| Mon 3 Nov 2003, 8:40 | | INTERIM RESULTS FOR THE SIX MONTHS ENDED 30 SEPTE |
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ENERGY AFRICA LIMITED - INTERIM RESULTS FOR THE SIX MONTHS ENDED 30 SEPTEMBER
2003
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 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 sustained production levels and continued strong cash
generation in the first half year
Cash generation remains strong - cash inflow from operations $58 million
Average production maintained - 22 050 bpd
Strong balance sheet - net cash at period end $4.1 million; $75 million new
credit facility signed
Encouraging progress with drilling program in Equatorial Guinea
New exploration licences secured in Senegal and North Sea
Active future exploration program - 9 wells before end March 2004
Commenting on the results, Rhidwaan Gasant, Managing Director of Energy Africa
said:
"We have had a busy six months with a high level of exploration and appraisal
activity. The lower rate of production from Ceiba was offset by good increases
from the UK and Gabon although the change in production mix did impact our
operating costs. Exploration activity will accelerate further in the next six
months and we remain well positioned to capitalise on opportunities principally
in our areas of focus."
3 November 2003
Enquiries:
Energy Africa Limited
Rhidwaan Gasant
+27 21 400 7600
College Hill
Nicholas Williams (SA)
Matthew Gregorowski (UK)
+27 11 447 3030
+27 83 607 0761
+44 207 457 2020
Overview
During the six month period to September 2003 an active exploration and
appraisal program was maintained. Additionally, significant new licence
interests were secured in the UK North Sea and in Senegal.
Average production for the period, at 22 050 bpd, was just below that of the
comparable period in 2002, notwithstanding lower than expected Ceiba production.
The lower rate of production in Ceiba was compensated for by higher rates in
both the UK (Alba Extreme South and Caledonia) and in Gabon (Etame and Niungo).
This change in mix of production rates, as recently announced, has led to an
increase in the operating costs per barrel.
Nevertheless as a consequence of higher oil prices in the period, turnover has
increased 4% to $92.8 million; cash inflow from operations, which is regarded as
the more appropriate measure of performance than earnings, was also maintained
at a satisfactory level of $ 58.0 million.
Energy Africa"s balance sheet remains very robust with net cash. During the
period, a further credit facility - for $75 million - was completed in order to
fund the company"s share of development costs, primarily, of the Northern Block
G complex of discoveries in Equatorial Guinea ("NBG"). A revised plan of
development in respect of these is now expected to be submitted to the
authorities in Equatorial Guinea in the first half of 2004.
Development plans for NBG have been postponed while further appraisal drilling,
primarily in the shallow water, is conducted. The ramp-up of Energy Africa"s
production levels will be correspondingly delayed, probably by one year. Two
wells out of the previously announced six well program have been drilled so far
with the remaining four wells planned to be drilled over the next several
months. Results have been encouraging. It is hoped that further exploration
and appraisal drilling success in the shallow water NBG area will further
enhance the economics of the development. In addition Energy Africa will be
participating in five further exploration wells in the next six months, four of
which will be outside of Equatorial Guinea.
We are also encouraged by the extensive discussions that have been taking place
with all interested parties in relation to the feasibility of an 800 MW power
plant in Namibia, fueled by gas from the Kudu Gas field in which the Company has
a 40% interest. There is real political will in Namibia for advancing the
project, of which the power plant in Namibia would, it is expected, represent
just the first phase.
Whilst production performance at Ceiba is expected to be largely responsible for
a decline in Energy Africa"s overall level of production in the second half, the
average level for the year as a whole is expected to be some 21 500 bpd.
Energy Africa has again put in place a limited level of zero cost collar oil
price hedging arrangements, this time for the period until the end of December
2004 in order to take advantage of current high prices to secure a guarantee of
reasonable minimum price levels. At the same time, we are retaining as much
price upside as possible for a proportion of the Company"s production.
We believe that the outlook for Energy Africa"s continued success remains
healthy and intend to maintain the Company"s strategy of increasing value mainly
through further exploration success.
