| Thu 25 Oct 2001, 0:00 | | Energy Africa - Interim Report For The Half Year E |
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Energy Africa Limited
Registration number: 1995/007140/06
(Incorporated in the Republic of South Africa)
Share code: ENR
ISIN: ZAE000010427
Interim Report for the half year ended 30 September 2001
Highlights
* Two significant discoveries in Equatorial Guinea
* Average production increased by 45% to 22 380 bpd
* Cash inflow from operations increased by 24% to $58 million
* Strong balance sheet reflecting an increase in net cash from year end
* Change to US$ reporting
* New management appointments
Commenting on the results, Rhidwaan Gasant, Managing Director of Energy
Africa said:
"This was an exceptional six months for the company. We will be capitalising
on the recent exploration success in Equatorial Guinea with an accelerated
drilling programme in that country as well as drilling a number of high
impact wells elsewhere. The company is extremely well positioned to meet its
target of doubling production within the next three years."
25 October 2001
Enquiries:
Energy Africa Limited, Cape Town Tel: +27 21 400 7600
Rhidwaan Gasant
Adrian Nel
Corporate Image, Cape Town Tel: +27 21 426 1233
Tamra Veley
College Hill, London Tel: +44 20 7457 2020
Nicholas Williams
Overview
The six month period was the most successful in Energy Africa's history,
both in terms of operational results, and more importantly, in terms of
exploration success.
Compared with the same period in 2000, production increased by 45% to 22 380
bpd, turnover increased by 25% to $79 million and cash flow from operations
increased by 24% to $58 million. Due largely to increased volumes and a
significantly lower exploration charge, net profit increased from $8.7
million to $22.1 million.
More significant, however, for the future of Energy Africa were the two new
discoveries made in Equatorial Guinea during the period under review, on the
Okume and Oveng prospects. Not only are these discoveries extremely
important in themselves, but they greatly enhance the prospectivity of a
number of other features with similar geological and geophysical
characteristics mapped on Blocks F and G. As a consequence, the exploration
and appraisal programme has been accelerated, with seven additional wells
planned for the period to March 2002.
Important new wells are also planned in Angola Block 9, Haute Mer in the
Congo, in various Gabon permits where Energy Africa Gabon SA holds back-in
rights, and in the Kudu field in Namibia.
Development activities continued at a high level. In the Ceiba field in
Equatorial Guinea, two production and two water injection wells were
successfully completed and the Phase 1a development is on schedule for
production in February 2002. In Gabon two production wells were drilled in
the Echira field and preparations for the Niungo development were commenced,
whilst in the UK North Sea development plans for the Alba Extreme South area
and the Caledonia field were approved and will be implemented in the next
twelve months.
The operational results for the second half will not match those for the
first half. As forecast in the Annual Report for the year ended 31 March
2001, production for the full year to end-March 2002 should average 21 000
bpd. Production for the next six months is therefore expected to average 19
000 bpd, reflecting the planned shut-in of the Ceiba field to put in place
the larger oil production and water injection facilities required for the
next stage of field development, as well as some decline in production prior
to the commencement of water injection. Lower production, albeit temporary,
coupled with lower anticipated oil prices and increased exploration costs,
will impact the results.
Nevertheless the coming six months promises to be an exciting and rewarding
time for your company. A number of high impact wells are planned. There
will be further growth of production from the Ceiba field as the second
phase development comes on line at the end of the period. We will continue
to focus our efforts on Africa which now accounts for over two-thirds of the
company's production. We have recently acquired new exploration acreage in
Uganda and we expect to have entered into additional exploration prospects
in West Africa by the year-end.
As announced at the time of the Company's Annual General Meeting in July,
Rhidwaan Gasant was appointed to the Board as Managing Director with effect
from 1 August. At the same time Adrian Nel was appointed Chief Operating
Officer and Andrew Windham joined the Board as Commercial Director. In
addition Peter Elwes, who remains a Non-executive Director, relinquished his
temporary responsibilities as Deputy Chairman.
Financial review
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. Comparatives referred to in this review are in
respect of the comparative six month period to 30 September 2000.
