Paladin Resources PLC
20 March 2002
PALADIN RESOURCES plc
("Paladin" or "the Company")
Preliminary Results for the year ended 31 December 2001
Paladin, the oil and gas exploration and production company with interests in
the UK, Danish and Norwegian North Sea, Indonesia and the USA, announces its
preliminary results for the year ended 31 December 2001.
• Record results:
- Average production increased 163% to 18,255 boepd (2000: 6,940 boepd)
- Turnover increased 146% to £104.7m (2000: £42.6m)
- Cash flow from operations increased 176% to £61.0m (2000: £22.1m)
- Operating profit increased 129% to £41.3m (2000: £18.0m)
- Earnings per share increased 64% to 8.48p (2000: 5.17p)
• 2001 activity highlights:
- UKCS Blake Field on stream in June ahead of schedule and under budget
- Successful appraisal wells drilled on UKCS Blake and Ross Fields
- US$76m acquisition of Petro-Canada's Norwegian assets
- US$35m acquisition of Enterprise Oil plc's Danish assets, including
the Siri and Stine Fields
• 2002 corporate activity:
- £11.6m acquisition of 4.5% stake in Goldeneye Field increasing
Paladin's share to 7.5%
- Agreement signed for £26m acquisition of 7.5% share of Njord Field and
20% share of Brage Field from Norwegian government
- Agreement reached to process and export oil from Nini and Cecilie
Fields using Siri Field facilities (Paladin 25%)
• 2002 production as a result of recent acquisitions expected to increase to
29,000 boepd from an average of 18,255 boepd in 2001
Malcolm Gourlay, Chairman of Paladin, commented:
"These are record results for Paladin and highlight the management's success in
turning Paladin around from a loss making company three years ago into a highly
profitable UK exploration and production business.
"Going forward, we continue to believe that there will be further opportunities
to create value for shareholders."
20 March 2002
Paladin Resources plc Tel: 020 7534 2900
Roy A. Franklin, Chief Executive
Cuth McDowell, Finance Director
College Hill Tel: 020 7457 2020
I am pleased to report that Paladin made significant progress on all fronts in
2001 and has produced another set of record financial results. When these
results are combined with the recently announced acquisitions in Norway and the
UK, your Company is well positioned for further growth in 2002 and to achieve
its near term targets.
Our Scandinavian business is now well established with completion of the
acquisition of Petro-Canada's Norwegian interests early in the year, the
purchase of Enterprise Oil plc's Danish interests in Licence 6/95 in September
and the acquisition (which became unconditional later in the year) of an
additional interest from Phillips in the same licence through the exercise of
pre-emptive rights. The business is set to develop further in 2002: the planned
acquisition of an interest in the Brage Field and an additional interest in the
Njord Field from the Norwegian State was announced recently and, in Denmark,
terms have been agreed for the processing of oil from two nearby fields at the
Siri platform, which will generate significant tariffing revenues for Paladin in
In the UK, the Blake Field came on stream in June, and the second half of the
year saw healthy contributions to production from both the Bittern and Blake oil
fields. Studies on the optimum development scheme for the Goldeneye Field
continued through the year and led, earlier this month, to approval of the field
development plan. As recently announced, we will acquire a further 4.5 per cent
interest in this gas field in the near future, taking our overall interest to
7.5 per cent. When the field comes on stream in the second half of 2004 it will
make a major contribution to production.
Although now a much less significant part of Paladin's expanded portfolio, our
Indonesian interests have performed well, providing steady production and
continuing investment opportunities in a prolific hydrocarbon province.
In spite of weaker commodity prices, particularly in the final quarter of the
year, we are in a strong financial position.
A near trebling of production more than compensated for lower commodity prices,
leading to cash flow (before interest, tax and depreciation but after
administration costs) of £61.0 million (2000: £22.1 million) and an operating
profit of £41.3 million (2000: £18.0 million). Retained profit for the year
almost doubled to £18.3 million (2000: £10.4 million), resulting in earnings per
share of 8.48 pence (2000: 5.17 pence).