Financial review
Summary
Energy Africa reports strong, albeit marginally lower, cash flow from
operations. Balance sheet continues to be solid with net cash at the end of the
period.
Cash flows
Cash inflow from operations was $58.0 million, a decrease of 4% compared to
$60.7 million in 2002.
Tax payments were $1.3 million, lower than the $4.7 million incurred in 2002 due
to the timing of payments.
Exploration expenditure was $26.5 million, an increase from the 2002 spend of
$19.4 million, reflecting the higher share of costs of wells drilled during the
period. Development spend was $36.2 million of which the majority was incurred
in Equatorial Guinea (2002: $41.3 million).
Loan repayments amounted to $2.0 million compared to $10.0 million of loan
drawdowns in 2002. The resultant net cash outflow after financing was $9.0
million (2002: inflow of $5.6 million).
Income statement
Turnover increased by 4% to $92.8 million from $89.4 million in 2002, reflecting
a 4% increase in realised oil prices. Turnover is reflected after delivering
0.4 MMbbl (2002: 0.5 MMbbl) of hydrocarbons to host governments under the terms
of Production Sharing Agreements.
Cost of production was $48.8 million (2002: $42.3 million). On a per barrel
basis operating costs were $5.63 per bbl (2002: $4.18), reflecting the effect of
lower production from Ceiba (where costs are mainly fixed costs) leading to a
different mix in production from the various fields as well as additional costs
at Tchatamba and Oribi. The depletion charge was $5.07 per bbl (2002: $4.86),
much of the increase being due to exchange rate movements.
The exploration charge increased to $20.5 million from $17.1 million in 2002 as
described above. Administration charges decreased to $5.2 million (2002: $7.3
million).
Net interest expense increased to $1.3 million (2002: $0.7 million) due to
higher average loan balances over the period as well as fees on the completion
of the $75 million loan facility. Taxation increased to $8.8 million (2002:
$6.1 million) due to higher production and revenue from Alba, resulting in
greater UK taxation.
Net profit after taxation was $7.3 million (2002: $15.5 million).
Balance sheet
Fixed assets were $257.5 million and comprise mainly the net book values of
producing assets. Net current assets were $11.0 million and include cash of
$28.1 million. Loans were $24.0 million resulting in a net cash balance of $4.1
million. The $75 million loan facility, arranged to fund the Company"s
development projects, was completed in June, but is currently undrawn.
Risk management
The company has continued its policy to protect a proportion of its operating
cash flow against lower oil prices through entering into hedging contracts in
the form of zero cost collars. Such contracts are in place for the period 1
October 2003 to 31 December 2003 at weighted average Brent oil floor prices of
$25.00 and ceiling prices of $29.20 at volumes of 8 000 bbl per day. In
addition, similar contracts for the period 1 January 2004 to 31 December 2004
have been entered into at weighted average Brent oil floor prices of $24.50 and
ceiling prices of $29.00 at aggregate average volumes of 4 984bbl per day.
Operating review
Production and development
Energy Africa"s working interest share of production for the six months to 30
September 2003 was 4 036 000 bbl of oil and LPG, an average of 22 050 bpd
compared with 22 540 bpd for the same period in 2002. The contribution of the
various fields to this total has changed significantly. Net production from the
Ceiba field fell by 48% from 8 860 bpd to 4 630 bpd. Production was adversely
affected by operational problems, some of which remain to be addressed. This
decline was compensated for by the increased contribution from the Alba field
following the successful completion of the Alba Extreme South development and
new production from the Niungo and Etame fields in Gabon and the Caledonia field
in the UK North Sea.
The average benchmark Brent oil price for the period was $27.23 per bbl (2002:
$26.00 per bbl). The average realised price was $25.01 per bbl (2002: $23.99
per bbl), a discount of 8% (2002: 8%)
Development activity was at a reduced level, being comprised largely of in-fill
drilling in the Ceiba, Alba and Niungo fields.