Summary
Energy Africa reports continued improvement in its financial results.
Strong cash generation through sustained growth in production, up 45% for
the period, enables the group to pursue an ambitious active exploration and
development programme.
Cash flows
Net cash flow from operations increased 24% to $58.3 million from $47.0
million in 2000.
Exploration expenditure was $8.9 million compared to $20.1 million in 2000,
reflecting the timing of drilling activity and an increase in development
costs, of which $29.0 million was on Ceiba, to $41.6 million from $24.8
million in 2000.
Loan repayments, comprising mainly the final repayments on the Nkossa
project loan, were $4.6 million (2000: $2.6 million). The resulting net
cash outflow after financing was $0.4 million (2000: $2.5 million).
Income statement
For the six months ended 30 September 2001 turnover increased to $79.4
million, an increase of 25% over the $63.6 million for the comparative six
months ended 30 September 2000. This increase was the result of the 48%
increase in volumes sold, offset by the 15% decrease in the realised oil
price. Turnover is reflected after delivering 0.4 MMbbl (2000: 0.3 MMbbl)
of hydrocarbons to host governments under the terms of Production Sharing
Agreements.
Cost of production was $34.2 million compared to $22.9 million in 2000. On
a per barrel basis, total cost of production was $8.35 per bbl (2000: $8.14
per bbl), which included operating costs of $3.96 per bbl and depletion of
$4.08 per bbl (2000: $3.92 and $4.06 respectively).
Exploration costs written off decreased to $9.8 million from $21.0 million
in 2000, reflecting the timing of drilling activity. After administration
charges of $3.3 million (2000: $3.9 million) operating income increased to
$31.8 million from $16.6 million in 2000.
Taxation was $9.5 million (2000: $8.9 million). The lower effective tax
rate was due to the lower exploration expenditure.
Net profit after taxation increased to $22.1 million from $8.7 million in
2000, mainly due to the increase in production and the lower exploration
charge.
Balance sheet
Fixed assets were $167.6 million and comprise mainly the net book values of
producing assets. Current assets include cash of $28.2 million. Loans were
all fully repaid during the period. Net cash increased to $28.2 million
from the $24.7 million net cash at the 31 March 2001 year end.
Operating review
Production and development
Energy Africa's working interest share of production for the six months to
30 September 2001 was 4 095 000 bbl of oil and LPG, an average of 22 380 bpd
compared with 15 390 bpd for 2000, an increase of 45%. The increase in
production reflected the full effect of Ceiba and the increased share in
production from the Gabonese fields. The average benchmark Brent oil price
for the period was $26.32 per bbl (2000: $28.69 per bbl), an 8% decrease.
The average price realised was $22.81 per bbl (2000: $26.74 per bbl), a
discount of 13% on the Brent crude oil price (2000: 7%) principally due to
the greater contribution of Ceiba, which has traded at a higher discount.
In the Ceiba field in Equatorial Guinea, two previously drilled wells were
successfully completed for production. Additionally two water injector
wells were drilled. At the Alba field in the UK North Sea development
drilling was ongoing whilst two new wells were drilled in the Echira field
in Gabon.
Exploration and appraisal
Three exploration wells were drilled in the period, two of which were oil
discoveries. Both of these were in Block G in Equatorial Guinea whilst the
third well, in the Ofoubou Permit in Gabon was plugged and abandoned.
Ongoing assessment of opportunities resulted in the acquisition of two new
licences in Uganda and the identification of several new opportunities which
will be pursued in the coming period.
Angola
In Angola Block 9 (Energy Africa 15%) a well, to test a large Albian raft in
shallow water, is scheduled to commence early in November. In the event of
success, other rafts in the block provide upside potential.
Congo Brazzaville
Production from the Nkossa field (Energy Africa 4%) averaged 58 590 bpd of
oil, condensate and LPG (2000: 65 630 bpd). A re-evaluation of the
undeveloped southern extension of the Nkossa field suggests that a
significant reserve may be present and an appraisal well is scheduled for
early 2002. In the Haute Mer Permit (Energy Africa 4%), a high resolution 3-
D survey was acquired over the Moho-Bilondo fields and the data used to
locate the Bilondo-2 appraisal well which is scheduled to be drilled in
November 2001. The Nsoko-2 appraisal well yielded disappointing results and
a development is unlikely. The Governments of Angola and Congo have agreed
a Joint Development Area covering the disputed border zone between the two
countries. This should allow the potentially very large Nkoumbi structure
to be tested, probably early in 2002.
