HARDMAN REPORTS POST TAX PROFIT OF A$22.9 MILLION FOR FIRST HALF 2006
Hardman Resources Limited ("Hardman" or the "Company") today announced results for the six months ended 30 June 2006 for the Company and its controlled entities (together the "Group").
FINANCIAL HIGHLIGHTS
- First half profit before tax of A$31.1 million (1H 2005: loss A$8.4 million)
- First half profit after tax of A$22.9 million (1H 2005: A$6.1 million, including one-off tax credit of A$14.5 million)
- Chinguetti cash earnings (EBITDAX) contribution of A$61 million, or US$56 per barrel
- Net cash at 30 June of A$136 million
OPERATIONAL HIGHLIGHTS
- Start up of Chinguetti production - a transforming event for Hardman, the initiator of modern exploration offshore Mauritania
- Hardman entitlement share of production for 1H2006 was 975,684 barrels or 7,683 barrels of oil per day since first oil, lower than predicted leading to current review of field reserves
- Mputa and Waraga discoveries in Uganda operated by Hardman create an emerging new oil province
- Successful testing of Mputa and Waraga confirm excellent reservoir quality and potentially commercial flow rates; oil in place from discoveries so far estimated at 100 to 300 mmbbls; Initial estimate of recoverable volumes of 30 mmbbls with near term upside from success at Nzizi appraisal well
- New exploration ventures in Tanzania and Suriname
OUTLOOK
- After unpredicted early decline, Chinguetti production stabilised in Q3 averaging 35,068 bopd gross in July and 33,018 bopd gross (provisional) for the period 1 through 22 August. Chinguetti production over the remainder of 2006 is expected to show continued stability or a slow decline dependent on reservoir connectivity and efficiency of water injection
- Chinguetti infill drilling is expected to commence Q4 2006 to increase field deliverability from around the year end
- Strong cash position allows active exploration and appraisal, including three wells offshore Mauritania to complete and further onshore drilling in Uganda this year. Major potential of this exciting new exploration play offshore Lake Albert yet to be tested
"The first half of 2006 has seen major milestones successfully passed. transformed organisation has achieved first commercial oil production in Mauritania, drilled our first operated international exploration wells resulting in the discovery of an exciting new oil province in Uganda, and accessed complementary new exploration opportunities.
The unpredicted decline in production and need to review reserves at Chinguetti was, however, a disappointment and suggests that the reservoir development of this field will be a challenging process of optimisation and application of technology over time to enhance recovery. But high margin barrels and a strong prevailing oil price mean the prize for translating oil in place to sold barrels is substantial and a strong incentive for the Joint Venture.
Despite setbacks the mitigation lies in pursuing our existing strategy to fully exploit our portfolio. We have substantial net cash, an inventory of exploration, appraisal and development options in both Mauritania and Uganda, and we have an operating capability to manage pace across our portfolio.
We are confident of continuing the development of Hardman into a significant international exploration and production company to add material net asset value for shareholders."
- Simon Potter, CEO and Managing Director
For more information:
Simon Potter: CEO / MD +61 8 9261 7600 Peter Thomas: CFO +61 8 9261 7600
Australian Media Contacts: Jill Thomas, Hardman Resources +61 8 9261 7600 London Media Contact: Patrick Handley, Brunswick Group +44 207 404 5959
CHIEF EXECUTIVE'S OVERVIEW
The first half of 2006 Hardman has seen a number of major milestones successfully passed.
The Chinguetti field was successfully brought on-stream on 25 February (WST), twenty-two months after development approval. As the initiator of modern exploration offshore Mauritania in 1996, Hardman has played a key role in many of the steps that made this possible, and the realisation of the first production revenues is a transforming event for the Company. For the first time we have significant operating cash flows available for re-investment.
The start of production has coincided with a period of historically high oil prices, and as a result, we have today been able to announce a first half profit of A$22.9 million.
