Equatorial Guinea
($40.4 million) as well as expenditure in the UK North Sea on Alba and Caledonia
($24.8 million) and in Gabon ($9.8 million). Net cash inflow before financing
was $2.9 million (2002: net cash outflow $17.4 million).
Financing activities resulted in a net cash inflow of $16.7 million (2002:
inflow $7.1 million). Proceeds from the issue of shares were $0.7 million
(2002: $1.7 million). Loan drawings on the $50 million revolving credit
facility amounted to $16.0 million (2002: $10.0 million). The resulting net
cash inflow after financing was $19.6 million (2002: net cash outflow $10.3
million).
Income statement
Turnover for the year increased by 28% to $184.5 million compared to $144.0
million in 2002. The increase was due to an increase of 2.4% in volumes sold to
7.2 MMbbl (2002: 7.1 MMbbl) and an increase of 24% in the realised oil price.
Turnover is reflected after delivering 1.0 MMbbl (2002: 0.7 MMbbl) of
hydrocarbons to host governments under the terms of Production Sharing
Agreements.
Cost of production for the year was $85.4 million (2002: $74.8 million). On a
per barrel basis, operating costs were $4.73 per bbl (2002: $4.49), the increase
being due to lower than expected production from Alba and Ceiba, but per barrel
operating costs are expected to decrease in 2004. Depletion was $4.83 per bbl
(2002: $4.53) reflecting the greater contribution of Ceiba, which being a deep
water field, has a higher cost per barrel. Royalties were $0.81 per barrel
(2002: $0.67) as a consequence of the higher oil price. Total cost of
production, excluding the effect of the movement in inventories, was $10.37 per
barrel (2002: $9.70).
The exploration charge for the year was $41.3 million (2002: $26.8 million).
This increase is due to the higher exploration spend in 2003 as well as
capitalisations in 2002. The increase in administration charges to $15.6
million (2002: $7.9 million) was due to the one-off additional costs incurred as
a result of the PETRONAS Offer. Operating profit was $41.9 million (2002: $34.4
million).
Taxation was $14.8 million for the year (2002: $12.6 million). Following
changes during the year in the tax rules in the UK, the decrease in corporation
tax charge arising from an accelerated capital allowance rate was offset by an
increase in deferred taxation.
Profit after taxation was $25.4 million for 2003 compared to $20.6 million in
2002.
Balance sheet
Fixed assets at year end were $236.7 million (2002: $199.2 million) and comprise
mainly the net book values of producing assets.
Net current assets were $22.5 million (2002: $7.2 million) which included cash
of $38.0 million (2002: $18.8 million). Loans were $26.0 million (2002: $10.0
million) and at year end Energy Africa had net cash of $12.0 million (2002: $8.8
million). Additional credit facilities of $75 million have been agreed - a
commitment letter has been signed and it is anticipated that the facility
agreements will be completed soon after the year end.
Risk management
In order to protect Energy Africa"s operating cash flow against weak oil prices
the Board has approved hedging of part of the Group"s oil production using
hedging strategies which would provide protection against sustained low oil
prices while retaining some exposure to potentially higher oil prices. Energy
Africa has therefore entered into oil price hedging contracts in the form of
zero cost collars for the period 1 January 2003 to 31 December 2003 at weighted
average Brent oil floor prices of $25.31 and ceiling prices of $29.59 at
aggregate average volumes of 7 260 barrels per day. In practice this means that
from 7 260 barrels per day for calendar year 2003 the Group will receive average
oil prices of a minimum of $25.31 and a maximum of $29.59.
The underlying currency of the Group"s cash flows is in US$. The Group"s policy
is to minimise material transactional exposures from currency movements against
the US$. This is achieved primarily by matching naturally occurring opposite
exposures wherever possible. There were no material unmatched currency
exposures during the year and no currency hedging contracts have been purchased.
It is group policy that any derivative or hedging transactions support the
underlying business of the Group and that no speculative transactions be entered
into.
Energy Africa undertakes an insurance program to minimise its exposure to risks
of physical damage or loss of its property, pollution of the environment and
other risks associated with the oil and gas industry. A limited program of
business interruption cover has also been purchased to protect against the
possible risk of loss of cash flow from the main producing assets.
