Exhibit 99.7
AUSTRAL PACIFIC ENERGY LTD.
STATEMENT OF RESERVES DATA
AND OTHER OIL AND GAS INFORMATION
(FORM 51-101F1)
Effective: December 31, 2008
Date of Statement: March 24, 2009
PART 1. | Date of Statement | 2 |
PART 2 | Disclosure of Reserves Data | 2 |
PART 3. | Pricing Assumptions | 7 |
PART 4. | Reserves Reconciliation | 8 |
PART 5. | Additional Information Relating To Reserves Data | 10 |
Undeveloped Reserves: | 10 | |
Future Development Costs | 10 | |
PART 6. | Other Oil and Gas Information | 10 |
6.1 Oil and Gas Properties and Wells | 10 | |
6.2 Properties with No Attributed Reserves | 12 | |
6.3 Forward Contracts | 12 | |
6.4 Additional Information Concerning Abandonment and Reclamation Costs | 13 | |
6.5 Tax Horizon | 13 | |
6.6 Costs Incurred | 13 | |
6.7 Exploration and Development Activities | 14 | |
6.8 Production Estimates 2009 | 14 | |
6.9 Production History | 15 |
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PART 1. Date of Statement
The effective date of the information being provided in this statement is as at December 31, 2008, and for the year ended December 31, 2008. The preparation date of the information being provided in this statement is March 24, 2009.
References to oil, gas, natural gas liquids, reserves (gross, net, proved, developed, developed producing, developed non-producing, undeveloped), forecast prices and costs, constant prices and costs, operating, costs, development costs, future net revenue and future income tax expenses shall, unless expressly stated to be to the contrary, have the meaning attributed to such terms as set out in the National Instrument 51-101, Companion Policy 51-101CP and all forms referenced.
All dollar figures are United States Dollars.
PART 2. Disclosure of Reserves Data
Austral Pacific Energy Ltd. and its subsidiaries (the “Company”) have one property with reserves, situated in onshore New Zealand, and the oil and natural gas reserves and net present values of future net revenue of that property were evaluated by Sproule International Limited (“Sproule”), an independent qualified reserves evaluator appointed by the Company.
The following tables, based on Sproule’s report, show the estimated share of the Company’s crude oil and natural gas reserves in its property and the net present value of estimated future net revenue for these reserves, using constant prices and costs as indicated. All evaluations of the present value of estimated future net revenue in the Sproule Report are stated after provision for estimated future capital expenditures, but prior to income taxes and indirect costs and do not necessarily represent the fair market value of the reserves. The recovery and reserve estimates of the Company’s oil and natural gas reserves stated here are estimates only and there is no guarantee that the estimated reserves will be recovered. Actual reserves may be greater than or less than the estimates stated here. Readers should note that the totals in the following tables may not add due to rounding.
Possible reserves are those additional reserves that are less certain to be recovered than probable reserves. There is a 10% probability that the quantities actually received will equal or exceed the sum of proved plus probable plus possible reserves.
The Company has adopted the standard measure of 6 mcf:1 boe when converting natural gas to barrels of oil equivalent. Boe’s may be misleading, particularly if used in isolation. A boe conversion ratio of 6 mcf:1 boe is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.
