EXHIBIT 99.1
AUSTRAL PACIFIC ENERGY LTD.
Annual Information Form
Fiscal Year Ended 31 December 2007
Dated March 28, 2008
TABLE OF CONTENTS
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Austral Pacific Energy Ltd. conducts its operations directly and through subsidiaries. The term “Austral” or “the Company” as used in this Form refers, unless the context otherwise requires, to Austral Pacific Energy Ltd. and its consolidated subsidiaries.
Unless otherwise indicated, references in this Form to “$” or dollars are to United States dollars. Where currency conversions are required the following rates have been used:
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| As at December 31, |
| Average for the year ended |
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US dollars to Canadian dollars |
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| 0.9810 |
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| 1.0659 |
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US dollars to New Zealand dollars |
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| 1.2900 |
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| 1.3483 |
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| Oil and Natural Gas Liquids |
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| Natural Gas |
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Bbl |
| Barrel |
| Bcf |
| billion cubic feet |
Bbls |
| Barrels |
| GJ |
| Gigajoule |
Boe |
| Barrels of oil equivalent (see note below) |
| Mcf |
| thousand cubic feet |
Bpd |
| barrels per day |
| Mmcf |
| million cubic feet |
Mbs |
| thousand barrels |
| Mcf/d |
| thousand cubic feet per day |
MMbs |
| million barrels |
| MMcf/d |
| million cubic feet per day |
MMstb |
| million stock tank barrels |
| MMBTU |
| million British Thermal Units |
Mstb |
| 1,000 stock tank barrels |
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NGLs |
| natural gas liquids |
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Other
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AMEX |
| American Stock Exchange |
NZSX |
| New Zealand Stock Exchange |
PEP |
| Petroleum Exploration Permit, as issued by the New Zealand government |
PMP |
| Petroleum Mining Permit, as issued by the New Zealand government |
PPL |
| Petroleum Prospecting Licence, as issued by the Papua New Guinea government |
PRL |
| Petroleum Retention Licence, as issued by the Papua New Guinea government |
TD |
| target depth |
TSX-V |
| TSX Venture Exchange |
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To Convert From |
| To |
| Multiply By |
Mcf |
| Cubic metres |
| 28.174 |
Cubic metres (m3) |
| Cubic feet |
| 35.494 |
Bbls |
| Cubic metres |
| 0.159 |
Cubic metres (m3) |
| Bbls oil |
| 6.290 |
Feet |
| Metres |
| 0.305 |
Metres (m) |
| Feet |
| 3.281 |
Miles |
| Kilometres |
| 1.609 |
Kilometres (km) |
| Miles |
| 0.621 |
Square kilometres (km2) |
| Acres |
| 247.105 |
Acres |
| Hectares |
| 0.405 |
Acres |
| Square kilometres |
| 0.004 |
Hectares |
| Acres |
| 2.471 |
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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SPECIAL NOTE REGARDING FORWARD-LOOKING STATEMENTS
This Annual Information Form includes statements that may be deemed to be “forward-looking statements” within the meaning of applicable legislation. Other than statements of historical fact, all statements in this Form addressing future production, reserve potential, exploration and development activities and other contingencies are forward-looking statements. Although management believes that the expectations expressed in such forward-looking statements are based on reasonable assumptions, such statements are not guarantees of future performance, and actual results or developments may differ materially from those in the forward-looking statements, due to factors such as market prices, exploration and development successes, continued availability of capital and financing, and general economic, market, political or business conditions, including, but not limited to, the risks and uncertainties identified under the subheading “Risk Factors” in this Form.
PRESENTATION OF OIL AND GAS RESERVES AND PRODUCTION INFORMATION
All oil and natural gas reserve information contained in this Annual Information Form has been prepared and presented in accordance with National Instrument 51-101 Standard of Disclosure for Oil and Gas Activities (“NI 51-101”). The actual oil and natural gas reserves and future production will be greater than or less than the estimates provided in this Annual Information Form. The estimated future net revenue from the production of the disclosed oil and natural gas reserves does not represent the fair market value of these reserves.
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Incorporation and Organisation
The Company’s legal and commercial name is Austral Pacific Energy Ltd. It changed its legal name to “Austral Pacific Energy Ltd.” from “Indo-Pacific Energy Ltd.”, on December 31, 2003.
The Company is legally domiciled in British Columbia, Canada, and now operates as a corporation under the Business Corporations Act (British Columbia) of 2004. The Company was incorporated on July 31, 1979 under the name Pryme Energy Resources Ltd. under the Company Act (British Columbia, Canada), and has operated continuously since that time. The Company was continued out of British Columbia into the jurisdiction of the Yukon in Canada on September 25, 1997, and operated under the Business Corporations Act (Yukon) until October 16, 2006 when it was continued into British Columbia.