Also in the first half, Hardman's first international exploration drilling as operator, onshore Uganda, resulted in two discoveries, at Mputa and Waraga, which have subsequently been successfully tested and appraised. These discoveries have created an entirely new potential oil province in Uganda and significantly upgraded the further exploration potential of the Western Rift Valley margin play in this area. In the limited portion of the block we have explored to date (approximately 6%) we have already established oil in place of 100-300 mmbbls and potential recoverable volumes of the order of 30 mmbbls with near term upside from success at Nzizi appraisal well to be drilled by the end of 2006, up-dip from discovered oil at Mputa. Further additions are likely from near field appraisal and exploration, but the greatest potential offshore, beneath Lake Albert, has yet to be tested. With these very encouraging early results, we will pursue the wider exploration of this area in an aggressive campaign. Subject to further studies, the demands of the local power market suggest an initial early production scheme would be both feasible and commercial, as well as a high priority for the Ugandan Government.
At the same time, we have been disappointed by the production performance of the Chinguetti field. Production has averaged 46,600 bopd (gross) since first oil but showed an unexpected sharp decline through to June, before stabilising at rates of around 35,000 bopd, well below the predicted 60-70 mbopd. Notwithstanding this reduced rate, each sold barrel has realised US$56/bbl to Hardman (net of operating costs). Below we explain the current understanding of the field's performance and the unpredicted reservoir complexities now evident, and also outline the remedial plans that are underway. It is clear that there are no quick solutions, that considerable additional capital expenditure and technological application will be needed, and that a downward adjustment to the recoverable reserves of the field is inevitable. At this stage, it would be premature to announce a complete new reserves estimate, as the operator has ongoing work to re-appraise its reservoir models and optimise the ensuing development plan. However, we can comment that the wells in the initial development plan are unlikely to recover significantly more than half the originally estimated reserves. Hardman will continue to provide shareholders with as much clarity as we can on the current situation and plans as they develop.
The problems to be overcome suggest that reservoir management of this field is going to be an ongoing process of gaining understanding of reservoir behaviour and optimal development methods. This will be the key to its long term success, but with the estimated oil in place not materially changed, the scope exists to profitably use technology proven elsewhere to enhance recovery over time. With high margin barrels and a strong prevailing oil price the prize for translating oil in place to sold barrels is substantial. Further, notwithstanding the lower production rates, the finding and development costs of the Chinguetti project should, at current oil prices, be paid back by the end of next year.
On the exploration front, in Mauritania the Block 6 Zoule-1 well, the PSC B Dore-1 well and most recently in the new drilling campaign the Colin-1 well in PSC A were all unsuccessful. The remainder of the 2006 exploration wells target different plays, including considerable gas potential in Block 8 and the shallow water Cretaceous play within PSC Area A at Kibaro. During the six month period we resolved a dispute with the Mauritanian Government over the validity of certain supplementary agreements to the production sharing contracts (PSCs). This was settled with revisions in contract terms contained in revised PSCs signed in June. Meanwhile the potential Tiof development progressed through concept selection to more detailed engineering work preparatory to a declaration of commerciality, subject to joint venture approval, around the year-end.
Key developments in the remainder of the asset portfolio are outlined below, with two new ventures announced in the first half in Tanzania and Suriname, both with modest entry costs. Being onshore exploration plays, with lower costs and faster cycle times, and in Suriname's case being adjacent to existing oil production, these ventures complement the mainly offshore, high risk - high reward profile of Hardman's portfolio to date. The farm-out of our Guyane licence showed good early progress in the second quarter and is at the stage of detailed negotiation with several parties.
In April we raised US$113 million in an equity placing in the London market, at a very narrow discount to the then share price. We decided on this course to provide funding for accelerated exploration of opportunities within our portfolio and new ventures, including appraisal of the Uganda discoveries and follow up exploration in the area. Accessing the London market has broadened our shareholder base and brought some major new institutions onto the register. As a result, we had net cash at the end of June of A$136 million.
