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Austral Pacific Energy Limited Interim Results

3 Aug 2006

Austral Pacific Energy Ltd. has provided a copy of its unaudited Interim financial statements and Management Discussion & Analysis for the six months ended 30 June 2006.

The full filings are also available on the Austral Pacific Energy Ltd. website (www.austral-pacific.com) or on SEDAR, the Canadian securities commissions' filing system (www.sedar.com).

Unless otherwise noted, dollar amounts refer to US dollars throughout this filing

The date of this filing is July 31, 2006, for the period ended June 30, 2006.

Please refer to the Company's initial Form 51-102F1, filed on May 27, 2004, for further information, which is updated below.

Overall Performance
The Company is engaged in oil and gas exploration in New Zealand and Papua New Guinea. This activity comprises:

- Undertaking geological and geophysical studies, both desk-top and field-based, with the objective of defining targets which can be risk-justified for drilling

- The drilling and evaluation of exploration wells

- The development of and production from any commercially viable discoveries.

The permits and licenses held by the Company are typically large and lightly drilled by North American standards. It is in the normal nature of the business that a portfolio of projects is pursued at any time, and that individual projects may never justify drilling. It is also the nature of the business that a large proportion of such exploration wells that are drilled will be unsuccessful. The Company typically acts as a member of a joint venture group of participants where the joint venture holds an exploration permit or license through a phased work program agreement, entered into with the appropriate regulatory body. In each of New Zealand and Papua New Guinea, the regulatory body is a state agency charged with administering the exploration for hydrocarbons within its jurisdiction on behalf of the state as the owners of the resource. The phased work program consists of a series of work steps, typically on an annual interval, in which the subsequent step is often contingent on the success of the previous step. For example, the commitment to drill a well in the up-coming permit year may be contingent on the success in defining a drilling target by seismic exploration in the previous year. The permit holders will often (but not always) have the right at the end of a work year to continue into the next permit year, or else to freely relinquish their permit rights. In this manner, the work program forms the basis of an agreement between the joint venture.

The Company held cash and short-term deposits amounting to $9.0 million as at June 30, 2006. Cash held by the Company decreased in the quarter by $2.3 million. This was a consequence of meeting operational and overhead commitments. The Company is capable of meeting all its obligatory commitments as at the date of this report.

The Company has incurred a loss for the quarter ended June 30, 2006 of $21,000 and a loss for the year to date of $1.8 million.
Cheal Field

Extended production testing of the Cheal wells ceased in December 2005. This decision was approved by the joint venture in anticipation of the imminent commencement of site and field development. As at the date of this report the field development plan and associated budget has been approved by the joint venture and work has commenced. The first phase in the development concept is an early production facility which will enable limited production of approximately 300 barrels per day (100%), and thereby accelerate associated cash flows. Early production commenced on July 25th, 2006. Workovers of the Cheal wells A3X and A4 to replace steel tubing with chrome will be undertaken to enable access to the producing Mt Messenger interval and to isolate the Urenui interval. Oil will be transported from site by road tanker and associated gas will be used to generate electricity.

A minimum of two further wells are planned from the Cheal A site. Appraisal of the northern portion of the field is planned by drilling the Cheal B1 well from the B site, approximately 1 kilometre north of the Cheal A site; further development wells will ultimately be required from the Cheal B site to fully develop the field.

A hot oil pumping facility has been recommended to cater for field production. This can utilise conventional venturi type jet pumps or hydraulic piston type pumps downhole, both of which operate via the supplied external power fluid. This system has the advantage of reducing the pour point of the produced crude so that it becomes transportable.

The site and permanent associated production and process facilities will be designed to accommodate 2,000 barrels per day of oil production and 2 million cubic feet of gas per day from several wells in parallel production and all driven by jet pump. Sufficient pump and storage capacity is intended to cater for this level of production. The existing onsite gas engine generator can utilise MMCFD per day of associated gas. Excess gas will be exported as it is neither practical not commercially viable to consider on site power generation for the quantities above MMCFD per day that are anticipated.

Several gas pipeline routes are currently under consideration.

Local council consents are currently being progressed through the various legal processes and full production of approximately 1,900 barrels per day (100%) is expected to be achieved early in quarter 2, 2007.