The continuation to British Columbia included the adoption of new Articles of the Company, as approved by the shareholders at the annual and special meeting held on May 2, 2006. Notice of Articles was filed with the British Columbia Registrar of Companies in September 2006, and such Articles are the primary charter document of the Company. The differences between the Company’s Bylaws under Yukon law, and the new Articles were set out in the Management Proxy Circular distributed in relation to the shareholders’ meeting noted above. Both the Circular and the Company’s new Articles are incorporated reference into this Annual Information Form and have been filed on and are available for download fromwww.sedar.com.
The Company’s registered office in the province of British Columbia is care of its British Columbia attorneys:
Lang Michener LLP
1500 Royal Centre, 1055 West Georgia Street
Vancouver, V6E 4N7
CANADA
The Company’s principal business offices are at:
Level 3, 40 Johnston Street
Wellington 6011
NEW ZEALAND
Telephone Number: (644) 495 0888
Intercorporate Relationships
The Company is the parent company of and conducts all its operations through the following material subsidiaries:
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Subsidiary Companies |
| Jurisdiction of |
| Business of |
| % Ownership & |
Source Rock Holdings |
| New Zealand |
| Holding company |
| 100% |
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Austral Pacific Energy |
| New Zealand |
| Oil and gas exploration |
| 100% |
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Millennium Oil & Gas |
| New Zealand |
| Oil and gas exploration |
| 100% |
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Rata Energy Limited |
| New Zealand |
| Oil and gas exploration |
| 100% |
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Totara Energy Limited(3) |
| New Zealand |
| Oil and gas exploration |
| 100% |
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Titoki Energy Limited(1) |
| New Zealand |
| Oil and gas exploration |
| 100% |
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Subsidiary Companies |
| Jurisdiction of |
| Business of |
| % Ownership & |
Puka Energy Limited(2) |
| New Zealand |
| Oil and gas exploration |
| 100% |
Hebe Energy Limited(2) |
| New Zealand |
| Oil and gas exploration |
| 100% |
Matai Energy Limited(2) |
| New Zealand |
| Oil and gas exploration |
| 100% |
Austral Pacific Energy |
| Papua New Guinea |
| Oil and gas exploration |
| 100% |
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(1) | Acquisition completed November 12, 2007. Name changed from International Resource Management Corporation Limited on November 20, 2007. |
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(2) | These companies were incorporated in March 2007 and later received assignment of various permit interests from Austral Pacific Energy (NZ) Limited. Their names were changed from Austral Pacific NZ No.1 Limited, Austral Pacific NZ No.2 Limited and Austral Pacific NZ No.3 Limited respectively, in June 2007. |
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(3) | Three subsidiaries of Austral Pacific Energy (NZ) Limited (Kanuka Energy Limited, Arrowhead Energy Limited and Totara Energy Limited) were amalgamated into one company called Totara Energy Limited, with effect from February 1, 2008. |
GENERAL DEVELOPMENT OF THE BUSINESS
Austral Pacific Energy Ltd., through its subsidiaries, is actively involved in the exploration for, and development and production of, oil and natural gas, and the acquisition of further interests in licences or permits, in New Zealand and Papua New Guinea.
The Company achieved a small amount of gas and condensate production from the Kahili discovery in 2004, however all Kahili reserves were written off in 2004. In 2005 the Company recognised proved reserves in respect to the Cheal oil field discovery, based on an independent assessment by Sproule International Limited. The April 2005 Sproule report also summarized the resource potential of the Cardiff structure, but as hydrocarbons had not at that time, nor as at December 31, 2007, been flow-tested from Cardiff-2A in a controlled and sustained manner, no reserves have been assigned to Cardiff.
Kahili Field
In the Company’s New Zealand permit PEP 38736, the Kahili-1B sidetrack well, drilled in November 2002, encountered a 115 feet gross hydrocarbon column in the Tariki sandstone in the onshore Taranaki Basin, New Zealand. Analysis of pressure data from flow testing carried out on the uppermost 50 feet of this zone indicates sufficient gas-condensate reserves to justify development. A review of the development options available was completed during 2003.
In April 2003, a gas prepayment agreement was entered into with a New Zealand company, NGC New Zealand Limited (NGC, now called Vector), whereby NGC provided $1,050,400 towards the Company’s ongoing exploration programs. In return, NGC was to receive the first $1,050,400 of gas supplied by the Company to NGC without payment, under contracts to be negotiated at then prevailing market rates. The Company must negotiate in the first instance with NGC, and if no contract is entered into within a certain time period after notification, the Company is free to seek other markets for the gas. If the amount is not discharged through gas sales to NGC over a ten year period, it must either be repaid by the Company or may be converted into share equity in one of the Company’s New Zealand subsidiaries.