Egypt
Prospect generation continued in the Matruh Licence (Energy Africa 20%) and
a large structure has been identified in the eastern onshore area. It is
likely that a 3-D seismic survey will be acquired in 2002 over Tertiary
leads in the offshore whereafter targets will be selected for drilling,
probably in 2003.
Energy Africa is also currently evaluating acreage included in the current
bid round which closes in March 2002 and several areas of interest have been
identified.
Equatorial Guinea
Production in the Ceiba field (Energy Africa 14.25%) averaged 35 900 bpd for
the period. This was somewhat higher than expected. However, in line with
expectations, the lack of pressure support is now evident and production in
September averaged only 20 000 bpd. As previously advised, the decline is
expected to continue until additional wells and water injection are brought
onstream in February. Production in January will be minimal as the field
will be shut-in for the change out of the Sendje Berge for the Berge Hus
FPSO. The Berge Hus will have a fluid handling capacity of 160 000 barrels
of fluids per day and a water injection capacity of 135 000 bpd.
Development of the field continued with the successful drilling of the Ceiba-
11 and Ceiba-12 water injectors and the completion for production of Ceiba-5
and Ceiba-10. The Ceiba-8 production well is currently being completed
whereafter the Sedco 700 drilling rig will move to the Okume area for
appraisal and well completion activities.
Exploration in Block G (Energy Africa 15%) produced two very significant
discoveries with the Okume-1 and Oveng-1 wells. The Okume-1 well
intersected 52.5m of net oil-bearing sandstones of excellent reservoir
quality whilst the Oveng-1 well intersected a similar section with 51m of
net pay. The wells tested separate structures 15km and 20km north east of
Ceiba respectively, and both yielded oil with a gravity of 36-37x API,
significantly lighter than that of the Ceiba crude (28x API). These
successes resulted in a revision of the drilling programme and the R.F.
Bauer drill rig has been contracted for seven firm and five optional wells.
The programme commenced in mid-October with appraisal wells on the Okume
discovery - one with the Bauer and another with the Sedco 700. If
successful, it is likely that development of the Okume field will commence
in 2002, possibly in the form of a fast-track development similar to that
implemented on the Ceiba field. Additionally the successes at Okume and
Oveng have demonstrated the efficacy of specialised seismic processing to
discriminate oil-bearing sands and a number of other prospects with similar
characteristics will be tested, both in the immediate vicinity of Okume-
Oveng and in other areas of Blocks G and F.
Gabon
Energy Africa's share of Energy Africa Gabon SA, in which it holds a 50%
interest, averaged 7 000 bpd for the period (2000: 4 100 bpd). The increase
reflects the full effect of the additional 12.5% interest purchased from the
Gabon Government in February as well as increased production from the
Tchatamba fields, offset by declining production in the Limande and Moukouti
fields.
Development drilling in the Echira field (Echira-12 and 13) was less
successful than expected, mainly due to mechanical problems encountered in
drilling and completing the intended horizontal sections. Echira-13 was
brought onstream in mid-September. Echira-12 will be brought onstream in
October. The Niungo development was approved and work on roads, pipelines
and a gas injection well was undertaken. Completion of three wells for
production will commence in March and first oil is expected towards the end
of the first quarter of 2002.
The Ofan-1 exploration well in the Ofoubou permit (EAGSA 60%, operator) was
completed in September, intersecting good quality water-bearing Gamba
sandstones with strong oil shows. Although disappointing, the results do
indicate potential for oil accumulations at the Gamba level and a re-
evaluation of the area is in progress. In the Azobe Permit (EAGSA 35%) the
AZFM-1 well on the Framboise prospect is scheduled to commence in the latter
half of October.