Operations
Production and Development
Energy Africa"s working interest share of production for the year ended 31 March
2003 was 8.117 million bbls (2002: 7.823 million bbls) of oil and LPG, an
average of 22 240 bpd and an increase of 4% over 2002 (21 430 bpd). The
increase was somewhat lower than anticipated due mainly to Alba production being
constrained by reduced well deliverability and then by facility unreliability
initially delaying full production from Alba Extreme South as well as delays in
bringing on new capacity in the Ceiba field. Additionaly production start-up in
the Caledonia field was delayed from October 2002 to February 2003 due to
constraints on a third party platform through which the oil is exported. In
Gabon, new production was brought online with the successful commissioning of
the Etame and Niungo fields, whilst successful development wells contributed to
production in the Echira, Moukouti and Tchatamba South fields.
Development plans were progressed for the Okume, Oveng and Elon fields in
Northern Block G (NBG) in Equatorial Guinea and Government approvals are
expected by mid-2003 with first production in early 2005. Similarly in Congo
Brazzaville, development plans for the Moho-Bilondo fields have been submitted.
The average Brent oil price for the year was $27.54 per bbl, an 18.3% increase
relative to the average price in 2002. The average realised price increased
from $20.56 per bbl in 2002 to $25.56 per bbl in 2003 an increase of 24.3%. The
decrease in the average discount from 11.7% to 7.2% is attributable to: an
improvement in the average quality of oil from the Ceiba field as wells on the
western flank (which have a better oil quality) were brought online; the
installation of a Calm Buoy mooring system which allows export via larger
tankers; and also to a general narrowing, for most of the year, of this discount
for high acid crudes which affected prices for both the Ceiba and Alba crudes.
Exploration and appraisal
Twelve exploration wells were completed in the year and three shortly
thereafter. Of the fifteen wells, four yielded oil discoveries, one was
suspended above the target interval due to mechanical problems and ten were
unsuccessful albeit that good oil shows were encountered in five of these.
Three discoveries were made in Equatorial Guinea where ten wells were drilled
whilst one successful well and three unsuccessful wells were drilled in Gabon.
The well in Uganda was suspended.
Five appraisal wells - four in Equatorial Guinea and one in Namibia - were
completed. The four in Equatorial Guinea were successful, but the Kudu-7 well in
Namibia failed to increase the reserve base.
New license interests were acquired in Mauritania (Block 1, 32%) and in
Equatorial Guinea (Block L, 20%) and in Gabon our Gabon joint venture company
took 100% in Akoum. Numerous opportunities were evaluated, some of which are
expected to result in the acquisition of new license interests in 2003.
Reserves
At 31 March 2003, the net commercial (producing) oil and LPG reserves
attributable to Energy Africa totalled 50.7 MMbbls. This is a decrease of 7.2
MMbbls (12.4%) from the 57.9 MMbbls brought forward. The decrease is due to
production of 8.1 MMbbls offset by net revisions, extensions and discoveries.
Potentially commercial oil reserves totalled 42 MMbbls, an increase of 4.7
MMbbls (12.6%) over 2002.
Potentially commercial gas reserves increased from 210 bcf to 350 bcf (67%) as a
result of an increase in the company"s interest in the Kudu gasfield in Namibia.
While the gross technical reserves have not changed, these net economic reserves
assume a smaller project than previously envisaged.
Congo (Brazzaville)
Production from the Nkossa field (Energy Africa 4%, operator Total) averaged 33
714 bpd of oil and 10 417 boepd of LPG per day (2002: 43 630 bpd and 11 640
boepd). Production is expected to decline further in 2004 but should rise
significantly in 2005 when production from the Nkossa South and Nsoko field
commences. Operating costs will be reduced by replacement of the floating
storage unit with a pipeline to the onshore Djeno terminal and some benefit is
now derived from services to other oil fields in the area. Development plans
have been finalised for the Moho-Bilondo fields and tendering for the
construction of a floating production unit with a capacity of 75 000 bpd is in
progress.
The K/A-IMI Unit Area (Energy Africa 2%, operator ChevronTexaco), incorporating
parts of the Haute Mer license in the Congo and Block 14 in Angola, was
finalised early in 2003 and a well to test the main prospect is scheduled for
mid-2003. Potential reserves are in excess of 500 MMbbls and there is a high
probability of success.
Egypt
In the Matruh license (Energy Africa 20%, operator Shell), the well scheduled
for March 2003 has been postponed until later in 2003. It is likely to target a
Cretaceous structure analogous to those which have yielded oil discoveries in
the neighbouring licences. Several structures have been identified and together
they could contribute a significant resource base.