The reduced near term production outlook will inevitably require adjustment to our exploration plans but, with an increasingly operated portfolio, we are better placed to influence the pace and prioritisation of activities. We expect to spend some US$65 million on exploration and appraisal this year and a similar amount again next year. This will include allocating a greater proportion of the budget to the now proven Ugandan play. The overall budget has been re-phased in part as a result of tight rig availabilities and likely prioritisation of contracted rig slots to production work offshore Mauritania, rather than exploration.
Hardman has substantial net cash to allow us to continue to pursue our articulated strategy; we have a considerable resource base in Mauritania and the capacity to accelerate activity in our exciting new play emerging in Uganda. Our internal capabilities are growing, maturing in our Uganda operations and the successful delivery of new ventures elsewhere. We are confident of developing Hardman into a significant international exploration and production company to add material net asset value for shareholders.
Dealing with the multiple issues we have faced in Mauritania, the highly active campaign in Uganda, the fund raising and new venturing have all placed high demands on our small staff, and on behalf of the Board I would like to thank them for their high commitment, flexibility and resourcefulness.
BOARD
On 30 June, the Company announced that Mr. RA (Bob) Carroll was appointed as Chairman to succeed the founding Chairman of the Company, Mr. Alan Burns, who had elected to retire and ceased to be the Chairman and Director with effect from 3 July 2006. Mr. Peter Mansell and Mr. John Conlin joined the Board of the Company as Independent, Non-executive Directors effective 18 May 2006.
Earlier, on 12 April 2006, the Company announced that Mr. Scott Spencer had retired from the Board after nearly 12 years' service in an Executive, and more recently in a non-executive, capacity.
FINANCE
1H 2006 1H 2005 PRODUCTION & SALES DATA
Crude oil production ('000 barrels) - Hardman share 976 -
RESULTS FOR THE FIRST HALF (A$ million except per share figures) Gross profit 47.3 - Profit before tax 31.1 (8.4) Profit after tax 22.9 6.1 Earnings per share (basic) (cents per share) 3.4 0.9 BALANCE SHEET (A$ million) Cash 223.7 120.8 Net cash/(debt) 135.7 35.9
CASH FLOW (A$ million) Operating cash flow after tax and finance costs 30.5 (2.8) Cash flow before financing (55.8) (96.1)
Production and Sales
Sales revenue reflected three Chinguetti liftings in the first half, following the commencement of production on 25 February 2006. The average realised oil price was US$63.90 per barrel, with Chinguetti crude attracting an initial quality discount to dated Brent of around US$5 to $6 per barrel, reflecting it being a new crude and early production levels being uncertain. As at 30 June, Hardman was over lifted compared with its entitlement to production resulting in an expense, reflected in Cost of Sales, to put Gross Profit onto a production entitlements basis.
Cost of sales
Cost of sales comprises field operating costs, including insurance, depreciation, depletion and amortisation (dd&a) charges, and over / under lifting adjustments. Operating costs were A$10.51 per barrel produced, principally comprising the Berge Helene FPSO lease charge. Depreciation was A$17.15 per barrel, including the impact of future capital costs to develop the estimated reserves of the Chinguetti field, which have been substantially increased. As noted above, reserves of the Chinguetti field are under review as a result of the lower-than-expected production from the field. Until that review is completed, it would be premature to adjust depreciation rates, but any reduction in reserves would lead to higher future charges.
The expense for over / under-lifted crude entitlement reflects an over lifted position relative to co-venturers as at 30 June, at market values. Hardman's share of crude oil inventory in the FPSO at 30 June is carried at cost of production.
Net Profit
Exploration expense for the first half of 2006 was A$10.7 million (2005: A$6.5 million) reflecting dry hole expense in Mauritania and expensed G&G costs.
Other income comprised gains on the sale of minor equity investments in other oil exploration companies. Other expenses include some one-off advisors' fees. Interest and similar income includes foreign exchange translation gains of A$2.4 million arising on US dollar denominated cash balances, as the group holds surplus funds in US dollars to match the currency of its major expenditures.
Profit before tax was A$31.1 million (2005 first half: A$ 8.4 million loss).
