Highlands Natural Resources Regulatory News (HNR)

29 Aug 2006 07:01

Hardman Resources Limited29 August 2006 August 29 2006 - For Immediate Release HARDMAN REPORTS POST TAX PROFIT OF A$22.9 MILLION FOR FIRST HALF 2006 Hardman Resources Limited ("Hardman" or the "Company") today announced resultsfor the six months ended 30 June 2006 for the Company and its controlledentities (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 inMauritania, drilled our first operated international exploration wells resultingin the discovery of an exciting new oil province in Uganda, and accessedcomplementary new exploration opportunities. The unpredicted decline in production and need to review reserves at Chinguettiwas, however, a disappointment and suggests that the reservoir development ofthis field will be a challenging process of optimisation and application oftechnology over time to enhance recovery. But high margin barrels and a strongprevailing oil price mean the prize for translating oil in place to sold barrelsis substantial and a strong incentive for the Joint Venture. Despite setbacks the mitigation lies in pursuing our existing strategy to fullyexploit our portfolio. We have substantial net cash, an inventory ofexploration, 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 significantinternational exploration and production company to add material net asset valuefor shareholders." - Simon Potter, CEO and Managing Director For more information: Simon Potter: CEO / MD +61 8 9261 7600Peter Thomas: CFO +61 8 9261 7600 Australian Media Contacts: Jill Thomas, Hardman Resources +61 8 9261 7600London 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 milestonessuccessfully passed. The Chinguetti field was successfully brought on-stream on 25 February (WST),twenty-two months after development approval. As the initiator of modernexploration offshore Mauritania in 1996, Hardman has played a key role in manyof the steps that made this possible, and the realisation of the firstproduction revenues is a transforming event for the Company. For the first timewe have significant operating cash flows available for re-investment. The start of production has coincided with a period of historically high oilprices, and as a result, we have today been able to announce a first half profitof A$22.9 million. Also in the first half, Hardman's first international exploration drilling asoperator, onshore Uganda, resulted in two discoveries, at Mputa and Waraga,which have subsequently been successfully tested and appraised. Thesediscoveries have created an entirely new potential oil province in Uganda andsignificantly upgraded the further exploration potential of the Western RiftValley margin play in this area. In the limited portion of the block we haveexplored to date (approximately 6%) we have already established oil in place of100-300 mmbbls and potential recoverable volumes of the order of 30 mmbbls withnear term upside from success at Nzizi appraisal well to be drilled by the endof 2006, up-dip from discovered oil at Mputa. Further additions are likely fromnear field appraisal and exploration, but the greatest potential offshore,beneath Lake Albert, has yet to be tested. With these very encouraging earlyresults, we will pursue the wider exploration of this area in an aggressivecampaign. Subject to further studies, the demands of the local power marketsuggest an initial early production scheme would be both feasible andcommercial, as well as a high priority for the Ugandan Government. At the same time, we have been disappointed by the production performance of theChinguetti field. Production has averaged 46,600 bopd (gross) since first oilbut showed an unexpected sharp decline through to June, before stabilising atrates of around 35,000 bopd, well below the predicted 60-70 mbopd.Notwithstanding this reduced rate, each sold barrel has realised US$56/bbl toHardman (net of operating costs). Below we explain the current understanding ofthe field's performance and the unpredicted reservoir complexities now evident,and also outline the remedial plans that are underway. It is clear that thereare no quick solutions, that considerable additional capital expenditure andtechnological application will be needed, and that a downward adjustment to therecoverable reserves of the field is inevitable. At this stage, it would bepremature to announce a complete new reserves estimate, as the operator hasongoing work to re-appraise its reservoir models and optimise the ensuingdevelopment plan. However, we can comment that the wells in the initialdevelopment plan are unlikely to recover significantly more than half theoriginally estimated reserves. Hardman will continue to provide shareholderswith as much clarity as we can on the current situation and plans as theydevelop. The problems to be overcome suggest that reservoir management of this field isgoing to be an ongoing process of gaining understanding of reservoir behaviourand 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 toprofitably use technology proven elsewhere to enhance recovery over time. Withhigh margin barrels and a strong prevailing oil price the prize for translatingoil in place to sold barrels is substantial. Further, notwithstanding the lowerproduction rates, the finding and development costs of the