In January 2004, a gas sales agreement was signed with NGC for the Kahili gas-condensate field (now held under mining permit PMP 38153). NGC constructed, owned and operated a separation plant to process the raw well stream. NGC also installed 12 km of pipelines to connect Kahili gas to the existing NGC pipeline infrastructure. The Kahili field was commissioned in August 2004. After initial flow, production declined rapidly, and the well was shut-in during November 2004. A different well performance to that recorded in the May 2003 production test (on which field development was based) is still not understood; but it is unlikely this well will produce again. The field reserve estimate and financial statement value has been written down to zero, following an independent assessment. However, a Kahili-2 well placed higher on the mapped structure is being considered by the joint venture parties, and is planned to be drilled in Q2, 2008. This may re-establish production from the field.
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Cheal Field
PEP38738 was acquired by the Company in October 2002, in return for the grant of a 25% net profit royalty. During 2003, the Company purchased the net profit royalties back, through its acquisition of all the permit interests of an Australian company, Horizon Oil NL, in several onshore Taranaki (New Zealand) permits and all of the shares in Totara Energy Limited (formerly Bligh Oil & Minerals NZ Limited), which company owned the royalty interests in PEP 38738. The permits acquired were additional interests in permits already held by the Company, together with a 10% interest in PEP 38718.
In May 2003, the participants re-entered the Cheal-1 well, originally drilled in 1995, which had tested oil and gas from a shallow secondary target. A test of the Cheal-1 well in July 2003 flowed gas at rates up to 4.5 mmscfd in a one day test period. Suitable production test equipment was then installed and extended flow testing commenced in October 2005, in order to establish developable reserves. However, oil reserves could not be estimated conventionally, despite steady oil production during the test.
Cheal-A3X was drilled in May 2004 to test the Mt Messenger sands beneath the shallower Urenui oil/gas pay previously discovered in Cheal-1 & -2. This well discovered oil pay sands over a gross interval of ~60m (~200 feet) within the Mt Messenger formation. A flow-test of both the Urenui and the deeper Mt Messenger sandstones commenced in June 2004. Cheal-A4 was deviated from the Cheal-A site during October 2004 and Mt Messenger oil pay was again intersected. Extended production testing of the Cheal –A3X and Cheal-A4 wells was undertaken in 2005. The extended testing demonstrated that the wells were capable of stable flow rates.
An initial independent assessment of reserves in the Cheal field by Sproule International Limited was completed in April 2005, and was updated as at December 31, 2005, assigning 0.58 million barrels (Company share) of Proven Undeveloped oil reserves to the Cheal Field.
In December 2005, the joint venture ceased production testing of the Cheal wells in order to re-develop the field and optimise field production and oil sales strategy during the course of 2006. Gas was being flared to atmosphere (in compliance with consent conditions) but was then linked to electricity generation equipment (used to generate electricity on-site). Power surplus to site requirements is sold into the national electricity grid system.
A 3D seismic survey was conducted over the Cheal and Cardiff discoveries during 2006. The results of the survey are being used to determine bottom hole locations for the Cheal development wells and will be used to optimize the drilling and testing plan at Cardiff.
Development of the field commenced on grant of the mining permit (PMP 38156) in July 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 a second site, Cheal B, located a kilometre or so to the north. Engineering optimisation and design of the facilities allow capacity to be increased in the future should this be required.
In December 2006, the Company acquired a further 19.8% interest in the Cheal mining and exploration permits, by the purchase of all the shares in one of the other joint venture participants, Arrowhead Energy Limited.
Development of the northern portion of the field from the Cheal B site commenced in 2006, with four wells 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 two upper levels, increasing confidence in the resource potential of the north western extension of the Cheal Oil Field. This well is currently suspended, awaiting further testing.
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The Cheal production station was commissioned in August 2007, and officially opened on October 8, 2007. Final commissioning of the pipelines and Cheal-B site were completed ahead of schedule in December 2007. Most of the plant at the new production station was designed specifically for the production station, in order to deal effectively and efficiently with the specific nature of the hydrocarbons being produced. The vessels, heat exchangers and piping are specific to the Cheal process. The design of the power fluid pump, the coalescing filter, and export compressor have been patented by their respective suppliers, and all instrumentation is covered by patents.
For Cheal field production, the Company has developed two avenues for disposal of associated gas – electricity generation on-site (including export of surplus electricity to the national electricity grid system), and a gas sales contract for sale of gas into the national domestic reticulation system. The first of these can only account for a maximum of 240 Mcf per day. During current production, associated gas produced is in the order of 500 Mcf per day, necessitating export of gas for treatment and sale via the gas sales contract as well.