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Table 1 | ||||||||||||||||
NI 51-101 | ||||||||||||||||
Summary of Oil and Gas Reserves | ||||||||||||||||
As of December 31, 2008 | ||||||||||||||||
Forecast Prices and Costs | ||||||||||||||||
Reserves | ||||||||||||||||
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| Natural Gas |
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| Light and Medium Oil | Heavy Oil | Coalbed Methane | (non-associated & associated) | Natural Gas (solution) | Natural Gas Liquids | ||||||||||
Reserve | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | ||||
Category | (Mbbl) | (Mbbl) | (Mbbl) | (Mbbl) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (MMcf) | (Mbbl) | (Mbbl) | ||||
Developed |
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Producing | 128 | 121 |
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Total Proved | 128 | 121 |
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Probable | 222 | 211 |
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| 248 | 231 |
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Total 2P | 350 | 332 |
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| 248 | 231 |
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Possible | 283 | 254 |
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| 234 | 208 |
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Total 3P | 633 | 586 |
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| 482 | 439 |
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Table 2 | |||||||||||||||||
NI 51-101 | |||||||||||||||||
Summary of Net Present Values of | |||||||||||||||||
Future Net Revenue | |||||||||||||||||
As of December 31, 2008 | |||||||||||||||||
Forecast Prices and Costs | |||||||||||||||||
Net Present Values of Future Net Revenue | |||||||||||||||||
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| Unit Value Before | ||||||||||||||
| Before Income Taxes Discounted at (% /Year) | After Income Taxes Discounted at (% /Year) | Income Tax | ||||||||||||||
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| Discounted at | ||||||||||||||
Reserves Category |
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| (10% /Year) | ||||||||||||||
(M$US) | (M$US) |
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0 | 5 | 10 | 15 | 20 | 0 | 5 | 10 | 15 | 20 |
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| (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | (M$) | $/BOE | ||||||
Proved | 2,882 | 2,809 | 2,741 | 2,678 | 2,619 | 2,882 | 2,809 | 2,741 | 2,678 | 2,619 | 22.65 | ||||||
Total Proved | 2,882 | 2,809 | 2,741 | 2,678 | 2,619 | 2,882 | 2,809 | 2,741 | 2,678 | 2,619 | 22.65 | ||||||
Probable | 6,998 | 6,503 | 6,066 | 5,676 | 5,327 | 6,998 | 6,503 | 6,066 | 5,676 | 5,327 | 24.31 | ||||||
Total Proved plus |
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Probable | 9,880 | 9,312 | 8,807 | 8,354 | 7,946 | 9,880 | 9,312 | 8,807 | 8,354 | 7,946 | 23.77 | ||||||
Possible | 12,376 | 11,218 | 10,224 | 9,368 | 8,623 | 12,376 | 11,218 | 10,224 | 9,368 | 8,623 | 35.42 | ||||||
Total, Proved plus |
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Probable plus Possible | 22,256 | 20,530 | 19,031 | 17,722 | 16,569 | 22,256 | 20,530 | 19,031 | 17,722 | 16,569 | 28.87 |
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Table 3 NI 51-101 Total Future Net Revenue (Undiscounted) As ofDecember 31, 2008 Forecast Prices and Costs | ||||||||
Reserves Category | Revenue (M$) | Royalties (M$) | Opera-ting Costs (M$) | Develop-ment Costs (M$) | Well Abandon-ment Costs (M$) | Future Net Revenue Before Income Taxes (M$) | Income Taxes (M$) | Future Net Revenue After Income Taxes (M$) |
Proved | 7,766 | 388 | 3,730 | 0 | 766 | 2,882 | 2,882 | |
Proved Plus Probable | 23,152 | 1,158 | 8,098 | 3,096 | 920 | 9,880 | 0 | 9,880 |
Proved Plus Probable Plus Possible | 44,035 | 3,409 | 11,267 | 5,885 | 1,219 | 22,256 | 0 | 22,256 |
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Table 4 | |||||
NI 51-101 | |||||
Net Present Value of Future Net Revenue | |||||
By Production Group As of December 31, 2008 Forecast Prices and costs | |||||
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| Future Net Revenue | Unit Value | ||
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| Before Income Taxes | Before Income Taxes | ||
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| Discounted at | Discounted at | ||
Reserves Category | Production Group | 10%/Year (M$) | 10%/Year $/BOE | ||
Proved | Light and Medium Crude Oil (including |
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| solution gas and associated by-products) | 2,741 | 22.65 | ||
| Heavy Oil (including solution gas and |
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| associated by-products) |
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| Coalbed Methane |
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| Natural Gas (including associated |
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| by-products) |
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Proved Plus | Light and Medium Crude Oil (including |
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Probable | solution gas and associated by-products) | 8,807 | 23.77 | ||
| Heavy Oil (including solution gas and |
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| associated by-products) |
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| Coalbed Methane |
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| Natural Gas (including associated |
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| by-products) |
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Proved Plus | Light and Medium Crude Oil (including |
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Probable Plus | solution gas and associated by-products) | 19,031 | 28.87 | ||
Possible | Heavy Oil (including solution gas and |
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| associated by-products) |
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| Coalbed Methane |
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| Natural Gas (including associated |
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| by-products) |
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PART 3. Pricing Assumptions
Forecast benchmark reference price and inflation rate assumptions are summarised in Table 5. This summary table identifies benchmark reference oil pricing schedules that might apply to areporting issuer. Product sale prices will reflect these reference prices with further adjustments for quality and transportation to point of sale. These prices and pricing assumptions were provided to the Company by its independent reserves evaluators, Sproule International Ltd.