Chinguetti projectshould, 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 BDore-1 well and most recently in the new drilling campaign the Colin-1 well inPSC A were all unsuccessful. The remainder of the 2006 exploration wells targetdifferent plays, including considerable gas potential in Block 8 and the shallowwater Cretaceous play within PSC Area A at Kibaro. During the six month periodwe resolved a dispute with the Mauritanian Government over the validity ofcertain supplementary agreements to the production sharing contracts (PSCs).This was settled with revisions in contract terms contained in revised PSCssigned in June. Meanwhile the potential Tiof development progressed throughconcept selection to more detailed engineering work preparatory to a declarationof 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, bothwith modest entry costs. Being onshore exploration plays, with lower costs andfaster cycle times, and in Suriname's case being adjacent to existing oilproduction, these ventures complement the mainly offshore, high risk - highreward profile of Hardman's portfolio to date. The farm-out of our Guyanelicence showed good early progress in the second quarter and is at the stage ofdetailed negotiation with several parties. In April we raised US$113 million in an equity placing in the London market, ata very narrow discount to the then share price. We decided on this course toprovide funding for accelerated exploration of opportunities within ourportfolio and new ventures, including appraisal of the Uganda discoveries andfollow up exploration in the area. Accessing the London market has broadened ourshareholder base and brought some major new institutions onto the register. As aresult, we had net cash at the end of June of A$136 million. The reduced near term production outlook will inevitably require adjustment toour exploration plans but, with an increasingly operated portfolio, we arebetter placed to influence the pace and prioritisation of activities. We expectto spend some US$65 million on exploration and appraisal this year and a similaramount again next year. This will include allocating a greater proportion of thebudget to the now proven Ugandan play. The overall budget has been re-phased inpart as a result of tight rig availabilities and likely prioritisation ofcontracted rig slots to production work offshore Mauritania, rather thanexploration. Hardman has substantial net cash to allow us to continue to pursue ourarticulated strategy; we have a considerable resource base in Mauritania and thecapacity to accelerate activity in our exciting new play emerging in Uganda. Ourinternal capabilities are growing, maturing in our Uganda operations and thesuccessful delivery of new ventures elsewhere. We are confident of developingHardman into a significant international exploration and production company toadd material net asset value for shareholders. Dealing with the multiple issues we have faced in Mauritania, the highly activecampaign in Uganda, the fund raising and new venturing have all placed highdemands on our small staff, and on behalf of the Board I would like to thankthem for their high commitment, flexibility and resourcefulness. BOARD On 30 June, the Company announced that Mr. RA (Bob) Carroll was appointed asChairman to succeed the founding Chairman of the Company, Mr. Alan Burns, whohad elected to retire and ceased to be the Chairman and Director with effectfrom 3 July 2006. Mr. Peter Mansell and Mr. John Conlin joined the Board of theCompany as Independent, Non-executive Directors effective 18 May 2006. Earlier, on 12 April 2006, the Company announced that Mr. Scott Spencer hadretired from the Board after nearly 12 years' service in an Executive, and morerecently in a non-executive, capacity. FINANCE 1H 2006 1H 2005PRODUCTION & SALES DATA Crude oil production ('000 barrels) - Hardman share 976 - Sales volume ('000 barrels) 856 -Overlifted volume ('000 barrels) (56)Inventory volume ('000 barrels) 176Sales revenue from operations (A$ million) 74.5 -Cash revenue from operations (A$ million) 46.6 -Realised oil price (US$ per barrel) 63.90 - 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 6.1Earnings per share (basic) (cents per share) 3.4 0.9BALANCE SHEET (A$ million)Cash 223.7 120.8Net 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, followingthe commencement of production on 25 February 2006. The average realised oilprice was US$63.90 per barrel, with Chinguetti crude attracting an initialquality discount to dated Brent of around US$5 to $6 per barrel, reflecting itbeing a new crude and early production levels being uncertain. As at 30 June,Hardman was over lifted compared with its entitlement to production resulting inan expense, reflected in Cost of Sales, to put Gross Profit onto a productionentitlements basis. Cost of sales Cost of sales comprises field operating costs, including insurance,depreciation, depletion and amortisation (dd&a) charges, and over / underlifting adjustments. Operating costs were A$10.51 per barrel produced,principally comprising the Berge Helene FPSO lease charge. Depreciation wasA$17.15 per barrel, including the impact of future capital costs to develop theestimated reserves of the Chinguetti field, which have been substantiallyincreased. As noted above, reserves