Equatorial Guinea
Oil production from the Ceiba field (Energy Africa 14.25%, operator Triton)
averaged 50 750 bpd (2002: 33 050 bpd). Production was negatively impacted by a
gravel pack failure in one of the wells and reservoir development in a new
production well was poorer than anticipated. Reservoir continuity has also been
tenuous in certain areas, leading to slower than anticipated production.
However, the primary focus in the year was accelerating the pressure maintenance
program with three water injectors being completed. Injection rates for the
year averaged 64 400 barrels of water per day with rates in excess of 110 000
barrels of water per day being sustained in the last quarter. Reservoir response
has been encouraging and two further injectors will be drilled in the coming
year. Subsea pumps were successfully installed on two production wells late in
2002 and pumps will be installed at all producers by end-2003. Additionally
three further producers are planned and production in excess of 40 000 bpd is
forecast in the next year.
A high level of exploration was maintained in 2003. In Block G the remarkable
success of the 2002 program was repeated with six exploration wells yielding
three discoveries - Elon Extension, Abang and G-13. Additionally four appraisal
wells were all successful and the two in the Elon field added significant
volumes of oil in shallow water depths, considerably enhancing the development
economics. Plans for the development of the Elon, Oveng and Okume fields,
comprising the initial phase of the NBG development, have been submitted for
Government approval and will be produced through a shared processing facility on
an FPSO moored in shallow water. Development drilling is expected to commence
late in 2003 with first oil in 2005. Subsequent development phases will
incorporate the Ebano, Akom and Abang fields.
Several exploration wells are also planned to test low risk prospects with the
potential to be produced through the NBG or Ceiba facilities, and a further
appraisal well is planned in the G-13 area in the southern toethrust belt.
Elsewhere in Equatorial Guinea, three unsuccessful exploration wells were
drilled in Block F but several prospects remain and it is likely that one of
these will be tested in 2004. A 20% interest was also acquired in the block to
the north, Block L, operated by ChevronTexaco. A well to test the large Balena
structure was completed subsequent to year end but was unsuccessful although oil
shows were encountered in some of the target levels.
Gabon
Production attributable to Energy Africa Gabon SA (EAGSA), in which Energy
Africa has a 50% beneficial interest, increased to 14 500 bpd (2002: 13 870 bpd)
resulting in 7 250 bpd net to Energy Africa (2002: 6 940 bpd). The increase in
production is due to the Niungo (EAGSA 40%) and Etame (EAGSA 7.5%) fields coming
onstream in September 2002. Fields in the Tchatamba complex (Energy Africa net
12.5%, operator Marathon) continued to perform ahead of expectation with
production averaging 37 394 bpd (2002: 41 000 bpd). In December 2002 the
floating storage unit was replaced by a pipeline to the Cap Lopez terminal, a
development which will yield cost savings in the future. Natural field decline
will be mitigated by the successful Tchatamba South-6 development well which has
been completed for production from the Azile reservoir, commencing in April
2003.
The Turnix field (Energy Africa net 13.75%, operator Perenco) benefited from the
successful appraisal well which came online in March 2002. Average production
increased to 5 261 bpd (2002: 4 260 bpd).
In the Limande field (Energy Africa net 10%, operator Agip) production showed a
marginal decline to 2 470 bpd (2002: 2 620 bpd). The planned additional
production well was not drilled but, given the large in-place volumes, scope
remains for further development drilling.
A single development well was drilled on the eastern flank of the Echira field
(Energy Africa net 20%, operator Perenco) and contributed to a marginal increase
in field production to 2 887 bpd (2002: 2 790 bpd). In the nearby Moukouti
field (Energy Africa net 20%, operator Perenco), the field life was extended by
a successful development well which commenced production in March 2003. Gross
production declined to 1 170 bpd (2002: 1 490 bpd).
In the Ganga field (Energy Africa net 20%, operator Perenco) production from the
single well declined to 325 bpd (2002: 400 bpd). The Niungo field (Energy
Africa net 20%, operator Perenco) was brought onstream in September 2002 with
three production wells with a total production rate of approximately 4 000 bpd,
giving an average for 2003 of 2 093 bpd (2002: nil bpd). Mechanical problems in
certain wells adversely affected production rates and will be addressed by a
workover program in the second quarter of 2003. Further production wells will
also be drilled and production is expected to increase to between 6 000 and 8
000 bpd.
