this deserves careful analysis

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 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 -

Sales volume ('000 barrels) 856 -
Overlifted volume ('000 barrels) (56)
Inventory volume ('000 barrels) 176
Sales 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 6.1
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.

Tevet Appraisal (Hardman 21.6%equity, Woodside operated)

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.