Net production for the year totalled 6.2 MMbbl of oil and NGL and 3.0 Bscf of
gas, an average of 18,255 boepd, which is a new record for Paladin and
represents an increase of 163 per cent from 6,940 boepd in 2000. Completion of
the acquisition of Petro-Canada's Norwegian interests in January 2001, the
acquisition of Enterprise Oil plc's Danish interests in September 2001 and, in
the UK, a full year's contribution from the Bittern Field and six months
contribution from the Blake Field, resulted in significant geographic
rebalancing of the Group's production in 2001: 38.6 per cent came from Norway
(2000: nil), 12.8 per cent from Denmark (2000: nil), 11.0 per cent from the UK
(2000: 10 per cent), 35.2 per cent from Indonesia (2000: 83 per cent) and the
balance of 2.4 per cent from the USA (2000: 7 per cent).
Overall, the Group invested £11.4 million on production and development projects
(2000: £10.6 million): £3.0 million in Norway, £0.7 million in Denmark, £1.4
million in the UK, £6.1 million in Indonesia and £0.2 million in the USA.
The Group invested £5.6 million on exploration activities in the UK, Indonesia,
Romania, Tunisia and Tanzania during the year (2000: £3.4 million), including
two successful appraisal wells in the Blake and Ross Fields in the UK.
Proven and probable reserves (on an entitlement basis) at 31 December 2001 were
63.1 MMboe, compared to 38.2 MMboe at 31 December 2000. Net positive revisions
of 6.4 MMboe essentially replaced production for the year, whilst acquisitions
in Norway and Denmark added some 26.3 MMboe, offset by a reduction of 1 MMboe
due to the sale of minor properties in the USA.
At year end, reserves in Norway constituted 27.3 per cent of the total, with 9.0
per cent in Denmark, 11.8 per cent in the UK, 49.9 per cent in Indonesia and the
balance of 2.0 per cent in the USA.
On a working interest basis, Group reserves increased to 80.9 MMboe (2000: 58.5
MMboe). In addition, a further 12 MMboe of uncontracted gas reserves are
currently not booked by the Group.
Despite a year of substantial investment and lower commodity prices, a
combination of significantly higher cash flow and the issue of new equity
enabled the Company to maintain its strong financial position, with net debt at
31 December amounting to £44.4 million (2000: £22.4 million), a multiple of just
over one times 2001 after-tax cash flow. This financial strength will enable our
currently proposed acquisitions and our future development commitments to be
financed from existing resources.
Bill Turcan, former Group Chief Executive of Elementis plc, joined the Board on
17 May, replacing David McGibbon who retired on the same day. Paul Chivers
resigned on 21 June due to other business commitments.
Strategy and Outlook
Paladin's strategy is to grow through both acquisition and exploration with the
objective of securing reserves and production on a commercially attractive
basis. Notwithstanding near term volatility in commodity prices, we continue to
plan and evaluate acquisition opportunities using a long-run US$ Brent oil price
in the mid-teens in real terms. This strategy and discipline has served the
Company well to date and is set to continue.
Both operating and financial performance in 2001 exceeded previous levels, and
production for the current year to date is averaging some 25,000 boepd. The
proposed acquisition of a further 7.5 per cent stake in the Njord Field and a 20
per cent stake in the Brage Field will raise annualised 2002 production to some
29,000 boepd. The purchase of a further 4.5 per cent interest in the Goldeneye
Field is complementary - the contribution to production from Goldeneye from 2005
onwards will be some 4,500 boepd, and both the UK and the gas elements of the
Group's portfolio will be enhanced.
Last year, the Board set new targets to increase production and reserves to
35,000 boepd and 120 MMboe respectively by 2004. The acquisition of our Danish
interests last September, and the recently announced acquisitions in Norway and
the UK, are significant steps towards those objectives. I am confident that
there will continue to be attractive acquisition opportunities in the coming
months, which will enable the Company to make further progress and to add value
2001 has been a challenging, successful and exciting year for Paladin. I would
like to take this opportunity, on behalf of shareholders, to thank the Directors
and staff for their commitment, hard work and professionalism over the last
J. Malcolm Gourlay
20 March 2002
Paladin's 2001 production amounted to 6.2 MMbbl of oil and NGL and 3.0 Bscf of
gas from the UK, Norway, Denmark, Indonesia and the USA, an average of 18,255
boepd. Exploration activity continued in the UK, Norway, Indonesia, Romania,
Tunisia and Tanzania. Further details are given below for each region.