Table 5 NI 51-101 Summary of Pricing and Inflation Rates Assumptions as of December 31, 2008 Forecast Prices and Costs | ||||
Year | TAPIS Malaysia ($US/bbl) | Cheal Natural Gas ($US/Mcf) | Inflation Rate1 (%/Yr) | |
Historical |
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2006 | 70.12 |
| 1.5 | |
2007 | 77.26 |
| 2 | |
2008 | 104.61 |
| 2 | |
Forecast
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2009 | 57.73 | 1.45 | 2 | |
2010 | 67.49 | 1.45 | 2 | |
2011 | 73.69 | 1.45 | 2 | |
2012 | 83.84 | 1.45 | 2 | |
2013 | 96.34 | 1.45 | 2 | |
2014 | 98.26 | 1.45 | 2 | |
2015 | 100.23 | 1.45 | 2 | |
2016 | 102.23 | 1.45 | 2 | |
2017 | 104.28 | 1.45 | 2 | |
2018 | 106.36 | 1.45 | 2 | |
2019 | 108.49 | 1.45 | 2 | |
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| Escalation rate of 2.0% thereafter |
(1) Inflation rates for forecasting prices and costs.
For the financial year ended December 31, 2008, the Company’s weighted average price received for oil was $97.11 per barrel.
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PART 4. Reserves Reconciliation
All changes are for reserves in the Cheal Oil Field, located in New Zealand, estimated using forecast prices and costs.
Light & Medium Oil | December 31, 2007 | December 31, 2008 | Change |
Gross proved | 946 Mbbl | 128 | -818 Mbbl |
Gross probable | 786 Mbbl | 222 | -564 Mbbl |
Gross proved plus probable | 1,732 Mbbl | 350 | -1,382 Mbbl |
Additional Solution Gas |
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Gross proved | 840 MMcf | 0 | -840 MMcf |
Gross probable | 888 MMcf | 248 | -640 MMcf |
Gross proved plus probable | 1728 MMcf | 248 | -1,480 MMcf |
The changes to the reserves estimates can be attributed to those factors set out in Table 6. The majority of changes are attributed to technical revisions. These revisions were driven by a number of factors including reduced forward-looking oil price assumptions; lower oil volumes due to the reduced thickness of the oil bearing reservoir encountered in the Cheal-A6 well in June 2008; and a more conservative recovery factor based on the existing well performance over the past 12 months:
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Table 6 | |||||||||||||||
NI 51-101 | |||||||||||||||
Reconciliation of Company Gross(1)Reserves (Before Royalty) | |||||||||||||||
by Principal Product Type | |||||||||||||||
As of December 31, 2008 | |||||||||||||||
Forecast Prices and Costs1 | |||||||||||||||
Factors | Light and Medium Oil | Heavy Oil & Coal Bed Methane & Natural Gas Liquids & Associated and Non-Associated Gas | Natural Gas Solution | ||||||||||||
Gross Proved e (Mbbl) | Gross Probabl (Mbbl) | Gross Proved Plus Probable (Mbbl) | Gross Possible (Mbbl) | Gross Proved Plus Probable Plus Possible (Mbbl) | Gross Proved (MBOE) | Gross Probable (MBOE) | Gross Proved Plus Probable (MBOE) | Gross Possible (MBOE) | Gross Proved Plus Probable Plus Possible (MBOE) | Gross Proved (MMcf) | Gross Probable (MMcf | Gross Proved Plus Probable (MMcf) | Gross Possible (MMcf) | GrossProved Plus Probable Plus Possible (MMcf) | |
31-Dec-07 | 946 | 786 | 1,732 | 715 | 2,447 | - | - | - | - | - | 840 | 888 | 1,728 | 949 | 2,677 |
Extensions | - | - | - | - | - | - | - | - | - | - | - | - | - | - | - |
Improved | |||||||||||||||
Recovery | - | - | - | - | - | - | - | - | - | - | - | - | - | - | - |