Tax expense of A$8.2 million related to deferred Mauritanian tax on first half operating profit (2005 first half: A$ 14.5 million tax credit, due to release of deferred tax provisions following changes to Australian taxation of overseas income).
Hardman generated a profit after tax for the half-year of A$22.9 million (2005 first half: A$6.1 million).
Cash Flow
The net inflow from operating activities for the period was A$30.5 million compared with a A$2.8 million outflow for the comparable period. The net inflow included the proceeds from just the first two Hardman oil liftings from the Chinguetti field.
Capital expenditure cash flows were A$93.0 million for the period compared with A$93.7 million for the first half 2005. Development expenditure was A$53.0 million spent on completion of the phase 1 development on the Chinguetti field and including A$29.6 million for the Chinguetti Project Bonus on signature of revised production sharing contracts, referred to below (US$21.6 million). Exploration and appraisal cash spend was A$40.0 million, being significantly higher than on an accruals basis (A$25.9 million) due to payment for accruals at 31 December 2005.
The cash flow outflow before financing was therefore A$55.8 million (2005: A$96.1 million), mainly in the first quarter and therefore funded from cash resources.
Capital Resources
In April 2006 Hardman raised US$113 million through a placing in the London market of 65.9 million ordinary shares, equivalent to 10% of share capital. The placing was undertaken to fund accelerated exploration and appraisal activities, including follow up to the successful discovery wells in Uganda, and conducted in the London market to broaden the institutional investor base of the company. As a result of this equity placing the group had cash resources of A$223.7 million at 30 June. There were no changes to group borrowing apart from currency retranslation and capitalisation of certain borrowing costs so net cash at 30 June was A$135.7 million at 30 June (31 December: A$35.9 million).
The company is well funded for its committed exploration, although as noted above, planned exploration budgets are likely to be slightly reduced to reflect lower production cash flows.
Hedging
Hardman currently has hedging contracts in place as shown in the table below.
Period Put options at Sold call options at Purchased call US$42.00 - US$46.00 US$68.84 - US$76.25 options at US$85.00 (barrels per day) (barrels per day) (barrels per day)
August-December 4,200 1,900 500 2006
January-June 3,400 2,550 500 2007
July-December 3,400 2,500 - 2007
January-June 2,600 2,600 - 2008
Since the date of the previous report, some further call options from the original zero cost collars have been cancelled. The changes were made to manage exposures in light of the twin circumstances of reduced Chinguetti production levels and oil price strength. Hardman's option collars are accounted for as cash flow hedges under the relevant accounting standard.
Realised losses in the first half of A$4.2 million on cancelling call options, as well as the negative mark to market adjustment for outstanding contracts effective as hedges of future cash flows, have been accounted for initially through equity and will be recognised in the income statement over the periods to which the original forecast transactions related. Hedge effectiveness for changes in the value of hedged cash flows is assessed on a hypothetical derivative basis meaning that time value adjustments are dealt with in equity.
REVIEW OF OPERATIONS
MAURITANIA - WEST AFRICA
Chinguetti Field (Hardman 19.008% working interest, Woodside operated)
First oil from the Chinguetti field was achieved on 25 February 2006, a significant milestone for Hardman following its initiation of oil exploration offshore Mauritania and introduction of farm-in partners. The final project cost was US$708 million.
Production for the first half from the Chinguetti field was 5,921,833 barrels (gross), or an average of 46,600 bopd (gross) from first oil on 25 February, of which Hardman's net entitlement under the production sharing contract was 975,684 barrels, or 7,683 bopd, since first oil.
As previously reported, this reflects a significantly lower rate of production than anticipated under the field development plan. This arose initially from the poor performance of the two production wells in the northern part of the field, neither of which proved to be optimally located in the centre of the reservoir channel axis. This resulted in reduced deliverability and increased the dependence on the four southern producers. Early production problems were also exacerbated by rate-dependent gas coning and surface gas handling constraints. The decline continued through to early June, with aquifer water incursion becoming apparent in two of the southern wells, and pressure decline generally apparent in the southern blocks, at which point production eventually stabilised at approximately 35,000 bopd (gross).