Cheal oil is trucked to nearby Waihapa Production Station, or to the Omata Tank Farm at New Plymouth for storage and on-sale, under agreed sales contracts.
Cardiff Field
In 2004, the Joint Venture participants in PEP 38738 applied for and received approval from the New Zealand government to divide the permit into a ‘deep’ permit (PEP38738-02 - covering all pre-Miocene strata – represented by the Cardiff prospect) and a ‘shallow’ permit (PEP38738-01 – covering all strata from present to base of Miocene – represented by the Cheal prospect). The Joint Venture parties agreed with Genesis Power, a New Zealand State Owned Enterprise and the leading generator and retailer of electricity and gas in New Zealand, to drill Cardiff-2, a deep gas well, funded by Genesis as to the first NZ$15million (approx $11million) of drilling and testing costs of this well. In consideration for this, Genesis acquired a 40% equity interest in the petroleum rights in PEP38738-02, and associated rights to purchase all gas for certain specified prices. The transaction included a gas sales agreement requiring the JV to offer available gas from PEP38738-02 to Genesis for sale in priority to other purchasers, at an indexed price. The Company and the JV participants retained all rights to shallow petroleum in PEP38738-01, including the Cheal field and similar prospects.
In August 2007, the Company agreed to acquire all of the shares of International Resource Management Corporation Limited, a privately held New Zealand-incorporated company with interests in the permits over the Cardiff field and surrounding exploration acreage, in which the Company also holds interests. This transaction was closed in November 2007. The Company entered into another agreement in January 2008 to purchase from another joint venture participant an additional 5.1% of PEP 38738-02 and PMP 38156-02 (Cardiff), contingent upon that party’s completion of the purchase of an additional 15.1% interest in these permits.
The Cardiff-2 well has been drilled and cased, and three initial ‘frac’ stimulations of separate gas bearing reservoirs have been successfully completed. Clean-up of the well-bore and reservoirs and initial flow-test results were inconclusive. 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. The testing is expected to be completed in April 2008. Results will then be thoroughly evaluated before any forward programme is finalised.
Douglas Discovery
An exploration drilling operation in Papua New Guinea was announced in February 2005. A British public UK listed company, Rift Oil plc, funded the first $6million of expenditure on the Douglas-1 well, which tested a large, seismically defined structure in the foreland area of the productive Papuan Basin. This well was confirmed as a discovery in 2006. The well was suspended while further studies including seismic evaluation, and analysis and negotiations to obtain and assess commercialisation options were undertaken. A Memorandum of Understanding was signed in March 2007 to evaluate a proposal to supply gas to an Australian company via a pipeline. During 2007, the operator of PPL235 (Rift Oil plc) continued to assess the opportunities to sell Douglas gas, and the Papua New Guinea
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government issued licence terms for years 5 & 6 (2007 to 2009) of the licence requiring the drilling of one well (expected to be Puk Puk), the drilling of an optional well contingent on the results of the first well and a seismic acquisition requirement.
Stanley Discovery
The extension of the term of PRL 4 (Papua New Guinea) was granted in September 2007, after lengthy negotiations with the PNG government. During 2007, the joint venture parties undertook additional infill seismic programme to firm up the structural interpretation of the Stanley Field and to assist with the selection of the Stanley-2 well location. At the same time, the joint venture parties have continued to progress the negotiation of a gas sales agreement with PNG SEL.
After 2007 year end, the Company announced an agreement to sell its interests in Stanley (PRL 4) and in PRL 5, to Horizon Oil, subject to certain conditions precedent.
Other Exploration
Supplejack-1 (drilled in 2005) was originally considered to have future economic potential, dependent upon further wells being drilled in the near vicinity. However, after drilling the nearby Ratanui-1 well in February 2007, for which wireline log interpretation and associated seismic mapping did not indicate economic hydrocarbons, Ratanui-1 was plugged and abandoned. In early 2008, a decision was made by the joint venture parties to plug and abandon the Supplejack-1 and Supplejack South 1A wells. This work is expected to be undertaken during 2008.
In February 2007, PEPs 38766 (onshore Taranaki) and PEP 38258 (offshore Canterbury) were surrendered.
Further surrenders were effected in February 2008 (PEPs 765 and 741 (onshore Taranaki)). PEP 38745 expired at the end of its second 5-year term in November 2007.
In March 2007, the Company was granted PEP 38524 in the southern offshore Taranaki Basin.