Bittern (Paladin 2.4%)
Gross production for the year from the Bittern Field averaged 53,750 bpd of oil
and NGL and 52 MMscfd of gas (1,512 boepd net to Paladin). The production
efficiency of the Triton FPSO improved throughout the year as the initial
problems with the gas compressors and power generation were overcome. Peak daily
production capacity remains at 62,000 bpd of oil and NGL and 90 MMscfd of gas.
Blake (Paladin 2.4%)
Drilling and tie-in of the six oil producers and two water injectors was
completed in the first half of the year and first production was achieved in
June 2001, two months ahead of schedule and ten per cent under budget. Gross
production for the year averaged 20,440 bopd (491 bopd net to Paladin).
Reservoir performance has been in line with expectations. It is planned to drill
an additional water injector during the course of 2002 in order to increase
pressure support and improve reservoir sweep efficiency.
During the year, an appraisal well was drilled in the flank area of the field.
This was successful in proving additional reserves in the Captain and the
Coracle sands. A development plan for this area is now being prepared, with
first production expected in 2004.
Goldeneye (Paladin 3% on an initial basis)
Pre-unitisation equity splits have been agreed, subject to redetermination after
first production, giving the Block 20/4b group (Paladin 15 per cent) a deemed 20
per cent share of the field. A field development plan has been approved by field
owners and project sanction was granted by the DTI on 13 March 2002. On
completion of the acquisition referred to in the Chairman's Statement, Paladin's
interest will increase to 37.5 per cent in Block 20/4b and, as a result, to 7.5
per cent in the field.
The Goldeneye development is based on five wells producing through a wellhead
jacket, with full wellstream evacuation via a 20 inch pipeline to onshore
processing facilities at St. Fergus. Sales agreements providing for the sale and
purchase of gas and condensate at the processing plant product exit point have
been agreed with Shell/Esso. First production is scheduled for the second half
Well 13/29b-7 was drilled in May and tested oil at rates of up to 2,200 bpd,
successfully proving an extension of the Ross Field into Block 13/29b (Paladin
20 per cent). Commercial negotiations are underway with the Ross Field owners.
20th Licensing Round
Work is on-going in a number of study groups with a view to the Company applying
for exploration acreage in the 20th Round in April 2002.
Njord (Paladin 7.5%)
Average gross production for the year was 50,634 bopd (3,798 bopd net to
Although some production was deferred during 2001 due to short-term operational
problems, reservoir performance continues to meet expectations.
A new 3D/4D seismic survey was acquired over the Njord Field during 2001.
Interpretation of this survey will help to identify new infill well locations,
improve productivity and aid the recovery of additional reserves.
Paladin's interest will increase to 15 per cent on completion of the acquisition
of a further 7.5 per cent stake from the Norwegian State.
Veslefrikk (Paladin 9%)
Average gross production for 2001 was 35,755 boepd (3,218 boepd net to Paladin).
An infill drilling programme, aimed at boosting short-term production, was
initiated in the fourth quarter of 2001.
Condensate production from the Huldra Field commenced in November, providing
Veslefrikk with a valuable additional revenue stream in the form of tariff
Significant investments were also made in upgrading the Veslefrikk facilities.
These will enhance both the integrity of the facilities and the performance of
Huldra (Paladin 0.5%)
The offshore phase of the Huldra development, comprising the installation of the
jacket and topsides, tie-back of control and condensate lines to Veslefrikk and
connection of a gas export line to the Heimdal platform, was undertaken between
March and July. Following hook-up and commissioning, the field came onstream in
mid-November. During December, four of the six production wells were brought
onstream as part of the build-up to a plateau production rate of 310 MMscfd.