In the permits in which EAGSA has options to acquire interests in the event
of commercial discoveries, drilling was delayed in the Mpolo and Chaillu
permits due to a problem encountered with the contracted rig and the wells
have been rescheduled for the first quarter of 2002. In the Tolo permit
(EAGSA 10%) operated by BHP, the IKA Marin-1 well was spudded in mid-
September and is expected to reach the primary target in mid-October whilst
in the Kenguerie permit (EAGSA 15%), the Kenpil-1 well is expected to
commence drilling in November 2001. In the Etame permit (EAGSA 7.5%) where
reserves are estimated to be in excess of 40 million bbls, first production
is anticipated late in 2002.
Libya
No additional acreage has been acquired in Libya and work was confined to
evaluating prospects on which to drill the last commitment well on Blocks
NC184/185 (Energy Africa 20%).
Namibia
A re-evaluation by Shell of development options for the Kudu gas field
(Energy Africa 10%) has indicated that Liquified Natural Gas (LNG)
production from a floating facility could be economically attractive given
the rapidly rising demand worldwide. One of the pre-requisites for such a
development is to prove up sufficient reserves. In order to achieve this a
supplementary 3-D survey, to commence in October and a two-well appraisal
drilling programme, to commence in January 2002 have been approved. If
results are positive, feasibility and engineering studies will be commenced
immediately in order to make a final investment decision by end-2002, a
timing requirement for committing to LNG sales agreements for 2006.
Production of some 5 million tons of LNG per year is envisaged, requiring a
production rate of the order of 850 million cubic feet of gas per day.
Feasibility studies for power generation in both Namibia and the Western
Cape continue and the possibility of using LNG as feedstock is not excluded.
South Africa
Production in the Oribi Field (Energy Africa 20%) averaged 6 640 bpd for the
period (2000: 13 000 bpd). The accelerating decline is in line with
expectations and production is expected to cease early in 2003. Studies in
respect of gas production for Mossgas from the E-AG (Energy Africa 10.56%)
and E-BA (Energy Africa 6.98%) blocks have commenced although a development
decision is not imminent.
Uganda
Energy Africa has acquired 50% interests in Blocks 2 and 3 in the Albertine
graben in Uganda, operated respectively by Hardman Resources and Heritage
Oil and Gas. The PSA for Block 2 was signed early in October and Government
approval for participation in Block 3 was received in mid-September. The
Albertine graben is analogous with rift basins in Sudan where commercial
production has been established despite very significant distances to
seaports. The graben shows a considerable thickness of Tertiary and
Cretaceous sediment and the presence of source rocks is indicated by well-
developed oil seeps at points along the graben margins. Seismic surveys to
identify prospective structures are planned in the onshore area of Block 3,
commencing in the fourth quarter of 2001 and in the lake area of Block 2
commencing early in 2002. A well is planned in Block 3 in mid-2002.
United Kingdom
The Alba field in the central North Sea (Energy Africa 8%) averaged 82 500
bpd (2000: 75 700 bpd) which is once again an excellent performance.
Development plans for the Alba Extreme South area have been approved by
partners and submitted to the Government authorities. First oil is still
planned for October 2002 but production is expected to decline somewhat from
current levels ahead of the new production coming online. Also in the North
Sea, the development plan for the Caledonia field (Energy Africa 10%) has
been approved by partners and submitted to the Government authorities.
First production is also scheduled for October 2002 at an initial rate of 12
000 bpd.
Future operational activity
In the six months to March 2002 Energy Africa's production from existing
fields is expected to average 19 000 bpd, the decline from the first half of
the year reflecting reduced production from Ceiba until February 2002, which
period will include a shut-in of the field for approximately one month for
the change out of FPSOs.
Exploration and appraisal wells in the next period include one well in each
of Namibia and Angola, two wells in Congo, wells in Gabon (including four in
respect of which EAGSA does not have to pay exploration costs) and seven
wells in Equatorial Guinea. Energy Africa's expenditure associated with
this programme is expected to be in the region of $20 million, approximately
double the amount expended in the period to end-September.
This interim report is signed on behalf of the Board.