Exploration and appraisal
The company has participated in five exploration wells since 1 April 2003, one
of which was still in progress at the period-end. All four of the completed
wells yielded good oil shows and two of these intersected potentially productive
oil columns. One appraisal well which confirmed potentially commercial reserves
was completed, and one was in progress at period-end.
Congo (Brazzaville)
Production from the Nkossa field (Energy Africa 4%) averaged 37 100 bpd of oil
and LPG (2002: 47 700 bpd). A further decline in production will occur over the
coming year but it is expected to be reversed by the development of the Nsoko
and Nkossa South South reserves which should contribute to production in October
2004.
Tendering for the Moho-Bilondo development resulted in an unacceptable level of
capital expenditure, based on the proved reserve. Development options are
consequently being re-assessed but additionally several low risk prospects have
been identified in the immediate vicinity of the Moho-Bilondo discoveries and an
exploration well to test the most significant of these is planned for the first
quarter of 2004.
In the K/A - IMI Unit Area (Energy Africa 2%), the KX-1 well was drilled to test
a major channel feature. The well intersected an excellent oil bearing sandstone
reservoir; however, a shallower-than-prognosed oil-water contact limits the
reserve potential of the channel system. There remains the potential for
commercial reserves in the greater channel complex and possible drilling
locations are being assessed.
Egypt
In the Matruh licence (Energy Africa 20%), a well to test an onshore oil
prospect is scheduled to commence in November 2003. The prospect is analogous
to recently discovered fields in the vicinity and has a relatively high
probability of success.
Equatorial Guinea
Oil production in the Ceiba field (Energy Africa 14.25%) averaged 32 500 bpd
(2002: 62 200 bpd). Production was negatively impacted by a mechanical failure
on a subsea pump on the Ceiba-3 well which resulted in the well being shut-in
for most of the period. Additionally, late in the period the Ceiba-2 well
unexpectedly failed for reasons not yet established. Further production wells
have been delayed pending the results of a high resolution 3-D seismic survey
currently in progress. However, the water injection program which has been the
main development focus over the past year has been successful with an injection
rate averaging 104 000 bpd (2002: 35 150 bpd), providing improved pressure
maintenance.
Full field artificial lift (subsea multiphase pumps) is to be installed during
the fourth quarter of 2003 and an additional injector, which has been drilled
and completed, will be brought on line. A shut-down of the production facility
for routine maintenance is also scheduled in this period. The net impact of
these events will be that production from the Ceiba field will be well below
forecast for the full financial year but is expected to recover thereafter as
new producers are drilled and the benefits of the multiphase subsea pumps are
seen.
As communicated in the Chairman"s Statement in July 2003, the plans of
development ("PODs") for the Elon, Oveng and Okume fields in the northern Block
G area (NBG) which had been submitted to the Equatorial Guinean authorities,
were withdrawn for revision. A high resolution 3-D seismic survey covering this
area was commenced in September and is currently still in progress. It is
anticipated that the data will enable a more precise delineation of the various
fields. Additionally a six-well exploration/appraisal programme in NBG was
commenced in September. This includes two deeper water wells, one of which,
Okume-5, was successfully completed, and four wells in shallow water utilising a
jack-up rig. One of these, completed after the end of the period, yielded
encouraging results and the reserve potential is being assessed. The shallow-
water wells will test low risk prospects in the vicinity of the Elon field and
provide additional reservoir information in the field itself. It is anticipated
that the results of the current seismic and drilling programs will be integrated
into revised POD"s in the first half of 2004. Assuming Government approval
during that period, the effect will delay first production from NBG to mid 2006.
Also in September 2003, the G13-3 well, located to further appraise the G13
discovery, was commenced. This was completed subsequent to the end of the
period, unfortunately with negative results.
In Block L (Energy Africa 20%), as previously reported, the Balena-1 well was
completed with minor oil shows. However, a number of further prospects have
been identified and it is possible that one of these may be drilled in the
second half of the year.
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 8 190 bpd for the period (2002: 6 900 bpd). The increase in
production is attributable to the contribution from the Niungo and Etame fields
which were not on line for most of the comparable period. The new production
more than offset the natural decline in the other fields, all of which
performed in line with expectations.