Siri/Stine (Paladin 25.26% in the Siri Field and Stine Segment 1, and 22.86% in
Stine Segment 2)
The acquisition of Enterprise Oil plc's Danish interests was completed in
mid-September. Paladin gained a 20 per cent interest in Licence 6/95, including
the Siri Field and Stine Segment 1 (20 per cent) and Stine Segment 2 (22.86 per
cent). Paladin also agreed, during the year, to acquire a 5.26 per cent interest
from Phillips in Licence 6/95 (excluding Stine Segment 2) through the exercise
of pre-emptive rights. As at the year end, the Siri Field was producing 35,000
bopd. The field has performed above expectations and a reserves upgrade was made
following a review of 2001 field performance.
The Stine Segment 2 oil accumulation was discovered in June 2001 by the Siri-4
exploration well and is being produced through a long reach horizontal well,
SCA-7, drilled from the Siri platform. Production from this well is above
expectations, commencing at an initial rate of 17,000 bopd in September and
reducing to 12,000 bopd by the year end.
Paladin's net production for 2001 from the Siri and Stine Segment 2 Fields
averaged 2,334 bopd.
Plans for the development of Stine Segment 1, as a satellite tie-in to the Siri
facilities, are underway and it is expected that a plan of development will be
submitted to the Danish authorities during the first half of 2002, with first
production scheduled for the first quarter of 2003.
Agreement has been reached between the Siri joint venturers and the partners in
the nearby Nini and Cecilie Fields on the terms for processing oil from Nini and
Cecilie at the Siri platform. On the basis that plans for the development of the
Nini and Cecilie Fields are approved by the Danish Energy Agency and project
sanction is given in June 2002, as is currently envisaged, Paladin would expect
to receive significant tariff revenues, commencing in mid-2003, and to benefit
from a reduction in Siri and Stine unit costs, leading to a longer Siri Field
South East Sumatra (Paladin 7.5%)
Gross production from the PSC averaged 125,200 bopd during 2001. This compares
with 126,645 bopd during 2000, demonstrating the success achieved by the
operator (Repsol-YPF Maxus) in arresting the production decline in this mature
asset. The Widuri Field waterflood has continued to deliver good results, as has
the continuing workover campaign on existing production wells. Paladin's
entitlement share of production was 4,958 bopd for the year.
Negotiation of a gas sales agreement is well advanced and, if successfully
concluded, would result in the initial development of the 600 Bscf of gas
reserves already proved but not yet booked within the PSC area.
Offshore North West Java (Paladin 2.5%)
Gross production from the PSC averaged 51,300 bpd of oil and NGL and 261 MMscfd
of gas. Paladin's entitlement share of production was 1,471 boepd for the year.
During the course of BP's first full year of operatorship, a number of studies
have been initiated to review the remaining reserves and exploration potential
of the PSC area. Once specific targets have been identified, it is expected that
an increased investment programme will commence.
Blora (Paladin 13.3%)
Following interpretation of the seismic data acquired during 2000, additional
prospects have been confirmed in the southern part of the PSC area. One of these
is being evaluated by the Ngawi-1 well, which was spudded in January 2002.
Paladin's total net production for the year averaged 159 bpd of oil and 1.6
MMscfd of gas. Two properties, Parks and Rhoda Walker, were sold in October. The
operatorship of Paladin's only remaining producing property, Fort Chadbourne,
was also transferred to St. Mary Energy in October. This enabled Paladin to
close its office in Abilene in February 2002 with resultant savings in general
and administrative costs.
Production net to Paladin's 50 per cent interest from Fort Chadbourne is
currently some 300 boepd.
Midia and Pelican (Paladin 80% and operator)
The Doina appraisal well, Doina-3, was drilled and abandoned in September. The
well confirmed the extent of the gas-bearing Doina Main reservoir, but the
shallower Doina Upper objective was not well developed. Consequently, the Doina
discovery is not yet considered to be commercially viable using conventional
development technology. The licence has been extended whilst studies continue on
innovative development options as well as on the remaining prospectivity of both
the Midia and Pelican Blocks.
Borj el Khadra (Paladin 10%)
543 km of seismic were acquired during 2001. Interpretation of these data has
identified a number of low risk prospects, the first of which will be drilled in
Agip operate the permit and other developments in the same area and a discovery
on Borj el Khadra could therefore be tied back to the local production
infrastructure quickly and cost-effectively.