A Petroleum Mining Permit (PMP 38156) covering an area of 30 square kilometres was granted on July 26th, 2006 for an initial term of 10 years. There is a right to extend the term of the mining permit following the delineation of further reserves.

The Company is the operator of the Cheal project on behalf of the joint venture, and owns a 36.5% beneficial interest in the PEP 38738-01 permit, which incorporates all the mapped extent of the Cheal field. A Sproule International Ltd report dated December 31, 2005, estimates Proven Undeveloped Reserves in Cheal at 1.417 million barrels (100%).

A 3D seismic survey over the Cheal and Cardiff structures has been completed and preliminary results are being delivered from the processing centre at the time of writing. The results of the survey will be used to determine the optimum bottomhole locations for both the Cheal development wells and further wells on the Cardiff structure.

Cardiff Project
The Cardiff-2A deep gas well lies within PEP 38738-02. Cardiff-2A was drilled (with one sidetrack) to a depth of 4,931m (16,178 feet), and successfully logged and cased in March 2005.

The joint venture agreed to production-test the three main reservoir intervals within the Kapuni Formation. The three primary test zones are all established producer sandstone
in offsetting wells and fields.

All test zones were hydraulically fractured over May/June 2005. However, during the latter part of the lowest test zone operation, fracturing sand backed up inside the production tubing for approximately 300 metres (1,000 feet). Severe delays in equipment availability prevented the removal of the sand until October. Flow testing commenced in October but, despite an initial clean-out of sands from the lower test zone, the zone blocked again with a viscous oily residue mixed with further 'frac' sand. Initial average test flows of gas (one million cubic feet plus per day) is interpreted to be dominantly from the uppermost test zone, the McKee. The middle zone, the K1A, was interpreted to be flowing water. The well was re-entered with coiled tubing in early November to clear the obstruction above the lowermost test zone. A series of flow and pressure build-up tests on the McKee sandstone formation have indicated an improvement in well productivity. This was reflected in flow rates which have at times exceeded three million cubic feet per day of gas and 100 barrels per day of light oil and condensate. Testing flows indicated that the higher pressure middle zone, the K1A, was not fully isolated from the uppermost zone and water was inhibiting the flow rates from the uppermost zone. An inflatable plug was set late April to isolate the middle and uppermost zone sand further flow testing has been conducted. The results of this set of tests were comparable to those previously obtained.

The bottom zone, the K3E, will be isolated and tested fully as part of the well workover program planned for the 4th quarter of 2006. The joint venture participants anticipate that by the end of the year it will be in a position to begin finalising plans for the optimum concept for field development. Newly acquired 3D seismic will help identify the potential for 'sweet spots' in the reservoir for future production wells.

A Petroleum Mining Permit (PMP 38156) covering an area of 30 square kilometres was granted on July 26th, 2006 for an initial term of 10 years. There is a right to extend the term of the mining permit following the delineation of further reserves.

No reserves have yet been assigned to this property. A Sproule International Ltd report dated April 30, 2005, estimates probabilistic 'resource in place in reservoir' associated with the Cardiff structure within PEP 38738-02 as having 50% (10%) probabilities of exceeding 215 (341) BCF gas plus 12.8 (21.5) million barrels of condensate. These estimates are not reserves, which by definition are quantities deemed economically recoverable to surface. The resource estimates are made at equivalent surface temperature and pressure.
The Company holds a 25.1% share in PEP 38738-02, which includes the mapped extent of the Cardiff field.

Exploration Projects
The Company continues to evaluate its exploration portfolio to identify high impact prospects for drilling. The permit areas that the Company has an interest in contain a number of promising leads and prospects.

A seismic survey within permit PEP38258 (Offshore Canterbury - Company share 75%) commenced early April and has acquired 483 km of 2D data. The data will be processed within the next two months and will be used to further mature the Whaler prospect.

An exploration drilling operation in Papua New Guinea (PPL235) was announced in February 2005. A listed British public company, Rift Oil PLC, committed to fund the first $6M of expenditure on the Douglas-1 well, which will test a large, seismically defined structure in the foreland area of the proven productive Papuan Basin. The joint venture acquired a heli-portable drilling rig which was mobilised from the United States to Papua New Guinea within the quarter. Douglas-1 was spudded on April 4th and was drilled to a depth of 1978m (6430 feet). Primary reservoir targets for the well were the Jurassic aged Alene, Toro and intra Imburu sandstones.