In the Akoum permit (Energy Africa net 50%) two exploration wells were completed
as detailed in the Annual Report for 2003. One of these intersected a
potentially commercial oil column but additional seismic has indicated that the
reserve is too small to merit development at the present time. A 3-D seismic
survey covering the southern portion of the permit was completed and results are
currently being assessed.
Mauritania
In Blocks 1 (Energy Africa 32%) and 2 (Energy Africa 20%) previously acquired 3-
D surveys were interpreted and prospect inventories compiled. Risk assessment
is currently being undertaken and the respective partner groups are considering
whether to enter the next period in which a commitment to drill a well in each
block is required.
Morocco
Assessment of 3-D seismic surveys previously acquired in the Cap Draa concession
(Energy Africa 20%) and the Tiznit concession (Energy Africa 32%) was ongoing
during the period. In the Tiznit concession, probabilities for commercial
success for the identified prospects are below the company"s threshold and entry
into the next period, which carries a drilling commitment, is unlikely. In the
Cap Draa permit, several prospects have been identified and a well is scheduled
to be drilled in 2004.
Namibia
The company has a 40% interest in Licence 2814A in which the Kudu gas field is
located. Extensive discussions have been held with Nampower, Namcor and the
Department of Mines and Energy regarding the feasibility of an 800MW combined
cycle gas turbine generator in Namibia. This would likely be the first phase
of a larger development and would contribute significantly to establishing the
true reserve potential of the field both through the acquisition of dynamic
reservoir data and by enhancing the commerciality of drilling further wells.
Senegal
In July 2003 Energy Africa announced the signature of a petroleum exploration
agreement in respect of the offshore St Louis Block. Energy Africa has a 90%
interest and Petrosen, the State oil company, a 10% interest. Seismic surveys
will be undertaken in 2004 or 2005 in selected areas.
South Africa
Oil production from the Oribi field (Energy Africa 20%) averaged 1 670 bpd
(2002: 3 700 bpd). Commercial production is expected to cease in early 2004.
Uganda
In September 2003, acquisition of 2-D seismic data commenced in the portions of
Blocks 2 and 3 (Energy Africa 50% in each) covered by Lake Albert and the survey
is still in progress. After some delays due to operational factors, the Turaco-
2 well in Block 3 was commenced early in October.
United Kingdom
The Alba field in the Central North Sea (Energy Africa 8%) averaged 81 760 bpd
(2002: 51 500 bpd). It is anticipated that this level will be maintained
through the remainder of the year. The Caledonia field (Energy Africa 10%)
which was brought on production in February 2003, averaged 8 660 bpd (2002: nil)
and performed in line with expectations.
In July 2003, Energy Africa negotiated an agreement in respect of a 20% interest
in blocks 16/12b and 16/13d on the UK Continental Shelf ("UKCS") and a well to
test a potential stratigraphic trap is scheduled to spud in late December. In
the same area Energy Africa secured a 50% interest in block 16/13b through an
application in the 21st Seaward Licensing Round on the UKCS. In the same
licensing round, Energy Africa was also awarded 100% interests in six blocks -
211/17, 211/23d & 28b, 211/24c and 3/5 & 10c - constituting four contiguous
areas in the East Shetland Basin. These licenses in the "Promote" category have
an initial two-year period in which the commitment is limited to geological and
geophysical interpretations.
Future Operational Activity
In the six months to 31 March 2004, Energy Africa"s net production is expected
to decline to 20 900 bpd mainly as a result of reduced production from the Ceiba
field, reflecting the facility shutdown and lower-than-anticipated productive
capacity. Consequently average production for the full year will be of the
order of 21 500 bpd.
Exploration activity will accelerate in the period to 31 March 2004. In
Equatorial Guinea the two wells currently drilling will be completed and it is
anticipated that a further five wells will be drilled. The Turaco-2 well in
Uganda will be completed and it is anticipated that one well each will be
drilled in Egypt, the Congo and in the UKCS. Energy Africa"s expenditure
associated with this programme is expected to be slightly lower than in the
first half. Capital expenditure for the full year will be lower than forecast
at approximately $60 million, following the delay of the NBG development.