Technical | -698 | - 564 | -1,262 | - 432 | -1,694 | - | - | - | - | - | -736 | -640 | -1,376 | -715 | -2,091 |
Revisions | |||||||||||||||
Discoveries | - | - | - | - | - | - | - | - | - | - | - | - | - | - | - |
Acquisitions | - | - | - | - | - | - | - | - | - | - | - | - | - | - | - |
Dispositions | - | - | - | - | - | - | - | - | - | - | - | - | - | - | - |
Economic Factors | - | - | - | - | - | - | - | - | - | - | - | - | - | - | - |
Production | -120 | - | -120 | - | -120 | - | - | - | - | - | -104 | - | -104 | - | -104 |
31-Dec-08 | 128 | 222 | 350 | 283 | 633 | - | - | - | - | - | - | 248 | 248 | 234 | 482 |
(1) Gross Reserves means the Company’s working interest reserves before calculation of royalties, and before consideration of the Company’s royalty interests.
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PART 5. Additional Information Relating To Reserves Data
Undeveloped Reserves:
All the Company’s proved and probable undeveloped reserves are currently located in the Cheal Oil Field. The Company previously had undeveloped reserves located in the Kahili Field. Both fields are located in New Zealand.
Gross undeveloped reserves were first attributed to the Company as follows:
Product Type | Light & Medium Oil (Mbbls) | |
Reserves Category | Proved Undeveloped | Probable Undeveloped |
Prior to Jan 1, 2006 | 818 | 1105 |
December 31, 2006 | 1037 | 785 |
December 31, 2007 | 360 | 1 |
December 31, 2008 | 0 | 0 |
Undeveloped reserves are attributed on the basis of an independent evaluation by Sproule International Limited. Sproule is an independent consultancy engaged by the Company to evaluate the oil and gas reserves of the Company’s interest.
In 2008, no new proved undeveloped reserves were attributed to the Company. The Company plans to incrementally increase reserves by undertaking fracture stimulation and drilling of some 2 additional production wells, in 2009 and later. At the date of this report, there is no Company or Joint Venture approval for these activities nor agreed budgets.
Future Development Costs
Development costs deducted in estimating future net revenue attributable to reserves as disclosed in Item 2 are as follows:
New Zealand only:
Reserves Category | Proved | Proved plus Probable |
2009 | 0 | $3.1m |
2010 | - | - |
2011 | - | - |
2012 | - | - |
2013 | - | - |
Total | 0 | 3.1m |
The Company expects development costs to be funded by production revenues and equity financing activities scheduled for 2009. The costs of this funding will not have a material effect on the disclosed reserves or future net revenue, except as to expected production. Debt re-structuring activities are underway to ensure that Cheal production and development remain economic.
PART 6. Other Oil and Gas Information
6.1 Oil and Gas Properties and Wells
The Company’s only property with attributed reserves is the Cheal Oil Field, located in onshore New Zealand.
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The development of the Cheal Oil Field was approved by the Joint Venture participants in 2006. A mining permit (PMP 38156) covering the Cheal Oil Field was granted on July 26, 2006 for an initial term of 10 years. There is a right to extend the term of the mining permit following delineation of further reserves. Development of the Cheal Oil Field commenced from August 2006 following approval of the development plan, and grant of the mining permit.