Corporate Developments
2007 was a year of management change for the Company – during June / July 2007, the Company appointed three key new roles within management – Commercial Manager, Head Legal Counsel and Projects Manager. During a further structural review in late 2007, the Commercial Manager’s role was later focussed more strongly towards the Cheal project, and the title changed to Cheal Asset Manager. Mr. Richard Webber, the Chief Executive Officer and a director, resigned from the Company with effect from April 30, 2007. Mr. Thompson Jewell was appointed to replace him from May 1, 2007. Mr. Bruce McGregor, the Chief Financial Officer, left the Company on February 23, 2007 to pursue other opportunities. An interim CFO, Mr. David McKeogh, was contracted from PricewaterhouseCoopers, and a permanent CFO, Mr. Derek Gardiner, was appointed with effect from June 11, 2007.
The Company’s financial position has changed in several material aspects in 2007:
On December 19, 2007, the Company announced the placement of 12.5 million units at $1.20 each, for total proceeds of $15 million. Each unit comprised one common share and one share purchase warrant, exercisable at $2.25 within 1 year after issue. The placement closed, and the shares and warrants were issued, on February 28, 2008. The principal purpose of the placement was to provide funds to accelerate the Cheal field development, other appraisal and development projects and to complete the final payment for the purchase of all the shares in International Resource Management Corporation Limited. A significant proportion of this financing was placed with new investors. As at March 28, 2008, none of the warrants had been exercised.
On July 6, 2007, the Company announced the placement with two accredited investors of just under 7.7 million preferred shares at $1.30 each, for total proceeds of $10 million. The preferred shares were convertible one-for-one into Austral’s common shares for a three year period and had a fixed dividend of 8% pa. They were to have voting rights on an as-if converted basis from January 1, 2008. If not earlier converted, the preferred shares were redeemable and retractable at par after 3 years. The
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placement closed, and the shares were issued, on September 14, 2007. The principal purpose of the placement was to provide further funds for the development of the Cheal field and for working capital purposes. The Company has reached an agreement in principle with the holders of the preferred shares for the conversion of the preferred shares into convertible debentures, with effect from January 1, 2008. The convertible debentures would have similar commercial terms, but would not be entitled to any voting rights. The conversion will be subject to a number of conditions precedent, including the approval of the TSX.
As part consideration to the broker of the preferred share placement (Morgan Keegan), the Company agreed to issue 150,000 two-year share purchase warrants for an exercise price of $1.30 (with the term increasing to three years, if the Company attains Tier 1 status on the TSX-V or moves to the Toronto Stock Exchange during the two year term). These warrants were granted as at September 30, 2007. As at March 28, 2008, none of the warrants had been exercised.
On March 30, 2007, the Company raised $3.2 million by the issue of 2,500,000 shares at $1.30 each in a share placement. The placement closed, and the shares were issued, on May 16, 2007. The purpose of the placement was to fund development costs of the Cheal field, and to provide working capital. A significant proportion of this financing was placed with existing shareholders.
In December 2006, the Company secured a $23 million loan facility for a term of 4 years at commercial lending rates. The loan was arranged and underwritten by Investec Bank (Australia) Limited. The principal purposes of the loan facility were to fund the acquisition of Arrowhead Energy Limited (a privately held New Zealand-incorporated company with interests in the permits over the Cheal and Kahili fields and surrounding exploration acreage, in which the Company also holds interests) and to meet ongoing costs associated with the development of the Cheal field. $15,738,000 was drawn down as at 31 December 2006 (including $3,000,000 which remains held in a restricted bank account as part of the security arrangements supporting the facility). The remaining $7,262,000 was drawn down in three instalments during 2007. Repayments during 2007 totalled $4,350,000. The balance outstanding under the facility at December 31, 2007 was $18,650,000.
After 2007 year end, the Company announced that it had reached agreement with Investec to restructure the facility, with the key financial terms being a principal repayment of US$4.2 million on March 31, 2008 (reflecting the scheduled US$2.2 million due; with the further US$2 million paid from the restricted cash held in respect of the loan facility and applied in inverse order of maturity). In addition, a further US$3.5 million will be paid on completion of the announced sale of the PNG PRL assets (to be applied as to $2.05 million against the June 30, 2008 scheduled principal due; and the balance of US$1.45 million applied in inverse order of maturity). The interest rate margin will increase by an additional 2% on the total principal outstanding for the period January 31 to June 30, 2008 inclusive. In addition, Investec will be issued with shares to the value of US$750,000 based on the Austral share price at March 19, 2008. There are several commercial and administrative conditions which must also be complied with.
Under the loan facility agreement, the Company issued to Investec 2.5 million common share purchase warrants. The warrants are exercisable for 24 months at a price of $2.11 per common share. As at March 28, 2008, none of the 2.5 million warrants had been exercised.