of the Chinguetti field are under review asa result of the lower-than-expected production from the field. Until that reviewis completed, it would be premature to adjust depreciation rates, but anyreduction in reserves would lead to higher future charges. The expense for over / under-lifted crude entitlement reflects an over liftedposition relative to co-venturers as at 30 June, at market values. Hardman'sshare of crude oil inventory in the FPSO at 30 June is carried at cost ofproduction. Net Profit Exploration expense for the first half of 2006 was A$10.7 million (2005: A$6.5million) reflecting dry hole expense in Mauritania and expensed G&G costs. Other income comprised gains on the sale of minor equity investments in otheroil exploration companies. Other expenses include some one-off advisors' fees.Interest and similar income includes foreign exchange translation gains of A$2.4million arising on US dollar denominated cash balances, as the group holdssurplus 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$8.2 million related to deferred Mauritanian tax on first halfoperating profit (2005 first half: A$ 14.5 million tax credit, due to release ofdeferred tax provisions following changes to Australian taxation of overseasincome). Hardman generated a profit after tax for the half-year of A$22.9 million (2005first half: A$6.1 million). Cash Flow The net inflow from operating activities for the period was A$30.5 millioncompared with a A$2.8 million outflow for the comparable period. The net inflowincluded the proceeds from just the first two Hardman oil liftings from theChinguetti field. Capital expenditure cash flows were A$93.0 million for the period compared withA$93.7 million for the first half 2005. Development expenditure was A$53.0million spent on completion of the phase 1 development on the Chinguetti fieldand including A$29.6 million for the Chinguetti Project Bonus on signature ofrevised production sharing contracts, referred to below (US$21.6 million).Exploration and appraisal cash spend was A$40.0 million, being significantlyhigher than on an accruals basis (A$25.9 million) due to payment for accruals at31 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 cashresources. Capital Resources In April 2006 Hardman raised US$113 million through a placing in the Londonmarket of 65.9 million ordinary shares, equivalent to 10% of share capital. Theplacing was undertaken to fund accelerated exploration and appraisal activities,including follow up to the successful discovery wells in Uganda, and conductedin 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$223.7million at 30 June. There were no changes to group borrowing apart from currencyretranslation and capitalisation of certain borrowing costs so net cash at 30June 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 notedabove, planned exploration budgets are likely to be slightly reduced to reflectlower 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 5002006 January-June 3,400 2,550 5002007 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 theoriginal zero cost collars have been cancelled. The changes were made to manageexposures in light of the twin circumstances of reduced Chinguetti productionlevels and oil price strength. Hardman's option collars are accounted for ascash 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 initiallythrough equity and will be recognised in the income statement over the periodsto 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 valueadjustments 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, asignificant milestone for Hardman following its initiation of oil explorationoffshore Mauritania and introduction of farm-in partners. The final project costwas 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, ofwhich Hardman's net entitlement under the production sharing contract was975,684 barrels, or 7,683 bopd, since first oil. As previously reported, this reflects a significantly lower rate of productionthan anticipated under the field development plan. This arose initially from thepoor 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 reservoirchannel axis. This resulted in reduced deliverability and increased thedependence on the four southern producers. Early production problems were alsoexacerbated by rate-dependent gas coning and surface gas handling constraints.The decline continued through to early June, with aquifer water incursionbecoming apparent in two of the southern wells, and pressure decline generallyapparent in the southern blocks, at which point production eventually stabilisedat approximately 35,000 bopd (gross). Production in July was 35,100 bopd gross, and has averaged around 33,000 bopdgross from the 1st to 22nd of August, slightly better than the 32,400 bopdproduced in June, mainly due to higher facilities uptime. Notwithstanding the poor northern well performance, the principal cause for theperformance of the reservoir not matching predictions would appear to be eitherunmodelled compartmentalisation and / or barriers limiting connectivity withinthe reservoir. Both of these elements have the effect of reducing the oil volumeaccessed by each well and of limiting the pressure support and sweep providedfrom the water injection wells. This is in addition to certain wells beingsub-optimally