Development of the northern portion of the field also commenced in Q4 2006 from a second site, Cheal B, located approximately a kilometre to the north of the original Cheal (A) site, with four wells (Cheal-B1, B2, B3 and B4) having been drilled by end 2006, three of which were completed as producers in early 2007.
The fourth well, Cheal B4, was an exploration well targeting Moki, Mt Messenger and Urenui sandstones to the north west of the field’s bounding fault. The well confirmed the presence of hydrocarbon charge outside the currently recognised limits of the field at the Mt Messenger and Urenui levels, increasing confidence in the resource potential of the north western extension of the Cheal Oil Field. The lower portion of the well was abandoned, with the upper level suspended, pending a sidetrack planned to be drilled in 2009. If successful, this well could be produced through existing facilities. During 2008, the Company drilled three new wells. The A6 well and a subsequent sidetrack to the south (A6ST) encountered oil-bearing sands of insufficient thickness to be commercially produced. The A7 well, drilled to the north and east of A6, did encounter commercially viable Mt. Messenger sandstones and was completed with temporary tie-in facilities. Producti on from Cheal-A7 commenced in August 2008. Permanent facilities are under construction and are anticipated to be completed by mid-2009.
Construction of the Cheal Production Facilities commenced in Q3 2006. The production facilities have an initial design capacity of 2,000 barrels of oil per day and 3 million cubic feet of gas per day, for up to ten development wells. They are located at the Cheal A site, receiving, processing and handling raw production from both the existing Cheal A site and from Cheal B. Engineering optimisation and design of the facilities allow capacity to be increased in the future should this be required. Construction was completed in Q3 2007. The pre-commissioning test phase commenced on August 10, 2007 and first oil was produced through the facilities in September 2007. The facilities are now fully certified and were formally opened on October 8, 2007.
Cheal-B1, B2 and B3 were brought into production through the Cheal production facility in December 2007 following the completion of the tie-ins to the pipelines connecting the Cheal B site with the Production Facilities at the Cheal A site. Most of the plant at the new production facility was designed specifically to deal effectively and efficiently with the particular nature of the hydrocarbons being produced.
Solution gas produced in association with Cheal crude oil production is used to generate electricity for on-site use, with the excess electricity initially being sold into the national electricity grid. The export of excess gas via a pipeline to the Waihapa Production Station commenced in December 2007, for treatment and on-sale. However, in July 2008, the operator of the Waihapa Production Station (Origin Energy) suspended operation of the station, due to inadequate supplies of gas to the facility from other sources. In Q4 2008, Origin terminated the gas handling contract with the Company. Contact Energy has proposed an option to purchase Cheal gas for re-injection into one of Contact’s existing reservoirs. Austral and Contact are working together to formalize an agreement. Currently, all gas produced is consumed by electricity generation for on-site use and export. Revenue from this source is minimal.
Summary of oil and gas wells in the Company’s material properties (all in New Zealand) are:
| Gross | Net |
OIL |
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Producing | 7* | 4.9* |
Non-Producing | 4 | 2.8 |
GAS |
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Producing | 0 | 0 |
Non-Producing | 2 | 1.3 |
* All producing wells are in the Cheal Field and also produce solution gas.
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6.2 Properties with No Attributed Reserves
All but one of the Company’s properties are located in onshore New Zealand. The D’Urville (PEP 38524) interest is located near offshore. Unproved properties material to the Company with no attributed reserves are:
Kahili (PMP 38153) Onshore, Taranaki, New Zealand (1,480 acres gross, 1,258 acres net)
Production from the Kahili Field has been suspended since November 2004. In July 2005, the government approved the cessation of production from the field.
During 2008, that consent to cease production under the mining permit was revoked and the joint venture was required to submit a work programme to re-commence production. The joint venture considered that the Kahili Field contains considerable up dip potential which could be tested by the drilling of a new well, Kahili-2, placed higher on the mapped structure. The drilling of the well was subject to a successful farm-out being negotiated which would be sufficient to fund the drilling operation.