This interim report is signed on behalf of the Board.
Dato" M Idris Mansor
R Gasant
30 October 2003
Group cash flow statements
6 Months 6 Months Year
to to ended
30 Sep 30 Sep 31 Mar
2003 2002 2003
(Reviewed) (Reviewed) (Audited)
$"000 $"000 $"000
Reconciliation of
operating profit
to net cash flow
from operations
Operating profit 17 423 22 262 41 922
Exploration expenditure
written off 20 474 17 130 41 325
Depreciation 20 906 20 365 39 886
Profit on disposal
of fixed assets - (9) (10)
Exchange loss 912 471 333
Net cash inflow from
operations prior to
working capital
adjustments 59 715 60 219 123 456
Working capital
adjustments (1 761) 445 2 877
Net cash inflow
from operations 57 954 60 664 126 333
Cash flow statement
Net cash inflow
from operations 57 954 60 664 126 333
Returns on
investments and
servicing of finance
Interest received 208 217 494
Interest paid (1 203) (351) (808)
Tax paid (1 287) (4 654) (7 750)
Investing activities
Exploration
Expenditure (26 469) (19 432) (38 299)
Payments to acquire
tangible assets (36 190) (41 340) (77 138)
Proceeds from sale
of fixed assets - 18 20
Net cash(outflow)/inflow
before financing (6 987) (4 878) 2 852
Financing
Issue of ordinary
Shares - 458 709
Increase in bank loans - 10 000 16 000
Repayment of loans (2 000) - -
Net cash (outflow)/
inflow after financing (8 987) 5 580 19 561
Cash flow from operations
per share - cents
Basic 56.0 58.9 122.4
Diluted 56.0 58.2 122.2
Group income statements
6 Months 6 Months Year
to to ended
30 Sep 30 Sep 31 Mar
2003 2002 2003
(Reviewed) (Reviewed) (Audited)
$"000 $"000 $"000
Total revenues 93 013 89 629 185 020
Turnover 92 805 89 412 184 526
Cost of production
(note 2) (48 846) (42 267) (85 371)
Gross income 43 959 47 145 99 155
Exploration expenditure
written off (20 474) (17 130) (41 325)
Administration expenses (5 150) (7 282) (15 575)
Other operating costs (912) (471) (333)
Operating profit 17 423 22 262 41 922
Interest income 208 217 494
Interest expense (1 536) (872) (2 188)
Profit on ordinary
activities before
taxation 16 095 21 607 40 228
Taxation (note 3) (8 762) (6 063) (14 836)
Profit on ordinary
activities after taxation
and attributable to
ordinary shareholders 7 333 15 544 25 392
Earnings/headline earnings
per share - cents
Basic 7.1 15.1 24.6
Diluted 7.1 14.9 24.6
Weighted average number
of ordinary
shares in issue ("000)
Basic 103 422 103 059 103 229
Diluted 103 422 104 168 103 360
Group balance sheets
30 Sep 30 Sep 31 Mar
2003 2002 2003
(Reviewed) (Reviewed) (Audited)
$"000 $"000 $"000
Employment of capital
Fixed assets 257 493 220 345 236 668
Current assets
Inventories 2 147 3 793 4 096
Debtors 22 032 26 885 19 822
Cash and bank deposits 28 147 23 942 38 026
52 326 54 620 61 944
Current liabilities
(note 4) (41 317) (34 750) (39 436)
Net current assets 11 009 19 870 22 508
Total assets less
current liabilities 268 502 240 215 259 176
Long term loan (13 000) (15 500) (17 000)
Deferred taxation (25 827) (17 738) (23 660)
Decommissioning
Provision (23 936) (21 007) (22 856)
205 739 185 970 195 660
Capital employed
Share capital 2 647 2 645 2 647
Share premium account 102 229 101 980 102 229
Other reserves 100 863 81 345 90 784
Shareholders" interest 205 739 185 970 195 660
Net book value per
share - cents
Basic 198.9 180.1 189.2
Diluted 198.9 178.4 189.2
Number of ordinary
shares in issue at
period end ("000)
Basic 103 422 103 233 103 422
Diluted 103 422 104 237 103 422
Group Statement of changes in equity
Share
Share premium Other
Capital account reserves Total
$"000 $"000 $"000 $"000
At 30 September 2002 2 645 101 980 81 345 185 970
Profit attributable
to ordinary
shareholders - - 9 848 9 848
Exchange adjustment - - (409) (409)
Arising on issue
of shares 2 249 - 251
At 31 March 2003 2 647 102 229 90 784 195 660
Profit attributable to
ordinary shareholders - - 7 333 7 333
Exchange adjustment - - 2 746 2 746
At 30 September 2003 2 647 102 229 100 863 205 739
Share premium account is not distributable other than as contemplated in the
Companies Act.