Forward Plans
Where 2006 was a year of preparation, and 2007 was a year of delivery, 2008 will be a year of consolidation to secure the financial future of the Company. The successful execution of our strategy in 2008 will require the Company to:
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| § | manage the Investec loan facility to reach, as soon as practical, Cheal project completion as defined by the agreement; |
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| § | implement further incremental production from the Cheal field and grow existing production capability; |
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| § | deliver a programme for the exploration and exploitation of the Mt Messenger formation in the greater Cheal area, |
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| § | seek further capital injection to ensure a stable financial platform for the Company to develop Cheal and fund its appraisal activities and exploration opportunities; |
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| § | secure a definitive test on the K3E zone, and if successful, prepare plans for the immediate development of the Cardiff field; |
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| § | actively promote monetisation of core assets through the likes of drilling and producing from Kahili-2, and divestment of certain of the PNG assets. |
A number of these programmes have not received joint venture 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.
The Company’s plan for 2008 is to rationalise its operating and capital expenditure programme to ensure it can sustain and improve production at Cheal and meet its commitments in other permits.
Broadly, the Company’s financial strategy is to build its ability to be self-funding through increasing production revenues at Cheal and Kahili and as required fund its capital and exploration expenditure program and any potential acquisitions by a mix of:
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| • | farm-out of equity in a permit; |
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| • | rationalisation and, if appropriate, monetisation of current portfolio assets; |
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| • | reinvesting any surplus funds from operations; |
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| • | using existing cash resources; |
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| • | project debt financing; and |
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| • | issuing additional equity. |
The appropriate choice of one or a mix of these options will be dependent upon the project under consideration.
General
The Company’s strategy to achieve growth is to acquire and invest in oil and gas properties throughout Australasia, with a particular emphasis on New Zealand’s onshore Taranaki Basin, and merging with or acquiring suitable targets if the opportunity arises. Management’s principal long term objective is to grow the Company into an oil and gas exploration, development and production company, with internally generated oil and gas sales revenues sufficient to maintain a selective grass roots exploration program to augment and replace produced reserves. Management seeks additional reserves and production growth through carefully considered acquisitions of additional oil and gas properties. The long term commercial success of the Company depends on an ability to find, acquire, develop and commercially produce oil and natural gas reserves.
Company management has industry experience in many international producing areas and has the capability to expand the scope of the Company’s activities as opportunities arise. Management seeks to select exploration and acquisition opportunities that will promote value creation within the Company. In reviewing all potential acquisitions, management considers the qualitative aspects of the subject properties including risk profile, technical upside, potential reserve life and asset quality.
The Company’s exploration policy is to acquire suitable “grass roots” interests, focussing on minimizing financial exposure of the Company through effective property portfolio management techniques including farming-out to, or joint venturing property interests with, other industry participants, and judicious use of lower cost exploration and development techniques, and of permit relinquishment where warranted.
Company management attempts to maintain good relationships with industry, political and institutional bodies. These relationships can assist the Company with the process of obtaining new oil and gas business opportunities and generating future growth for the Company.
Specialised Skill and Knowledge
The success of the Company largely depends upon the performance of its key employees and on the advice and project management skills of various consulting geologists, geophysicists and engineers retained by the Company from time to time. Although there are other personnel available in the sector
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who could replace Company exploration experts, there is likely to be some difficulty in finding immediate replacements of suitable calibre.
Competitive Conditions
Company management strives to maintain the Company’s competitive edge by utilising current technologies to enhance exploitation, development and operational activities. However, the oil and gas industry is highly competitive. The Company actively competes for prospect acquisitions, exploration permits and licences, drilling equipment and services, access to production infrastructure, and employment of skilled industry personnel, and for capital to finance such activities, with a substantial number of other oil and gas companies, many of which have significantly greater financial and personnel resources than the Company. The Company’s competitors include major integrated oil and natural gas companies and numerous other independent oil and natural gas companies and individual producers and operators.
Certain of the Company’s customers and potential customers are themselves exploring for oil and natural gas, and the results of such exploration efforts could affect the Company’s ability to sell or supply oil or gas to these customers in the future.
The Company’s ability to successfully bid on and acquire additional property rights, to discover reserves, to participate in drilling opportunities and to identify and enter into commercial arrangements with customers will be dependent upon developing and maintaining close working relationships with industry participants and joint venture parties and its ability to select and evaluate suitable properties and to consummate transactions in a highly competitive environment.
Regulatory Regime
The Company is subject to government regulation of the oil and gas properties it holds and of the operations it conducts on those properties, such those relating to waste disposal, toxic substances, prices, royalties, environmental protection, occupational health and safety, land access and use, permit conditions, as well as those regulations which relate to all companies operating in the relevant jurisdictions such as relating to corporate governance, withdrawal of capital from a country in which the Company is operating, taxation, and employment laws. Management does not believe that these regulations affect the Company’s business in a manner different from the effects on other companies competing in the same industry.