Subsequent to year-end, farm-out negotiations were terminated without an agreement being reached. As a consequence, the joint venture parties have surrendered the permit with effect from March 6, 2009.
The Company held an 85 percent interest in the Kahili joint venture and was the operator.
Cardiff (PMP 38156) Onshore, Taranaki, New Zealand (7,487 acres gross, 3,362 acres net)
During 2005, the Cardiff-2A well was deviated out of the Cardiff-2 (Dec 2004) borehole, and drilled (with one sidetrack). Three test zones within the Kapuni Formation were perforated and hydraulically fractured . A series of flow and pressure build-up tests in 2006 indicated an improvement in well productivity. This was reflected in flow rates which at times exceeded three million cubic feet per day of gas and 100 barrels per day of light oil and condensate. A mining permit (PMP 38156) was granted over the Cheal and Cardiff fields in July 2006.
The Cardiff-2A ST1 well was worked over during November and December 2007, additional wireline work was completed on the well in January 2008, with flow testing of the K3E zone commencing in late February 2008. Results of the flow test were inconclusive and further operations were suspended pending a full field evaluation.
The conditions of PMP 38156 initially required production to commence from the Cardiff Field by July 2008. In light of the inconclusive flow test results from the K3E, application has been made for a change of conditions of the permit, to remove the requirement to commence production from the Cardiff field.
On 8 January 2008, the Company entered into an agreement to purchase from Genesis Energy an additional 5.1% of the Cardiff joint venture, contingent upon Genesis completing the purchase of another participant’s 15.1% interest in the Cardiff joint venture. That condition was satisfied only in February 2009. Accordingly the Company’s interest will increase by a further 5.1%, after report date.
No reserves have yet been assigned to this property. The Company is the operator of the Cardiff joint venture.
Expiration within one year
The net area of unproved property for which the Company expected its rights to explore, develop and exploit to expire within one year, as at December 31, 2008, was nil.
As at the date of this report, 1,258 acres (net) has expired by surrender of the Kahili (PMP 38153) permit on March 6, 2009. Based on the Company’s forward plan, other permits may be surrendered rather than it committing to further work programmes (see further discussion in the Company’s annual Management Discussion & Analysis filed on SEDAR atwww.sedar.com).
6.3 Forward Contracts
As at December 31, 2008, the Company was party to two gas contracts, which may preclude full realisation, and may protect from the full effect, of future market prices:
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(a)
On 2 April 2003 the Company entered into a gas prepayment agreement with a New Zealand company, under which the Company received NZ$2 million ($1.438 million) to fund its ongoing exploration programmes. The Company is required to deliver NZ$2 million ($1.438 million) of gas under gas sales contracts to be negotiated at the then prevailing market rate.
(b)
A gas supply agreement for all gas available for sale from the deep formations of PEP 38738 and PMP 38156. The agreement requires notice to be given when gas becomes available for sale and the estimated quantities available. Genesis Power Limited must give notice within a certain time period of the amount (if any) it wishes to purchase, and the nominated purchase period. The price is specified as a base price (as at March 31, 2004) plus price index adjustments. Any gas not accepted by Genesis Power Limited is available for sale to third parties.
6.4 Additional Information Concerning Abandonment and Reclamation Costs
The Company’s abandonment and reclamation costs are calculated by estimating the costs to fulfil the current obligations using current techniques in regard to wells that are producing, under appraisal or pending development.
At December 31, 2008, the Company was party to joint ventures that have an obligation to “plug and abandon” a total of 12 (gross; 8 net) wells at the end of their useful life. The present value of these obligations has been projected based on an estimated future liability of $2.27 million discounted using credit adjusted risk-free rates of 17 percent. The costs are expected to be incurred between 2009 and 2012.
$1.06 million (47%) of these costs do not relate to the Cheal Oil Field and therefore was not included in Table 3 and in the calculations underlying the data disclosed in Item 2. All of these non-Cheal costs are expected to be payable within the three following fiscal years (2009 to 2011). Cheal costs are forecast to be payable in 2012.