completed away from the main sand channels or too close to gascaps or water contacts. The existing structural models of the Chinguetti fieldare being re-worked to better understand the reservoir, including a newinterpretation of the 3D seismic dataset. This will inform subsequentmodification of the reservoir development plan. Earlier problems with delayed commissioning of the gas compression facilitieshave been largely rectified, with all three gas compressors now generallyavailable. Consequently, gas flaring has now been reduced to a lower level, withmost 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 reservoirproduction potential, including accelerated in-fill drilling, potentiallyacquiring additional high resolution seismic data over the field with theintention to create a 4D dataset and potential workovers to reduce waterproduction. 4D seismic could provide significant insights and should enable usto understand the field mechanisms better and then assist the successfullocation of future wells. An infill drilling campaign (phase 2a) is planned to commence in the fourthquarter 2006. However, with only one spare christmas tree available at present,completing more than one additional well in this phase would require retrievaland re-use of a tree from an existing low production well. The rig time and riskassociated with this operation may lead the joint venture to defer drilling morethan one well to the planned phase 2b of four production wells to start in thesecond half of 2007 when the results of the high resolution seismic should beavailable. The near term production outlook depends on the effectiveness ofpressure support from water injection offsetting natural decline to keepproduction close to recent rates, with an initial increment of around 10,000bopd (gross) to be expected from each new producer completed. As previously announced, given the production history, the reserves for thisfield are under review. The operator is not expected to deliver the results ofits current re-appraisal of the reservoir model and revised development plan tothe joint venture until towards the end of 2006. As an interim measure, Hardman has commented on oil in place and the likelyreserves to be recovered via the 10 production wells forming the originaldevelopment plan (phase 1 + phase 2); which had been estimated to recover 123mmbbls of proven and probable reserves. Present oil in place is estimated at theP50 level not to be materially lower than the pre-development estimate of 380mmbbls, with gains from lower oil water contacts in parts of the field seen inthe development wells offset by poorer sand distribution. However, recoverablereserves from phases 1 and 2, given production performance to date and inparticular the observed degree of reservoir compartmentalisation, should not beexpected in aggregate to recover significantly more than half the originalreserves of 123 mmbbls. It should be noted however that any estimate of the 2P recoverable reserves musttake into account additional recovery from other future wells in a re-assesseddevelopment plan. Ultimate recovery will also depend on the benefits from theproposed 4D seismic programme in early 2007 and application of differenttechnical solutions (e.g. well designs) from those in the original developmentplans. These are the aspects which will be addressed over the remainder of 2006.The corresponding net entitlement reserves to Hardman under the productionsharing arrangements are expected to be reduced by a lesser proportion thanchanges to the gross field reserves. Tiof (Hardman 21.6% equity, Woodside operated) Concept definition studies are in progress following the selection in the secondquarter 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 awell engineering team tasked with the drilling rig component of the design, asubsurface team tasked with locating the wells and an environmental team. Subject to joint venture approval, the operator's current plan is to move to acompetitive basis of design tender over the remainder of this year, with a viewto declaration of commerciality around year end. A final investment decisionwould follow by Q2 2007. Results from Chinguetti production and lessons learned in the drilling of thedevelopment wells are already being incorporated into the Tiof developmentplanning, and consequently Chinguetti technical issues are unlikely tonegatively impact any Tiof decision. The business case for high resolution 3D iscurrently being assessed to assist with locating development wells. Reserves for Phase 1 are now provisionally estimated at 50-60 mmbbls, increasedover the earlier estimate due to the planned extended reach of wells from thecentral facility, with subsequent phases to access additional reserves. Tevet Appraisal (Hardman 21.6%equity, Woodside operated) Evaluation of the Tevet discovery as tie-back to the Chinguetti facilities iscontinuing, with Tevet being fast tracked to determine whether to proceed nowwith development of the core part of the Tevet reservoir or undertake furtherappraisal work to better define the reservoir. Mauritania Exploration The Zoule-1 and Dore-1 wells were completed as dry holes in the first quarter aspart of the 2005 drilling campaign. Exploration drilling resumed in Julyfollowing the arrival of the Atwood Hunter semi-submersible rig in offshoreMauritania. The drilling sequence commenced with the PSC Area A Colin-1 Miocene prospect,which despite a significant reservoir sand section did not intersect anycommercial hydrocarbons. The rig is currently drilling the Flamant-1 well inBlock 8 to be followed by Aigrette-1 in Block 7, before returning to the Area Ajoint 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 modifiedafter the Aigrette well to prioritise Chinguetti field work ahead of drillingKibaro. 