Dato' M Idris Mansor
R Gasant
24 October 2001
Group income statement
Six months to Six months to Year ended
30 Sept 2001 30 Sept 2000 31 March 2001
(Reviewed) (Reviewed) (Audited)
$'000 $'000 $'000
Total revenues 80 024 65 293 141 987
Turnover (note 2) 79 411 63 562 138 512
Cost of production
(note 3) (34 207) (22 936) (50 784)
Gross income 45 204 40 626 87 728
Exploration expenditure
written off (9 771) (20 998) (35 683)
Administration expenses (3 261) (3 939) (10 572)
Other operating
(costs)/income (377) 945 1 742
Operating profit 31 795 16 634 43 215
Interest income 613 1 731 3 475
Interest expense (719) (711) (1 545)
Profit on ordinary
activities before
taxation 31 689 17 654 45 145
Taxation (note 4) (9 541) (8 926) (20 030)
Profit on ordinary
activities after taxation
and attributable to
ordinary shareholders 22 148 8 728 25 115
Earnings/headline earnings
per share - cents
Basic 21.7 8.7 24.9
Diluted 21.5 8.6 24.7
Weighted average number of ordinary
shares in issue (`000)
Basic 101 921 100 831 101 056
Diluted 102 796 101 486 101 698
Group balance sheet
30 Sept 2001 30 Sept 2000 31 March 2001
(Reviewed) (Reviewed) (Audited)
$'000 $'000 $'000
Employment of capital
Fixed assets 167 641 101 577 142 591
Current assets
Inventories 6 368 4 674 4 638
Debtors 14 521 9 141 18 663
Cash and bank deposits 28 229 60 756 29 325
49 118 74 571 52 626
Current liabilities
(note 5) (17 833) (29 772) (24 980)
Net current assets 31 285 44 799 27 646
Total assets less
current liabilities 198 926 146 376 170 237
Long term interest
bearing project loans - (1 032) -
Deferred taxation (11 307) (4 369) (8 132)
Decommissioning
provision (18 391) (10 453) (16 648)
169 228 130 522 145 457
Capital employed
Share capital 2 635 2 621 2 630
Share premium account 100 655 98 764 99 823
Retained income 86 516 47 981 64 368
Other reserves (20 578) (18 844) (21 364)
Shareholders' interest 169 228 130 522 145 457
Net book value per
share - cents
Basic 165.7 129.2 143.0
Diluted 164.4 128.5 142.4
Number of ordinary
shares in issue at
period end ('000)
Basic 102 159 101 005 101 726
Diluted 102 960 101 591 102 171
Group cash flow information
Six months to Six months to Year ended
30 Sept 2001 30 Sept 2000 31 March 2001
(Reviewed) (Reviewed) (Audited)
$'000 $'000 $'000
Reconciliation of operating
profit to net cash flow
from operations
Operating profit 31 795 16 634 43 215
Exploration expenditure
written off 9 771 20 998 35 683
Depreciation 16 950 11 617 23 619
Profit on disposal of
fixed assets - - (3)
Exchange loss/(gain) 378 (946) (1 742)
Net cash inflow from
operations prior
to working capital
adjustments 58 894 48 303 100 772
Working capital
adjustments (589) (1 357) (7 194)
Net cash inflow from
operations 58 305 46 946 93 578
Cash flow statement
Net cash inflow from
operations 58 305 46 946 93 578
Return on investments
and servicing of finance
Interest received 621 1 754 3 526
Interest paid (344) (466) (848)
Tax paid (4 678) (3 465) (16 829)
Investing activities
Exploration
expenditure (8 910) (20 126) (39 504)
Payments to acquire
tangible assets (41 630) (24 820) (71 477)
Proceeds from sale
of fixed assets - - 4
Net cash inflow/(outflow)
before financing 3 364 (177) (31 550)
Financing
Issue of ordinary
shares 837 343 1 411
Increase in bank and
other loans - - 917
Repayment of loans (4 591) (2 642) (5 284)
Net cash outflow after
financing (390) (2 476) (34 506)
Cash flow from operations
per share - cents
Basic 57.2 46.6 92.6
Diluted 56.7 46.3 92.0
Group statement of changes in equity
Share Exchange
Share premium Retained translation
capital account profit reserve Total
$`000 $`000 $`000 $`000 $`000
At 30 September
2000 2 621 98 764 47 981 (18 844) 130 522
Profit attributable
to ordinary
shareholders - - 16 387 - 16 387
Exchange adjustment - - - (2 520) (2 520)
Arising on issue of
shares 9 1 059 - - 1 068
At 31 March
2001 2 630 99 823 64 368 (21 364) 145 457
Profit attributable
to ordinary
shareholders - - 22 148 - 22 148
Exchange adjustment - - - 786 786
Arising on issue of
shares 5 832 - - 837
At 30 September
2001 2 635 100 655 86 516 (20 578) 169 228
Auditors Report
The financial information for the six months ended 30 September 2001 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
Accounting policies applied during the period are consistent with the
accounting policies as stated in the annual report for the year ended 31
March 2001.