See also disclosures in the section “Description of the Business – Risk Factors – Regulatory Requirements” of this Form.
The general rules applicable to the Company’s permits and licences granted in New Zealand and Papua New Guinea are as follows:
New Zealand
Unless otherwise indicated, Petroleum Exploration Permits granted in New Zealand provide an exclusive right to explore for petroleum for an initial term of five years, renewable for a further five years over one-half of the original area. Upon application, the holder is required to commit to do certain work in the permit area, during the permit term. Permit holders can apply for changes to the committed work programs under certain circumstances. If a discovery is made, the permit holder may be entitled to apply for a Petroleum Mining Permit, granted for a term of up to 40 years from the date of issue. The New Zealand government has reserved a royalty from the sale of petroleum products. For any discovery made between June 30, 2004 and December 31, 2009, the royalty will be the greater of (A) 1% of the net sales revenue (from natural gas) and 5% of the net sales revenues (from oil); or (B) 15 to 20% of accounting profits from the sale of petroleum products. For other discoveries, the royalty will be the greater of (A) 5% of net sales revenue or (B) 20% of accounting profits.
Papua New Guinea
Petroleum prospecting licences granted in Papua New Guinea provide for the exclusive right to explore for petroleum for an initial term of six years, renewable for a further five years over one-half of the original area, and the right to enter into a Petroleum Development Licence or Petroleum Retention Licence upon a discovery. Petroleum retention licences granted in Papua New Guinea provide for the
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exclusive retention of interest in the permit for an initial term of five years, renewable for a further five years over the original area, while development options are progressed. The Petroleum Development Licence provides the right to produce any oil and gas discovered for a period of up to 25 years and may be extended for a further period of up to 20 years from discovery, subject to a maximum 22.5% participating interest that can be acquired by the Government of Papua New Guinea and a 2% royalty to the government, which royalty the government pays (all or part of) to project area landowners, local-level government authorities, or provincial government authorities, in agreed or determined proportions. The participants can apply for extensions or reductions of the committed work programs for the licences under certain circumstances (by way of an Application for Variation of the Work Program).
Production and Revenue
The Company sells oil and gas from producing or pre-producing properties in which it holds an interest.
Oil
In 2005, the Company recognised proved reserves in respect to the Cheal oil field discovery. Development of the Cheal field commenced in August 2006. The production station construction programme was slightly delayed, with first permanent production commencing in Q3 2007. Simultaneous production from testing operations occurred from July to December 2006 and re-started in February 2007, from new development wells drilled in December 2006.
During 2005, 2006 and 2007, the Company sold all oil produced from its production testing of Cheal and Cardiff fields, on short-term temporary arrangements at world parity prices (less costs, fees and royalties). Permanent production oil and gas is now sold under longer-term sales contracts. Selling price remains based on world parity prices (less costs, fees and royalties).
In 2005, 2006 and up to December 2007, the Company sold virtually all of its oil production to Southern Petroleum NZ Limited (a subsidiary of Swift Energy Ltd). From December 2007, the Company commenced selling Cheal production to Shell (Petroleum Mining) Company Limited.
Gas
There is no spot market for natural gas in New Zealand; therefore all gas sales are made under long term contracts for the primary purpose of electricity generation or reticulation to homes and businesses.
The Company achieved a small amount of gas and condensate production from the Kahili discovery in 2004, which gas was sold to NGC under contract. However, all Kahili reserves were written off in 2004, based on an independent report by Sproule International Limited. There has been no further production from the Kahili field since this time.
The Company did not sell any gas in 2005 or 2006. Solution gas associated with oil from the Cheal field was initially flared to atmosphere (in compliance with consent conditions) but was later (September 2005) linked to electricity generation equipment, which equipment is used to generate electricity on-site at Cheal. Prior to completion of gas export pipelines in December 2007, any power surplus to site requirements was sold into the national electricity grid system. Since that time, gas surplus to electric generation requirements is now exported to the nearby Waihapa treatment station, for treatment under processing contract, followed by delivery under sales contracts to another third party.
The 2005 independent reserves evaluator’s report on Cheal also summarized the resource potential of the Cardiff structure, but as hydrocarbons had not at that time, nor as at December 31, 2007, been flow-tested from Cardiff-2A ST1 in a controlled and sustained manner, no reserves have been assigned to Cardiff. The Cardiff-2A ST1 well did produce gas and condensate on production test during 2005. Gas was flared to atmosphere (in compliance with consent conditions) and condensate was sold at world parity prices (less costs, fees and royalties). Some flow testing of Cardiff-2A ST1 was undertaken during 2006, and testing of the K3E zone in the well commenced February 25, 2008.