The well reached a total depth of 1978 metres (6340 feet) on Friday 26th May. Wireline logs indicated that the well intersected two gas bearing columns, the first in the Alene sand from 1785 metres to 1789 metres (4 metres gross; 4 metres net) and the second in the Toro sand from 1838 metres to 1855 metres (17 metres gross; 12 metres net). Formation pressure measurements were also recorded.

Forward expenditures for the year 2006 are likely to be dominated by Cheal and Cardiff activities and a seismic program in Papua New Guinea.

Funding and risks
The Company considers it can meet all obligatory work requirements out of existing funds; although it may elect to farm-out portions of certain commitments as part of its ongoing exploration portfolio management.

The Company has earned a small amount of revenue from the sale of Cardiff condensate. The Company will re-commence earning revenue in the third quarter, 2006 as production operations were recommenced utilising temporary production facilities on July 25th at approximately 300 barrels per day (100%).

Production will continue until the permanent production facilities are completed in quarter 1, 2007. Following completion of permanent facilities, the Company expects an initial production rate of approximately 1,000 barrels per day (100%) rising to approximately 1,900 barrels per day (100%) in quarter 2, 2007. Following site redevelopment, significant reductions in operating costs are also expected which will provide the Company with improved net income per barrel.

The Company faces a variety of business risks. The principal ones relate to exploration failure, oil price, exchange rates and the cost and availability of services. If current high oil prices continue the Company will benefit from this following the recommencement of Cheal production. The Company's exploration costs are made principally in both NZ dollars and US dollars. The NZ dollar has appreciated markedly against the US dollar over the last two years, but recently has weakened considerably. Within the quarter the US:NZ exchange rate fluctuated between a high of 0.6442 and a low of 0.5925. The contrarian effects of exchange rate fluctuations on cost of services and on revenues in NZ dollars or as converted to US dollars, provide natural offsets. Exchange rate movements cannot be predicted. The Company maintains the bulk of its cash reserves in US dollars.

Due to the recent high level of oil exploration activity worldwide and in the Company's principal areas of business, exploration services have increased significantly in cost and are in greater demand than previously.

Results of Operations
Update for the Quarter Ended June 30, 2006

The only significant revenue within the quarter was derived from joint venture recoveries and interest which totaled $437,888 for the quarter.

General and administrative expenses were $966,052 for the quarter ended June 30, 2006 compared to $842,332 to the same period in 2005. The increase of $123,720 was primarily attributable to:

- increased salaries as a result of increased resourcing levels required to implement the Company strategy (increase of $99,186);

- increased occupancy and related costs of $20,653 were incurred as a result of relocation of the company's premises and associated costs related to increased staffing levels;

- increased directors fees of $26,228 were incurred reflecting changes in the composition of the Board and to bring director remuneration into line with the market.

Stock compensation expense increased from $19,691 in the June 2005 quarter to $146,155 in the June 2006 quarter. This arose as a result of the share options that were issued to employees and directors over the past 12 months.

For the quarter ended June 30, 2006, the Company incurred a net loss of $21,129 compared to a net loss of $857,559 for the quarter ended June 30, 2005. The decreased loss of $836,430 was primarily attributable to:

- decreased net production (sales less royalties, depletion and production costs) of $171,948 arising from the cessation of test production activities in the Cheal field;

- increased general and administrative expenses of $123,720 as described above;

- increased stock compensation expenses of $126,464 as described above;

offset by;

- increased miscellaneous income of $139,549 from joint venture activities (overhead recoveries) and interest on funds invested;

- decreased impairments of oil and gas properties of $402,566 consistent with the full cost accounting policy. Following the recognition of proved reserves, the Company did not have any impairments relating to unproved properties in New Zealand as the estimated cash flows from the proved property reserves under the full cost ceiling test was sufficient to recover the carrying value of the New Zealand country cost pool;

- decreased exchange loss of $733,476 as the March 2006 exchange loss reversed.

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