The group has changed its reporting currency from South African rands to US
dollars to facilitate a better understanding of its results, since the
majority of its revenues and costs are in US dollars and the US dollar is
the recognised currency of the oil exploration and production industry.
The conversion to US dollars was translated as follows:
* Share capital, share premium and reserves at the applicable historical
rates of exchange.
* Assets and liabilities at the closing rates of exchange.
* Income, expenses and cash flows at average exchange rates.
* The resulting translation differences are included in other reserves.
Six months Six months Year
ended ended ended
30 Sept 2001 30 Sept 2000 31 March 2001
$'000 $'000 $'000
2. Turnover
Africa 53 796 34 964 87 563
Non-Africa 25 615 28 598 50 949
79 411 63 562 138 512
3. Cost of production
Operating costs 16 232 11 035 24 993
Movement in underlift (1 844) (679) (1 185)
Royalty paid in cash 3 103 1 134 3 714
Depreciation 16 716 11 446 23 262
34 207 22 936 50 784
4. Taxation
Corporation tax
- current 6 727 9 124 16 314
- prior year (7) 190 -
Deferred tax 2 821 (388) 3 716
9 541 8 926 20 030
5. Current liabilities
Current portion of
borrowings - 5 284 4 591
Corporation tax payable 9 560 13 995 7 278
Other creditors and
accruals 8 273 10 493 13 111
17 833 29 772 24 980
6. Capital commitments
Contracted and
approved 34 213 41 701 50 063
7. Production MMbbl MMbbl MMbbl
Group share of
production 4.1 2.8 6.5
Delivered to host
governments (0.4) (0.3) (0.9)
Movements in underlift (0.2) (0.1) (0.1)
Group production sold 3.5 2.4 5.5
Summary rand convenience translation
Six months to Six months to Year ended
30 Sept 2001 30 Sept 2000 31 March 2001
(Reviewed) (Audited)
R million R million R million
Income statement
Turnover 652 441 1 015
Operating profit 261 115 317
Net profit 182 61 184
Earnings/headline earnings
per share (cents) 178 60 182
Cash flow
Cash flow from operations
pre-working capital
adjustments 484 335 738
Cash inflow from operations 479 326 685
Exploration expenditure 73 140 289
Development expenditure 342 172 524
Cash inflow from operations
per share (cents) 470 323 678
Balance Sheet
Fixed assets 1 510 733 1 142
Cash 254 439 235
Loans - 46 37
Net cash 254 393 198
Net assets 1 524 943 1 165
Net book value per
share (cents) 1 492 933 1 145
R/$ exchange rate
(period average) 8.21 6.93 7.32
R/$ exchange rate
(period end) 9.01 7.22 8.01
Directors: Dato' M Idris Mansor (Chairman) (Malaysian), R Gasant (Managing),
P J G Elwes (British), A A Maule, W A Nel, L Nyhonyha, F M J L Poimboeuf
(French), A Said (Malaysian), A G Windham (British)
Company Secretary: W H Torr
21st Floor, Metropolitan Centre, 7 Coen Steytler Avenue
Cape Town 8001, Republic of South Africa.