6.5 Tax Horizon
The Company currently estimates that income taxes are unlikely to become payable before 2015, subject to current assumptions of production levels and commodity prices.
6.6 Costs Incurred
In the year ending December 31, 2008, the Company made the following expenditures (whether capitalised or charged to expense):
Country | New Zealand | Papua New Guinea* |
Property Acquisition Costs – Proved properties | - | - |
Property Acquisition Costs – Unproved properties | - | - |
Exploration Costs | $2.4 million | $0.23 million |
Development Costs | $6.06 million | - |
* All Papua New Guinea interests were disposed of during fiscal 2008.
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6.7 Exploration and Development Activities
During fiscal 2008, the Company completed the following wells in New Zealand:
| Gross | Net |
Exploratory Wells completed for: |
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Oil | 1 | 0.70 |
Gas | - | - |
Service | - | - |
Dry hole | 2 | 1.39 |
Development Wells completed for: |
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Oil | - | - |
Gas | - | - |
Service | - | - |
Dry hole | - | - |
New Zealand
The Company is currently reviewing operating expenditure in, and implementing cost reduction measures for, production of the Cheal Field (PMP 38156). Permanent facilities to tie-in Cheal A7 (drilled July 2008) are currently being constructed, and are expected to be completed in mid-2009. The Company plans to implement fracture stimulation operations during 2009, to improve production recovery from currently producing Cheal wells.
The Company is reducing all other exploratory spending, and therefore permits other than the Cheal permit are being monetized through an orderly sales process.
Some programmes noted have not yet received joint venture or governmental approval and may not necessarily proceed. Also, depending upon the outcomes of some of these programmes, different decisions may be reached to vary work programmes, modify or abandon them altogether.
Papua New Guinea
The Company sold its interests in Papua New Guinea in Q2 2008.
6.8 Production Estimates 2009
Estimated production volumes for fiscal 2009 are derived from gross proved reserves and gross probable reserves disclosed under Item 2. Figures quoted are net to the Company.
New Zealand: Cheal Field
Product Type | Gross Proved (bbls) | Gross Probable (bbls) |
Light and medium oil | 125,268 | 102,309 |
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6.9 Production History
The Company’s historical production and netback data for the period ended December 31, 2008 is presented below:
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| Light and Medium Oil |
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| Q1 | Q2 | Q3 | Q4 | Total Year |
New Zealand |
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Company share of daily |
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production (bbl/day) |
| 382.98 | 326.97 | 283.16 | 321.91 | 328.46 | |
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Average ($/bbl) |
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| Price received | $98.66 | $142.09 | $106.10 | $42.19 | $97.11 | |
| Royalties |
| $(4.35) | $(6.60) | $(4.53) | $(1.96) | $(3.24) |
| Production costs | $(15.21) | $(39.46) | $(51.37) | $(23.43) | $(31.12) | |
| Netback |
| $79.10 | $96.03 | $50.20 | $16.80 | $62.75 |
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Company share of 2008 production - bbls |
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| 119,890 | |||
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Important fields (greater than 20% of total): |
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Cheal field |
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| 119,890 | |
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The Company has not had any significant gas production since November 2004 when the Kahili-1B well ceased production. Gas production in 2008 was solely solution gas produced in association with oil from the Cheal field. Approximately two-thirds of Cheal solution gas was sold under contract, until July 2008 when the gas handling facilities available to the Joint Venture were shut-in. Gas sales during 2008 amounted to $203,470 from the Cheal field, at approximately 250 mscf per day (Company share) until July 2008. The remainder of the gas was used for own use (electricity generation on-site) with surplus electricity exported to the national electricity grid system. Gas is now being used solely for on-site electricity use and electricity export.
Austral Pacific Energy Ltd.
Level 3, 40 Johnston Street, Wellington 6011, New Zealand
PO Box 5337, Lambton Quay, Wellington 6145, New Zealand
Phone: (644) 495 0888; Facsimile: (644) 495 0889;
Contact: Thompson Jewell, CEO
Website: www.austral-pacific.com
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