Following the expiry of the PSA in September, Paladin signed a Memorandum of
Understanding with the Tanzanian Petroleum Development Corporation giving the
Company the exclusive right to negotiate a PSA for the Bigwa/Rufiji and Mafia
Island areas. Discussions are currently underway to bring joint venture partners
into these areas.
Roy A. Franklin
20 March 2002
Production and profits
Following completion of the Scandinavian acquisitions during 2001, Group
production for 2001 was significantly higher at 18,255 boepd (2000: 6,940 boepd)
and, despite a lower average realised price of US$22.63 per boe (2000: US$25.40
per boe), turnover increased by 146 per cent to £104.7 million (2000: £42.6
Average production costs were lower at US$7.75 per boe (2000: US$8.79 per boe),
reflecting increased low cost production in Scandinavia and the UK and
additional entitlement barrels in Indonesia arising from lower oil prices.
Depletion and depreciation increased to US$4.90 per boe (2000: US$3.96 per boe),
reflecting the higher capital and acquisition costs attributable to UK and
Scandinavian production. A write-off of £2.5 million of exploration and
appraisal expenditures relating to Tanzania and Romania added US$0.54 per boe to
the charge (2000: US$0.29 per boe).
Retained profits for the period were substantially higher at £18.3 million
(2000: £10.4 million), reflecting strong growth in underlying production.
Cash flow and net debt
Operating cash flow before interest, tax and depletion, but after administration
costs of £2.5 million, was significantly higher at £61.0 million compared with
£22.1 million in 2000.
On-going capital expenditure (including capitalised interest) of £17.1 million
was split between production and development (£11.4 million), exploration and
appraisal (£5.6 million) and other (£0.1 million). Net interest expense was £3.5
million (2000: £0.6 million).
Payments (inclusive of adjustments) of £42.4 million in respect of the
acquisition of Petro-Canada's Norwegian assets and £28.2 million in respect of
the acquisition of Enterprise Oil plc's interests in Denmark were made during
the year. These were partly offset by disposal proceeds of £1.8 million from the
sale of two peripheral US properties.
Year-end net debt increased to £44.4 million (2000: £22.4 million), the increase
reflecting the debt-financed acquisitions in Scandinavia, offset by net proceeds
from the placing and open offer completed in November (£18.4 million) and the
issue of shares to Petro-Canada in January (£2.7 million). All debts and other
liabilities arising from the Group's activities are included in the Group
The main economic factors affecting the Company's results are the price of oil,
which is denominated in US dollars, and the sterling/US dollar exchange rate, as
the results are ultimately reported in sterling.
To manage commodity price risk, the Group's policy is to hedge oil and gas price
exposure up to a maximum of 50 per cent of production (excluding Indonesia and
Norway, where downside price risk is already mitigated by relatively high tax
During the second half of 2001, with increasing UK production and the
acquisition of producing interests in Denmark, the Company entered into oil
price swaps (based on dated Brent) for the second half of 2001 and the first
half of 2002: 50,000 bbl per month for July to December 2001 at an average price
of US$24.50 per bbl; 25,000 bbl per month for September to December 2001 at a
price of US$25.20 per bbl; and 100,000 bbl per month for January to June 2002 at
an average price of US$24.11 per bbl. These volumes represent 36 per cent of
projected Group production from the UK and Danish North Sea over the period.
Overall, the second half 2001 swap contributed £0.7 million to turnover and
increased year average realisations by US$0.16 per boe.
Further oil price swaps (based on dated Brent) have been entered into in 2002
for the second half of 2002 and the first half of 2003: 75,000 bbl per month for
July to December 2002 at an average price of US$22.01 per bbl; and 75,000 bbl
per month for January to June 2003 at an average price of US$21.58 per bbl.
To manage currency risk, cash requirements during the year were funded by US
dollar borrowings to match income denominated in US dollars, thereby minimising
exposure to adverse exchange rate movements. US dollars were also sold forward
to match the payment of taxes in other currencies.
The Group also fixed the interest rate on borrowings of US$12.5 million at 2.59
per cent for the period from December 2001 to December 2002 and on borrowings of
US$12.5 million at 2.11 per cent for the period from December 2001 to June 2002.