Production in July was 35,100 bopd gross, and has averaged around 33,000 bopd gross from the 1st to 22nd of August, slightly better than the 32,400 bopd produced in June, mainly due to higher facilities uptime.
Notwithstanding the poor northern well performance, the principal cause for the performance of the reservoir not matching predictions would appear to be either unmodelled compartmentalisation and / or barriers limiting connectivity within the reservoir. Both of these elements have the effect of reducing the oil volume accessed by each well and of limiting the pressure support and sweep provided from the water injection wells. This is in addition to certain wells being sub-optimally completed away from the main sand channels or too close to gas caps or water contacts. The existing structural models of the Chinguetti field are being re-worked to better understand the reservoir, including a new interpretation of the 3D seismic dataset. This will inform subsequent modification of the reservoir development plan.
Earlier problems with delayed commissioning of the gas compression facilities have been largely rectified, with all three gas compressors now generally available. Consequently, gas flaring has now been reduced to a lower level, with most surplus gas production being re-injected into the nearby Banda reservoir, although some continued flaring is likely required to maintain full production.
Several initiatives are being planned or evaluated to improve reservoir production potential, including accelerated in-fill drilling, potentially acquiring additional high resolution seismic data over the field with the intention to create a 4D dataset and potential workovers to reduce water production. 4D seismic could provide significant insights and should enable us to understand the field mechanisms better and then assist the successful location of future wells.
An infill drilling campaign (phase 2a) is planned to commence in the fourth quarter 2006. However, with only one spare christmas tree available at present, completing more than one additional well in this phase would require retrieval and re-use of a tree from an existing low production well. The rig time and risk associated with this operation may lead the joint venture to defer drilling more than one well to the planned phase 2b of four production wells to start in the second half of 2007 when the results of the high resolution seismic should be available. The near term production outlook depends on the effectiveness of pressure support from water injection offsetting natural decline to keep production close to recent rates, with an initial increment of around 10,000 bopd (gross) to be expected from each new producer completed.
As previously announced, given the production history, the reserves for this field are under review. The operator is not expected to deliver the results of its current re-appraisal of the reservoir model and revised development plan to the joint venture until towards the end of 2006.
As an interim measure, Hardman has commented on oil in place and the likely reserves to be recovered via the 10 production wells forming the original development plan (phase 1 + phase 2); which had been estimated to recover 123 mmbbls of proven and probable reserves. Present oil in place is estimated at the P50 level not to be materially lower than the pre-development estimate of 380 mmbbls, with gains from lower oil water contacts in parts of the field seen in the development wells offset by poorer sand distribution. However, recoverable reserves from phases 1 and 2, given production performance to date and in particular the observed degree of reservoir compartmentalisation, should not be expected in aggregate to recover significantly more than half the original reserves of 123 mmbbls.
It should be noted however that any estimate of the 2P recoverable reserves must take into account additional recovery from other future wells in a re-assessed development plan. Ultimate recovery will also depend on the benefits from the proposed 4D seismic programme in early 2007 and application of different technical solutions (e.g. well designs) from those in the original development plans. These are the aspects which will be addressed over the remainder of 2006. The corresponding net entitlement reserves to Hardman under the production sharing arrangements are expected to be reduced by a lesser proportion than changes to the gross field reserves.
Tiof (Hardman 21.6% equity, Woodside operated)
Concept definition studies are in progress following the selection in the second quarter of a dry tree concept as the preferred Tiof development scenario. Current activity comprises more detailed evaluation of a tension leg platform (TLP) concept by SEA Engineering in Houston, USA. Other work streams include a well engineering team tasked with the drilling rig component of the design, a subsurface team tasked with locating the wells and an environmental team.
Subject to joint venture approval, the operator's current plan is to move to a competitive basis of design tender over the remainder of this year, with a view to declaration of commerciality around year end. A final investment decision would follow by Q2 2007.