The Etame field (Energy Africa net 3.75%, operator Vaalco) also came onstream in
September 2002 at a rate of 14 500 bpd. Average production for the year was 8
161 bpd (2002: nil bpd). A further production well is planned for mid-2003 which
should ensure an average rate in excess of 14 000 bpd in the coming year.
As previously reported, an exploration well drilled in the Limande exploitation
permit (Energy Africa net 10%, operator Agip) was unsuccessful. An unsuccessful
exploration well was also completed in the Nziembou permit (Energy Africa net
20%, operator Perenco).
In April 2003, EAGSA signed a PSC with the Gabon Government in respect of the
Akoum permit (Energy Africa net 50%, operator EAGSA), covering the area in which
the three Tchatamba fields are located. In April 2003 the first exploration
well recorded very strong oil shows but reservoir characteristics were poor and
the well was plugged and abandoned. A second exploration well in the Akoum
permit encountered potentially commercial oil reservoirs and has been suspended
for future re-entry. Additional seismic is being acquired to define the
structure more closely
Following a negative assessment of the potential of the Ofoubou-Ankani permit
(Energy Africa net 30%, operator EAGSA), the interest was ceded to the joint
venture partners.
In permits where EAGSA has options to participate in discoveries, dry wells were
drilled in the Mpolo and Chaillu permits (Energy Africa net 5.0%-12.5% options,
operator Agip). Drilling planned in the coming year includes a further well in
the Mpolo permit as well as wells in the Gryphon permit (Energy Africa net 5%
option, operator Anadarko) and in the Etame permit (Energy Africa net 3.75%
option, operator Vaalco).
Mauritania
In the offshore Mauritanian salt basin, 3-D seismic surveys were acquired in
Block 2 (Energy Africa 20%, operator Woodside) and in Block 1 where Energy
Africa secured a 32% interest in September 2002 (operator Dana Petroleum). This
data is currently being interpreted and decisions on whether to commit to
exploration wells are required in mid-2003. The positive results in Block 4 to
the north, where Woodside Petroleum"s Chinguetti and Banda discoveries have
proved a working petroleum system, are encouraging, but questions regarding
source rock maturity remain.
Morocco
In the Cap Draa (Energy Africa 20%, operator Enterprise Oil) and Tiznit (Energy
Africa 32% and operator) permits in the offshore Tarfaya basin, evaluation of
previously acquired 3-D seismic surveys is ongoing and a number of attractive
prospects have been identified. However drilling is not contemplated until the
latter part of 2004.
Namibia
Following disappointing results of the Kudu-6 and Kudu-7 wells in License 2814A,
the previous operator, Shell, withdrew from the licence and its 75% interest was
distributed to the remaining partners. Consequently, Energy Africa now holds a
40% interest and ChevronTexaco, who has assumed operatorship, a 60% interest. A
comprehensive review of reserves and gas marketing options has been undertaken
and a 800 MW power plant in Namibia is considered to be a potentially viable
option. This would consume some 875 bcf over a 20 year period, equating to 350
bcf net to Energy Africa.
South Africa
In the Oribi field (Energy Africa 20%, operator PetroSA), production continued
to decline and in 2003 averaged 3 040 bpd (2002: 6 120 bpd).
Uganda
In Block 3 (Energy Africa 50%, operator Heritage Oil & Gas) the Turaco-1 well
was drilled to a depth of 2 487m and encountered encouraging gas and oil shows
in the bottom section of the well. Due to mechanical difficulties, this section
of the well could not be logged and it is planned that the Turaco-2 well will
penetrate this section as well as intersecting a deeper prospective interval.
It is likely that drilling will commence in mid-2003.
In Block 2 (Energy Africa 50%, operator Hardman Petroleum) located north of
Block 3 and covered largely by Lake Albert, 2-D seismic acquisition is planned
for mid-2003 and will also include that part of Block 3 overlain by the lake.
United Kingdom
Production from the Alba field (Energy Africa 8%, operator ChevronTexaco) was
significantly below initial forecasts at 65 980 bpd (2002: 79 300 bpd) despite
the very successful Alba Extreme South development which was completed on time
and within budget. Production losses stemmed mainly from reduced total
deliverability caused by completion failures in three wells, a longer-than-
anticipated platform shutdown for the installation of additional facilities and
initial operational difficulties on the platform once production of oil from the
Extreme South development commenced. However, all problems have been rectified
and production since November 2002 has averaged over 87 000 bpd. It appears
likely that the target of 83 300 bpd for calendar 2003 will be achieved or
exceeded.