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 targetinterval but no significant hydrocarbons. Reasons for failure are attributed toa lack of seal at the head of the Colin channel. The sand quality was muchhigher than those intersected at Chinguetti where the 'B' sands are known to begas bearing. The operator is in the process of reviewing its definition of drillingcandidates for 2007 wells, focusing on near Tiof and near Chinguetti potentialtie back prospects. Following the revised PSC settlement with the Mauritanian Government, the areadefining the Chinguetti Exclusive Exploitation Authorisation (EEA) is nowproposed to be restricted to the Chinguetti field only. All of the remainingarea, previously under the EEA, is proposed to be again defined as part of AreaB and subject to the second exploration period relinquishment. The Area Brelinquishment consists of the western deep water portion and is to be formallyresubmitted 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 toidentifying significant resource potential in northern offshore Mauritania andis the best test of a large regional high with both primary and deeper secondaryobjectives. Significant follow up potential exists within the permit for thisnew play type targeting Cretaceous carbonate platform/reefs. The Flamantprospect 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 inBlock 8. Aigrette-1 is primarily a gas prospect on trend from the Pelican-1 gasdiscovery. The primary targets are stacked Cretaceous sandstones with some 0.7TCF potential. Mauritania Commercial On 6 June 2006 Hardman and its co-venturers signed revised production sharingcontracts (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 theoriginal PSCs. In summary, the major elements of the resolutions are:exploration periods secured in line with previous arrangements; a Chinguettiproduction bonus of US$100 million gross (Hardman share 21.6%) paid by the AreaB participants following the approval of the revised contract; a modest increasein the share of revenue to the Mauritanian Government during periods when therealised oil price exceeds US$55 per barrel; and establishment of anEnvironmental Commission funded through a total annual payment of US$1 millionby 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 theMputa-1 exploration well and drilled the exploration well Waraga-1, andappraisal well Mputa-2. At Waraga-1 oil was encountered in three sand intervals. Mputa-1 had alreadyencountered oil in two intervals and Mputa-2 confirmed the lateral extent ofboth the upper and lower target sandstones. However, the upper zone containedwater whilst the lower zone contained oil which can be correlated to similar oilbearing zones in both Mputa-1 and Waraga-1. The presence of oil saturated sands in these basal units in all wells drilled todate implies an extensive stratigraphic trapping mechanism at this level. Allthree wells were cased and suspended for potential future production. Flow testing was carried out on the Waraga-1 and Mputa-1 discoveries. Three oilbearing zones were perforated and successfully tested in the Waraga-1 well.Waraga tests indicate excellent reservoir quality with high permeability anddeliverability, and the oil has good natural flow characteristics with maximumflow rates of 4,200 bopd from each of two of the three individual tests. Asummary of the test results is shown below: Waraga-1 Perforated Interval Main test (36/64" Maximum flow (1" Oil qualityTest Depth choke) choke #1. Lower 1,888-1,894 metres 1,500 bopd 4,200 bopd 33.6degreesZone API #2. Middle 1,782-1,792.5 2,400 bopd 4,200 bopd 33.8degreesZone metres API #3. Upper 1,680-1,710 metres 2,100 bopd 3,650 bopd 18.6degreesZone API TOTAL 6,000 bopd 12,050 bopd Mputa-1 was then tested, with the first of three tests being a speculative testof the fractured basement. Oil was recovered on this test but failed to flow tosurface. The second test was of thin sand near basement which flowed at 300 bopdwhile the third test of the main sand at 966.5m - 974.5m flowed at a maximumrate of 820 bopd. The oil from the two zones was essentially the same qualitywith a 33 degree API which in turn is similar to the oil in the lower two testedzones 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 thatthe reservoir sandstones are capable of producing oil under natural flow atpotentially commercial rates. The latter aspect is particularly significant,given that the Mputa reservoirs are at shallower depth, and are hence at lowerpressure and temperature than the corresponding reservoir units at Waraga. Thispositive test result therefore expands the operating envelope over which typicalWaraga and Mputa crudes can be produced and eliminates pre-test concerns overoil viscosity and fluid properties at these shallower depths. The oil columnextends 