Results from Chinguetti production and lessons learned in the drilling of the development wells are already being incorporated into the Tiof development planning, and consequently Chinguetti technical issues are unlikely to negatively impact any Tiof decision. The business case for high resolution 3D is currently being assessed to assist with locating development wells.
Reserves for Phase 1 are now provisionally estimated at 50-60 mmbbls, increased over the earlier estimate due to the planned extended reach of wells from the central facility, with subsequent phases to access additional reserves.
Evaluation of the Tevet discovery as tie-back to the Chinguetti facilities is continuing, with Tevet being fast tracked to determine whether to proceed now with development of the core part of the Tevet reservoir or undertake further appraisal work to better define the reservoir.
Mauritania Exploration
The Zoule-1 and Dore-1 wells were completed as dry holes in the first quarter as part of the 2005 drilling campaign. Exploration drilling resumed in July following the arrival of the Atwood Hunter semi-submersible rig in offshore Mauritania.
The drilling sequence commenced with the PSC Area A Colin-1 Miocene prospect, which despite a significant reservoir sand section did not intersect any commercial hydrocarbons. The rig is currently drilling the Flamant-1 well in Block 8 to be followed by Aigrette-1 in Block 7, before returning to the Area A joint venture to drill Kibaro-1. Afterwards it will commence Chinguetti production drilling as discussed above.
It will then depart Mauritania for eight months as planned, before returning later in 2007 for a further contract period of eight months, with an option to extend. It is possible that the sequence could be modified after the Aigrette well to prioritise Chinguetti field work ahead of drilling Kibaro.
PSC A and B (Hardman 24.3% and 21.6% equity respectively, Woodside operated)
The Colin-1 well encountered excellent quality reservoir 'B' sands in the target interval but no significant hydrocarbons. Reasons for failure are attributed to a lack of seal at the head of the Colin channel. The sand quality was much higher than those intersected at Chinguetti where the 'B' sands are known to be gas bearing.
The operator is in the process of reviewing its definition of drilling candidates for 2007 wells, focusing on near Tiof and near Chinguetti potential tie back prospects.
Following the revised PSC settlement with the Mauritanian Government, the area defining the Chinguetti Exclusive Exploitation Authorisation (EEA) is now proposed to be restricted to the Chinguetti field only. All of the remaining area, previously under the EEA, is proposed to be again defined as part of Area B and subject to the second exploration period relinquishment. The Area B relinquishment consists of the western deep water portion and is to be formally resubmitted in the third quarter for approval by the Mauritanian Government.
Block 8 (Hardman 18% equity, Dana operated)
The Flamant-1 well presently being drilled is considered a key well to identifying significant resource potential in northern offshore Mauritania and is the best test of a large regional high with both primary and deeper secondary objectives. Significant follow up potential exists within the permit for this new play type targeting Cretaceous carbonate platform/reefs. The Flamant prospect has the potential to contain about 5 TCF of gas recoverable.
Block 7 (Hardman 16.2% equity, Dana operated)
The joint venture selected Aigrette-1 for drilling after the Flamant-1 well in Block 8. Aigrette-1 is primarily a gas prospect on trend from the Pelican-1 gas discovery. The primary targets are stacked Cretaceous sandstones with some 0.7 TCF potential.
Mauritania Commercial
On 6 June 2006 Hardman and its co-venturers signed revised production sharing contracts (PSCs) for Areas A, B, C Block 2 and C Block 6 offshore Mauritania, bringing to a close the dispute earlier this year over amendments to the original PSCs. In summary, the major elements of the resolutions are: exploration periods secured in line with previous arrangements; a Chinguetti production bonus of US$100 million gross (Hardman share 21.6%) paid by the Area B participants following the approval of the revised contract; a modest increase in the share of revenue to the Mauritanian Government during periods when the realised oil price exceeds US$55 per barrel; and establishment of an Environmental Commission funded through a total annual payment of US$1 million by the joint venturers during the life of production from the revised PSCs.