The Group's taxation charge for the year comprised current tax charges in
respect of Indonesia and Scandinavian activities. Taxable profits in North
America are expected to be fully covered by prior year losses and ongoing
The Group provides for deferred tax in respect of timing differences between the
recognition of profits for tax and accounting purposes to the extent they are
expected to reverse in the future. As a result of this policy, no deferred tax
provision was made in 2001 (2000: UK charge of £0.9 million).
The overall effective tax rate for the year was 52 per cent (2000: 40 per cent).
The increase primarily reflects the higher rate of taxes payable on Norwegian
FRS19, issued at the end of 2000, requires full provision to be made for
substantially all timing differences. As indicated in the 2000 accounts, the
Group will adopt this standard in 2002.
20 March 2002
Production and Reserves
Production 2001 2000
Oil Mbbl bopd Mbbl bopd
Indonesia 2,066 5,660 1,846 5,044
UK 654 1,792 219 598
USA 58 159 77 210
Scandinavia 3,379 9,257 - -
Total Oil Production 6,157 16,868 2,142 5,852
Gas Bscf MMscfd Bscf MMscfd
Indonesia 1.68 4.60 1.62 4.42
UK 0.46 1.26 0.18 0.50
USA 0.60 1.64 0.59 1.60
Scandinavia 0.30 0.82 - -
Total Gas Production 3.04 8.32 2.39 6.52
Mboe boepd Mboe boepd
Total Oil Equivalent Production 6,664 18,255 2,540 6,940
Production volumes are reported on an entitlement basis; on a working interest
basis, Group production in 2001 averaged 23,588 boepd.
Proven and Probable Reserves
Proven and Probable Reserves at 31 December 2001 2000
Oil MMbbl MMbbl
Indonesia 28.23 27.78
UK 4.04 4.04
USA 0.50 1.22
Scandinavia 21.74 -
Total Oil Reserves 54.51 33.04
Gas Bscf Bscf
Indonesia 19.79 21.57
UK 20.61 1.78
USA 4.48 7.29
Scandinavia 6.84 -
Total Gas Reserves 51.72 30.64
Total Reserves Oil Equivalent 63.13 38.15
Notes to Production and Reserves
1. Oil includes NGL.
2. Quantification of reserves is based on the Company's own estimates
supported by operators' and third party experts' estimates. The
reserves in the table above represent the Group's entitlement to
commercial proven plus probable reserves, as defined in the SORP. On a
working interest basis, Indonesian reserves at 31 December 2001 would
increase by 17.80 MMboe to 49.33 MMboe and total Group reserves would
increase to 80.93 MMboe. In addition, uncontracted gas reserves in
Indonesia and Norway amount to 12 MMboe.
3. Quantities of oil equivalent are calculated on an energy
equivalent basis for the purpose of the above tables and for
depreciation and depletion calculations.
4. The following movements in proven and probable reserves
occurred in 2001:
Reserves at 31 December 2000 38.15
Produced in 2001 (6.66)
Revisions to estimates 6.35
Reserves at 31 December 2001 63.13
Group Profit and Loss Account
For the year ended 31 December 2001 2000
Notes £000 £000
Turnover 104,713 42,582
Cost of sales
Production costs (35,846) (14,746)
Depletion and depreciation (22,664) (6,633)
Exploration expenditure written off (2,487) (495)
Gross profit 43,716 20,708
Administrative expenses (excluding exceptional item) (2,462) (2,140)
Exceptional administrative expenses - (613)
Operating profit 4 41,254 17,955
Net interest expense (3,498) (564)
Profit on ordinary activities before taxation 37,756 17,391
Taxation (19,492) (7,014)
Retained profit for the year 18,264 10,377
Earnings per share 1
Basic 8.48p 5.17p
Diluted 8.45p 5.16p
Group Statement of Total Recognised Gains and Losses
For the year ended 31 December 2001 2000
Profit for the year 18,264 10,377
Foreign exchange differences 68 4,599
Total recognised gains for the year 18,332 14,976
Group Balance Sheet
At 31 December 2001 2000
Tangible fixed assets 161,154 94,120
Investments 453 -
Stock 1,595 613
Debtors 14,958 7,847
Cash at bank and in hand - 1,046
Creditors: amounts falling due within one year (18,660) (6,586)
Net current (liabilities)/assets (2,107) 2,920
Total assets less current liabilities 159,500 97,040