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 potentialrecoverable volumes of the order of 30 mmbbls with near term upside from successat Nzizi appraisal well to be drilled by the end of 2006, up-dip from discoveredoil at Mputa. Further additions are likely from near field appraisal andexploration, but the greatest potential offshore, beneath Lake Albert, has yetto be tested. With these very encouraging early results, we will pursue thewider exploration of this area in an aggressive campaign. Subject to furtherstudies, the demands of the local power market suggest an initial earlyproduction scheme would be both feasible and commercial, as well as a highpriority for the Ugandan Government. The JV has presented potential options to the Government and is currently indiscussions concerning the way forward including the exploration, furtherappraisal and potential development concepts applicable for the Block. A furtheronshore exploration and appraisal drilling programme is planned to commence inthe fourth quarter of 2006. Preparations are underway for drilling the Nziziprospect anticipating the well will spud in December 2006, as well as evaluatingoptions for future drilling of the large Ngassa prospect offshore Lake Albertwhere the JV has committed to evaluating options that could see commencement ofdrilling on the lake by the end of 2007. In addition, planning is well advanced for the acquisition of onshore 2D seismicat the north-eastern region of Lake Albert which should commence in the fourthquarter of 2006. This area to the East of Butiaba has not been exploredpreviously. However, there are numerous oil seeps within the area and oil showswere noted in the 1938 Waki-1 well. A gravity survey recently completed by theUgandan Government's Petroleum Exploration and Production Department suggestssignificant potential for structural traps in the area and these data have beenused in the planning of the layout of the 2D seismic. TANZANIA - EAST AFRICA (Hardman 50% equity and Operator, subject to farm-inobligations) During the first half Hardman announced a farm-in to the Mtwara and Lindilicences held by Aminex plc. The Tanzanian Government has approved theassignments. Hardman will become operator following the completion ofacquisition of 500kms of 2D seismic data. Planning is underway for amarine-to-shore transition 2D seismic survey in the Lindi licence, to beoperated by Hardman. The transition survey is targeting a large prospect whichstraddles the coast line. This prospect was initially mapped on vintage seismicdata. The marine 2D seismic data acquired in late 2005 supports the originalinterpretation. 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 June2006, following an application for a second five year permit term, although itremains 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 partnersto take this project forward to the drilling phase. It is likely to still take anumber of months to conclude commercial arrangements. SURINAME - SOUTH AMERICA (Hardman 40%, subject to farm-in obligations. ParadiseOil operated) In April, Hardman announced a Heads of Agreement to acquire a 40% workinginterest in the onshore Uitkijk and Coronie concessions in Suriname held byParadise Oil, a subsidiary of the State oil company, Staatsolie. Discussionswith Paradise Oil have since progressed well, with signing of the PSCsanticipated in Q4 2006. The concessions are both large and prospective, coveringa total area of approximately 3,300 square kilometres, and lying directlyadjacent to Suriname's main producing oil fields, Tambaredjo and Calcutta, whichcollectively have over 1 billion barrels of oil in place and produceapproximately 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 activeconsideration by the operator, but commencement of drilling is not now likelybefore Q2 2007, this is delayed from the previously announced Q4 2006 due to rigselection. FALKLAND ISLANDS - OFFSHORE SOUTH AMERICA (Hardman 22.5% equity, FOGL operated) The initial results of the 2005/06 seismic survey have confirmed the diversityof leads and the overall good prospectivity of the licence area. The forwardwork program comprises 5150km 2D seismic, 550km Controlled SourceElectro-Magnetic (CSEM) survey, and a provisional seabed coring program. TheCSEM technology is a cost effective method of high grading the extensiveinventory 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 theresults, acquire infill 2D seismic in order to determine the best sites forexploration wells. Drillable prospects will need to be of a sufficient size tobe potentially commercial in this remote area. Drilling is not expected tocommence before 2008. SIMON POTTERCEO & MANAGING DIRECTOR Note: (1) In accordance with the ASX Listing Rules, the geological informationsupplied in this report has been based on information provided by geologists whohave had in excess of five years experience in their field of activity. (2)In accordance with the AIM Rules, the information in this report hasbeen reviewed and signed off byMr. Andrew Patterson, B Eng., Technical Manager of Hardman Resources, who is amember of the Society of Petroleum Engineers of Australia and has at least 5years relevant experience within the sector. This information is provided by RNS The company news service from the London Stock Exchange