UGANDA - EAST AFRICA (Hardman 50% equity and operator)
During the first half of 2006 Hardman, as operator, completed drilling the Mputa-1 exploration well and drilled the exploration well Waraga-1, and appraisal well Mputa-2.
At Waraga-1 oil was encountered in three sand intervals. Mputa-1 had already encountered oil in two intervals and Mputa-2 confirmed the lateral extent of both the upper and lower target sandstones. However, the upper zone contained water whilst the lower zone contained oil which can be correlated to similar oil bearing zones in both Mputa-1 and Waraga-1.
The presence of oil saturated sands in these basal units in all wells drilled to date implies an extensive stratigraphic trapping mechanism at this level. All three wells were cased and suspended for potential future production.
Flow testing was carried out on the Waraga-1 and Mputa-1 discoveries. Three oil bearing zones were perforated and successfully tested in the Waraga-1 well. Waraga tests indicate excellent reservoir quality with high permeability and deliverability, and the oil has good natural flow characteristics with maximum flow rates of 4,200 bopd from each of two of the three individual tests. A summary of the test results is shown below:
Waraga-1 Perforated Interval Main test (36/64" Maximum flow (1" Oil quality Test Depth choke) choke
£1. Lower 1,888-1,894 metres 1,500 bopd 4,200 bopd 33.6degrees Zone API
£2. Middle 1,782-1,792.5 2,400 bopd 4,200 bopd 33.8degrees Zone metres API
£3. Upper 1,680-1,710 metres 2,100 bopd 3,650 bopd 18.6degrees Zone API TOTAL 6,000 bopd 12,050 bopd
Mputa-1 was then tested, with the first of three tests being a speculative test of the fractured basement. Oil was recovered on this test but failed to flow to surface. The second test was of thin sand near basement which flowed at 300 bopd while the third test of the main sand at 966.5m - 974.5m flowed at a maximum rate of 820 bopd. The oil from the two zones was essentially the same quality with a 33 degree API which in turn is similar to the oil in the lower two tested zones in Waraga-1. A summary of the test results is shown below:
Mputa-1 Test Perforated Interval Depth choke Flow Oil quality
£2. Lower Zone 1,118-1,126 metres 32/64" 300 bopd 32degrees API
£3. Upper Zone 966.5-974.5 metres 40/64" 820 bopd 33degrees API TOTAL 1,120 bopd
These test results prove not only that the oil at Mputa is mobile but also that the reservoir sandstones are capable of producing oil under natural flow at potentially commercial rates. The latter aspect is particularly significant, given that the Mputa reservoirs are at shallower depth, and are hence at lower pressure and temperature than the corresponding reservoir units at Waraga. This positive test result therefore expands the operating envelope over which typical Waraga and Mputa crudes can be produced and eliminates pre-test concerns over oil viscosity and fluid properties at these shallower depths. The oil column extends approximately 170m below the Mputa-1 reservoir intersection as well as up-dip to the crest of the structure.
In the limited portion of the block we have explored to date (approximately 6%) we have already established oil in place of 100-300 mmbbls, and potential recoverable volumes of the order of 30 mmbbls with near term upside from success at Nzizi appraisal well to be drilled by the end of 2006, up-dip from discovered oil at Mputa. Further additions are likely from near field appraisal and exploration, but the greatest potential offshore, beneath Lake Albert, has yet to be tested. With these very encouraging early results, we will pursue the wider exploration of this area in an aggressive campaign. Subject to further studies, the demands of the local power market suggest an initial early production scheme would be both feasible and commercial, as well as a high priority for the Ugandan Government.
The JV has presented potential options to the Government and is currently in discussions concerning the way forward including the exploration, further appraisal and potential development concepts applicable for the Block. A further onshore exploration and appraisal drilling programme is planned to commence in the fourth quarter of 2006. Preparations are underway for drilling the Nzizi prospect anticipating the well will spud in December 2006, as well as evaluating options for future drilling of the large Ngassa prospect offshore Lake Albert where the JV has committed to evaluating options that could see commencement of drilling on the lake by the end of 2007.