The Caledonia field (Energy Africa 10.06%, operator ChevronTexaco) was also
scheduled to commence production in October 2002 but start-up was delayed to
February 2003 by the failure of the third party platform to enable the hook-up
of the processing and export facilities on schedule. Production in March 2003
was 7 700 bpd and averaged 1 080 bpd for the year (2002: nil bpd). Maximum rate
has not yet been achieved due to a delay in commissioning the gas lift system.
Future Activity
In the year to March 2004, Energy Africa"s net production is expected to remain
at a similar level to that of 2003 as new field developments will not come
onstream in the period.
It is anticipated that at least ten exploration wells will be drilled - four in
Equatorial Guinea and one each in Congo, Gabon, Mauritania, Egypt, Uganda and
the UK North Sea. An appraisal well is planned to further assess the G-13
discovery in Equatorial Guinea and further appraisal drilling may result from
success in the exploration program.
Development of the NBG fields in Equatorial Guinea and the Moho-Bilondo fields
in Congo are expected to commence and further development drilling will be
undertaken in the Nuingo, Etame and Alba fields.
Assessment of new opportunities will continue with a view to maintaining an
appropriately balanced exploration portfolio and selected acquisition
opportunities will be pursued in areas where competitive advantages exist,
including in the UKCS.
Group income statements
Year Year
ended ended
31 March 31 March
2003 2002
Notes $"000 $"000
Total revenues 185 020 144 907
Turnover 184 526 143 996
Cost of production 2 (85 371) (74 822)
Gross income 99 155 69 174
Exploration expenditure
written off (41 325) (26 845)
Administration expenses (15 575) (7 869)
Other operating expenses (333) (50)
Operating profit 41 922 34 410
Interest income 494 911
Interest expense 3 (2 188) (2 162)
Profit on ordinary activities
before taxation 40 228 33 159
Taxation 4 (14 836) (12 588)
Profit on ordinary activities
after taxation and
attributable to ordinary
shareholders 25 392 20 571
Earnings/headline earnings
per share - cents
Basic 24.6 20.1
Diluted 24.6 19.9
Weighted average number of
ordinary shares in issue ("000)
Basic 103 229 102 124
Diluted 103 360 103 161
Group balance sheets
31 March 31 March
2003 2002
Notes $"000 $"000
Employment of capital
Fixed assets 236 668 199 198
Current assets
Inventories 4 096 5 683
Debtors 19 822 18 906
Cash and bank deposits 38 026 18 765
61 944 43 354
Current liabilities 5 (39 436) (36 163)
Net current assets 22 508 7 191
Total assets less
current liabilities 259 176 206 389
Long term interest
bearing project loan 6 (17 000) (10 000)
Deferred taxation (23 660) (10 712)
Decommissioning provision (22 856) (19 059)
195 660 166 618
Capital employed
Share capital 2 647 2 642
Share premium account 102 229 101 525
Other reserves 90 784 62 451
Shareholders" interest 195 660 166 618
Net book value per share - cents
Basic 189.2 161.9
Diluted 189.2 160.9
Number of ordinary shares
in issue at year end ("000)
Basic 103 422 102 913
Diluted 103 422 103 582
Group cash flow information
Year Year
ended ended
31 March 31 March
2003 2002
Notes $"000 $"000
Reconciliation of
operating profit
to net cash flow
from operations
Operating profit 41 922 34 410
Exploration expenditure
written off 41 325 26 845
Depreciation 39 886 36 123
(Profit)/loss on
disposal of fixed assets (10) 17
Exchange loss 333 50
Net cash inflow from
operations prior
to working capital
adjustments 123 456 97 445
Working capital adjustments 2 877 (1 909)
Net cash inflow from operations 126 333 95 536
Cash flow statements
Net cash inflow from operations 126 333 95 536
Returns on investments and
servicing of finance
Interest received 494 919
Interest paid (808) (1 287)
Tax paid (7 750) (12 062)
Investing activities
Exploration expenditure (38 299) (31 241)
Payments to acquire
tangible assets (77 138) (69 305)
Proceeds from sale of fixed assets 20 15
Net cash inflow/(outflow)
before financing 2 852 (17 425)
Financing
Issue of ordinary shares 709 1 714
Increase in bank loans 16 000 10 000
Repayment of loans - (4 591)
Net cash inflow/(outflow)
after financing 19 561 (10 302)
Cash flow from operations
per share - cents
Basic 122.4 93.5
Diluted 122.2 92.6
Group Statement of changes in equity
Share
Share premium Other
Capital account reserves Total
$"000 $"000 $"000 $"000
At 1 April 2001 2 630 99 823 43 004 145 457
Profit attributable to ordinaryshareholders - - 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
Profit attributable
To ordinary
shareholders - - 25 392 25 392
Exchange adjustment - - 2 941 2 941
Arising on issue of shares 5 704 - 709
At 31 March 2003 2 647 102 229 90 784 195 660
Share premium account is not distributable other than as contemplated in the
Companies Act.