Auditor"s report
The financial information for the six months ended 30 September 2003 set out
from and including the Group cash flow statements 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. This interim financial report is presented in accordance
with AC127/IFRS34 - Interim Financial Reporting. These accounting policies are
consistent with those stated in the annual report for the year ended 31 March
2003.
6 Months 6 Months Year
to to ended
30 Sep 30 Sep 31 Mar
2003 2002 2003
(Reviewed) (Reviewed) (Audited)
$"000 $"000 $"000
2. Cost of production
Operating costs 22 736 17 244 38 383
Movement in underlift 1 873 2 033 1 189
Royalty paid in cash 3 760 2 948 6 581
Depreciation 20 477 20 042 39 218
48 846 42 267 85 371
3. Taxation
Corporation tax
- current 7 830 680 3 842
- prior period - (399) (522)
Deferred tax
- current 932 5 038 10 752
- rate change - 744 764
8 762 6 063 14 836
4. Current liabilities
Current portion
of borrowings 11 000 4 500 9 000
Corporation tax payable 8 658 1 748 1 848
Other creditors
and accruals 21 659 28 502 28 588
41 317 34 750 39 436
5. Capital commitments
Contracted and approved 50 477 22 304 82 317
6. Geographical analysis
Turnover
Africa 58 070 70 352 136 622
Non-Africa 34 735 19 060 47 904
92 805 89 412 184 526
Results of operations
Africa 4 887 18 480 26 147
Non-Africa 9 836 5 472 16 847
14 723 23 952 42 994
Unallocated items (7 390) (8 408) (17 602)
Profit attributable to
ordinary shareholders 7 333 15 544 25 392
7. Production MMbbl MMbbl MMbbl
Group share of
Production 4.0 4.1 8.1
Delivered to host
Governments (0.4) (0.5) (1.0)
Movements in underlift 0.2 0.2 0.1
Group production sold 3.8 3.8 7.2
Summary Rand convenience translation
6 Months 6 Months Year
to to ended
30 Sep 30 Sep 31 Mar
2003 2002 2003
R million R million R million
Cash Flow
Cash inflow
from operations 439 633 1 227
Exploration expenditure 200 203 372
Development expenditure 274 432 749
Cash inflow from operations
per share - cents 424 615 1 189
Income statement
Turnover 703 934 1 792
Operating profit 132 232 407
Net profit 56 162 247
Earnings/ headline
earnings per share - cents 54 158 239
Balance Sheet
Fixed assets 1 792 2 332 1 863
Cash 196 253 299
Loans (167) (212) (205)
Net assets 1 432 1 969 1 540
Net book value
per share - cents 1 385 1 907 1 489
R/$ exchange rate
(period average) 7.57 10.44 9.71
R/$ exchange rate
(period end) 6.96 10.59 7.87
All income statement and cash flow figures have been translated at the average
exchange rate for the period. All balance sheet figures have been translated at
period end rates of exchange.
Sponsor
Merrill Lynch South Africa (Pty) Limited
Date: 03/11/2003 07:23:31 AM Supplied by www.sharenet.co.za
Produced by the JSE SENS Department