In addition, planning is well advanced for the acquisition of onshore 2D seismic at the north-eastern region of Lake Albert which should commence in the fourth quarter of 2006. This area to the East of Butiaba has not been explored previously. However, there are numerous oil seeps within the area and oil shows were noted in the 1938 Waki-1 well. A gravity survey recently completed by the Ugandan Government's Petroleum Exploration and Production Department suggests significant potential for structural traps in the area and these data have been used in the planning of the layout of the 2D seismic.
TANZANIA - EAST AFRICA (Hardman 50% equity and Operator, subject to farm-in obligations)
During the first half Hardman announced a farm-in to the Mtwara and Lindi licences held by Aminex plc. The Tanzanian Government has approved the assignments. Hardman will become operator following the completion of acquisition of 500kms of 2D seismic data. Planning is underway for a marine-to-shore transition 2D seismic survey in the Lindi licence, to be operated by Hardman. The transition survey is targeting a large prospect which straddles the coast line. This prospect was initially mapped on vintage seismic data. The marine 2D seismic data acquired in late 2005 supports the original interpretation.
Planning is also underway for a land 2D seismic survey in the Mtwara Licence, again addressing structures mapped on vintage data.
GUYANE - SOUTH AMERICA (Hardman 97.5% equity and Operator)
The permit has now progressed into the second exploration period as at 1st June 2006, following an application for a second five year permit term, although it remains subject to official rendering of title by the Government authorities. Hardman's proposed farm-out of equity in this very large permit is progressing; discussions are currently underway with a number of potential farm-in partners to take this project forward to the drilling phase. It is likely to still take a number of months to conclude commercial arrangements.
SURINAME - SOUTH AMERICA (Hardman 40%, subject to farm-in obligations. Paradise Oil operated)
In April, Hardman announced a Heads of Agreement to acquire a 40% working interest in the onshore Uitkijk and Coronie concessions in Suriname held by Paradise Oil, a subsidiary of the State oil company, Staatsolie. Discussions with Paradise Oil have since progressed well, with signing of the PSCs anticipated in Q4 2006. The concessions are both large and prospective, covering a total area of approximately 3,300 square kilometres, and lying directly adjacent to Suriname's main producing oil fields, Tambaredjo and Calcutta, which collectively have over 1 billion barrels of oil in place and produce approximately 13,000 bopd.
Hardman will earn its interest via the funding of an initial, capped, exploration campaign of up to 25 wells. Rig options are under active consideration by the operator, but commencement of drilling is not now likely before Q2 2007, this is delayed from the previously announced Q4 2006 due to rig selection.
FALKLAND ISLANDS - OFFSHORE SOUTH AMERICA (Hardman 22.5% equity, FOGL operated)
The initial results of the 2005/06 seismic survey have confirmed the diversity of leads and the overall good prospectivity of the licence area. The forward work program comprises 5150km 2D seismic, 550km Controlled Source Electro-Magnetic (CSEM) survey, and a provisional seabed coring program. The CSEM technology is a cost effective method of high grading the extensive inventory of stratigraphic and structural leads mapped in the seven licenses. The strategy will be to obtain CSEM data over the larger leads, and based on the results, acquire infill 2D seismic in order to determine the best sites for exploration wells. Drillable prospects will need to be of a sufficient size to be potentially commercial in this remote area. Drilling is not expected to commence before 2008.
SIMON POTTER CEO & MANAGING DIRECTOR
Note: (1) In accordance with the ASX Listing Rules, the geological information supplied in this report has been based on information provided by geologists who have had in excess of five years experience in their field of activity.
(2)In accordance with the AIM Rules, the information in this report has been reviewed and signed off by Mr. Andrew Patterson, B Eng., Technical Manager of Hardman Resources, who is a member of the Society of Petroleum Engineers of Australia and has at least 5 years relevant experience within the sector.
HDR Price at posting:
0.0¢ Sentiment: Hold Disclosure: Not Held