Auditor"s report
The financial information has been derived from the audited group annual
financial statements. The unqualified audit opinion of the auditors (Ernst &
Young) is available for inspection at the Company"s registered office.
Notes to the financial statements
1. Accounting policies
Basis of preparation
The financial information has been prepared 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 year.
Measurement and presentation currencies
The Group uses the United States Dollar as its measurement and presentation
currency.
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
2003 2002
$"000 $"000
Operating costs 38 383 35 147
Movement in underlift 1 189 (1 039)
Royalty paid in cash 6 581 5 240
Depreciation 39 218 35 474
85 371 74 822
3. Interest expense
2003 2002
$"000 $"000
Interest payable on loans 1 089 1 184
Finance charge
- unwinding of discount 1 099 978
2 188 2 162
The finance charge represents the unwinding during the year of the discount on
the decommissioning provision.
4. Taxation
2003 2002
$"000 $"000
SA taxation
Normal - current 969 1 809
- prior period (91) -
Foreign taxation
Normal - current 2 873 8 885
- prior period (431) (686)
Deferred
- temporary differences
- current 10 752 2 580
- rate adjustment 764 -
14 836 12 588
The foreign deferred tax charge includes provision for deferred UK Petroleum
Revenue Tax.
5. Current liabilities
2003 2002
"000 $"000
Current portion of borrowings 9 000 -
Corporation tax payable 1 848 6 018
Other taxes and social security costs 171 245
Other creditors 4 271 4 623
Accruals 24 146 25 277
39 436 36 163
6. Borrowings
2003 2002
$"000 $"000
Interest bearing borrowings
Secured loan repayable after morethan one year 17 000
10 000
17 000 10 000
7. Capital commitments
2003 2002
$"000 $"000
Contracted 82 317 42 861
8. Status of financial information
The above information does not constitute statutory financial statements. It has
been extracted from the 2003 Group financial statements that have been approved
by the directors but not yet delivered to the Registrar of Companies.
Oil and gas reserves and production
2003 2002
MMboe MMboe
Reserves
Oil
Commercial oil reserves
Movement in Group net remaining Proven+Probable Reserves
At beginning of year 57.9 47.3
Revisions of previous estimates 0.3 7.3
Discoveries, extensions and other additions 0.6
11.1
Production (8.1) (7.8)
50.7 57.9
Proven+Probable reserves
by type of field
Fields in production 50.7 49.2
Fields under development - 8.7
50.7 57.9
Reserves by category
Proven 31.3 39.2
Proven+Probable 50.7 57.9
Potentially commercial oil reserves
Group net remaining
Proven+Probable reserves 42.0 37.3
Total oil reserves 92.7 95.2
bcf bcf
Gas
Potentially commercial gas reserves
Group net remaining
Proven+Probable reserves 350 210
MMboe MMboe
Production
Group share of production 8.1 7.8
Delivered to host governments (1.0) (0.7)
Movement in underlift 0.1 -
Group production sold 7.2 7.1
Production by location of field
Africa 6.1 5.5
UK 2.0 2.3
8.1 7.8
Summary Rand convenience translation
Year Year
ended ended
31 March 31 March
2003 2002
R million R million
Income statement
Turnover 1 792 1 374
Operating profit 407 328
Net profit 247 196
Earnings/ headline
earnings per share (cents) 239 192
Cash Flow
Cash inflow from operations 1 227 912
Exploration expenditure 372 298
Development expenditure 749 661
Cash inflow from operations
per share (cents) 1 189 893
Balance Sheet
Fixed assets 1 863 2 264
Cash 299 214
Loans 134 114
Net cash 165 100
Net assets 1 540 1 894
Net book value
per share (cents) 1 489 1 840
R/$ exchange rate
(year average) 9.71 9.54
R/$ exchange rate (year end) 7.87 11.37
Date: 26/05/2003 07:00:27 AM Supplied by www.sharenet.co.za
Produced by the JSE SENS Department