Creditors: amounts falling due after one year (44,379) (23,411)
Provisions for liabilities and charges (3,217) (1,204)
Net assets 111,904 72,425
Capital and reserves
Called up share capital 25,300 20,069
Share premium 44,138 28,222
Profit and loss account 42,466 24,134
Equity shareholders' funds 111,904 72,425
The financial statements were approved by the Board of Directors on 19 March
2002 and signed on its behalf by:
J M Gourlay C J McDowell
Non-executive Chairman Finance Director
Group Cash Flow Statement
For the year ended 31 December 2001 2000
Notes £000 £000
Cash flow from operating activities 4 60,999 22,051
Returns on investments and servicing of finance
Interest received 60 143
Interest paid (3,519) (1,602)
Net cash outflow from returns on investment
and servicing of finance (3,459) (1,459)
Taxation (14,486) (6,592)
Capital expenditure and financial investments
Ongoing capital expenditure (excludes capitalised interest) (16,619) (13,055)
Acquisition of oil and gas fixed assets (70,550) (5,664)
Sale of oil and gas interests 1,811 2,884
Deferred acquisition cost - (2,500)
Investment in own shares (453) -
Net cash outflow from capital expenditure (85,811) (18,335)
Net cash outflow before financing (42,757) (4,335)
Issue of shares 21,147 -
Increase in borrowings 47,934 3,300
Decrease in borrowings (27,429) -
Net cash inflow from financing 41,652 3,300
Decrease in cash in the year (1,105) (1,035)
Reconciliation of net cash flow to movement in net debt
Decrease in cash in the year (1,105) (1,035)
Increase in borrowings (47,934) (3,300)
Decrease in borrowings 27,429 -
Change in net debt resulting from cash flows (21,610) (4,335)
Exchange differences (433) (1,611)
Movement in net debt in the year (22,043) (5,946)
Net debt at the start of the year (22,365) (16,419)
Net debt at the end of the year (44,408) (22,365)
(forming part of the financial statements)
1. Earnings per share
The earnings per share is calculated on a retained profit of £18,264,000 (2000:
profit of £10,377,000) and a weighted average number of 215,427,204 ordinary
shares (2000: 200,694,381 shares).
The diluted earnings per share is calculated on a retained profit of £18,264,000
(2000: profit of £10,377,000) and a weighted average number of 216,186,775
ordinary shares (2000: 201,121,706 shares) calculated as follows:
Basic weighted average number of shares 215,427 200,694
Dilutive potential ordinary shares:
Employee share options 760 427
The Directors do not recommend the payment of a dividend
3 The financial information set out above does not constitute the Company's
statutory accounts for the years ended 31 December 2001 or 2000 but is derived
from those accounts. Statutory accounts for 2000 have been delivered to the
Registrar of Companies, and those for 2001 will be delivered following the
Company's Annual General Meeting. The auditors have reported on these accounts;
their reports are unqualified and did not contain statements under section 237
(2) or (3) of the Companies Act 1985.
4 Reconciliation of operating profit to operating cash flows
Operating profit 41,254 17,955
Depreciation and depletion charge 22,664 6,633
Exploration expenditure written-off 2,487 495
Increase in stocks (973) (97)
Increase in debtors (7,872) (1,882)
Increase/(decrease) in creditors 3,448 (693)
(Decrease) in provisions (9) (360)
Net cash inflow from operating activities 60,999 22,051
5 Post balance sheet events
The Group signed a sale and purchase agreement on 13 March 2002 to acquire a
further 22.5 per cent interest in UKCS Block 20/4b from Shell U.K. Limited for a
basic consideration of £11.6 million.
The Group also signed sale and purchase agreements on 18 March 2002 to acquire a
further 7.5 per cent interest in the Njord Field and a 20 per cent interest in
the Brage Field, both in Norway, from the Norwegian State for a total basic
consideration of 325 million Norwegian Kroner.
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