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The Douglas-1 exploration well (PPL 235; Austral 35%) and the Stanley well (PRL 4; Austral 28.92%) in Papua New Guinea have both been determined to be gas discoveries and have been suspended while further studies and analysis and negotiations to obtain and assess commercialisation options were undertaken.
Foreign Operations
Austral’s operations and related assets are located in New Zealand and Papua New Guinea. Papua New Guinea may be considered to be a developing country and hence has a higher risk than New Zealand of becoming politically and/or economically unstable or which could become politically and economically unstable in the future. Such instability, and any changes in regulations or shifts in political condition, are beyond the Company’s control and adversely affect the Company’s business.
Exploration and development activities in politically or economically unstable countries may require protracted negotiations with host governments, national oil companies and third parties and are frequently subject to economic and political considerations, such as taxation, nationalisation, expropriation, inflation, currency fluctuations, increased regulation and approval requirements or timelines, governmental regulation and the risk of actions by lawless factions, any of which could adversely affect the economics of exploration or development projects.
Infrastructure development in Papua New Guinea is limited. In addition, the Company’s properties are located in remote areas, which may prove difficult or time-consuming to access. These factors may affect the Company’s ability to explore and develop its properties and to store and transport its oil and gas production.
Business Cycle and Seasonality
The Company’s business operations and revenue are not seasonal, except to the extent that:
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| • | forecast weather may determine the timing of operations and weather delays may affect the speed of completion of operations; and |
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| • | its revenues are generally reliant on international oil prices, which are partially affected by seasonality. |
Oil prices vary in line with international prices, for which there have been, in past years, seasonal highs in the summer months (for the “US driving season”) and in the winter months (for the northern hemisphere heating oil season).
The Company’s revenues are also partially reliant on local gas prices in New Zealand, which are not affected by seasonality. As gas is sold under long term contract, gas prices are determined at the outset of the contract and generally only increase by application of an inflation adjustment formula independent of any seasonality factors.
Environmental Risks
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to a variety of local and international conventions and laws and regulations. Pro-active management by the Company of environmental concerns can reduce its exposure, and procedures are in place to ensure care is taken in the day-to-day management of the Company’s oil and gas properties. Environmental legislation provides for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances produced in association with oil and natural gas operations. Exploration legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures and a breach may result in the imposition of fines and penalties, some of which may be material.
Drilling hazards or environmental damage can greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include, but are not limited to, delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, encountering unexpected formations or
- 14 -
pressures, premature decline of or invasion of water into reservoirs, blow-outs, cratering, sour gas releases, fires and spills, insufficient storage or transportation capacity, or other geological, infrastructure and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximizing production rates and recoveries over time, and cash flow and revenue forecasts attempt to realistically estimate production declines, production declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect the long term continuity of revenue and cash flow levels to varying degrees.
Environmental legislation is evolving in a manner expected to result in stricter standards and enforcement, larger fines and liability and potentially increased capital expenditures and operating costs. No assurance can be given that environmental laws will not result in a curtailment of production or a material increase in the costs of production, development or exploration activities or otherwise adversely affect the Company’s financial condition, results of operations or prospects.
Management is not aware of present material liability related to environmental matters. However, the Company may, in the future, be subject to liability for environmental offences of which it is presently unaware.
Carbon Emissions Regime
The New Zealand government is a signatory to the Kyoto protocol and in order to meet the requirements of this protocol it is in the process of implementing Climate Change initiatives. Recently the government released a Framework for a New Zealand Emissions Trading Scheme and the New Zealand Energy Strategy. The government has signalled in these documents the intention to implement an emissions trading scheme and measures to encourage the use of renewable sources of power for electricity, to only allow new thermal generation in circumstances where security of supply requires, to reduce transport emissions and to promote efficiency in the use of energy.
A proposed bill is now before the NZ Parliament and undergoing the consultation process to introduce a cap and trade emissions trading scheme. Liquid fossil fuels are proposed to come under the scheme in January 2009 and natural gas in January 2010. The unit of trade is proposed to be linked to international Kyoto units. The bill also proposes a 10 year ban on the building of new thermal power generation unless required for security of supply. To fit within the exception, an exemption will be required from the Minister of Energy who will make this decision based on advice from the NZ Electricity Commission.
Austral, along with other members of the oil and gas exploration and production community in New Zealand is involved in the government consultation process. Austral is also assessing the potential effect on its business of the proposed government initiatives. The current expectation is that Austral oil sales will be exempt from the scheme given these are exported to the East Coast of Australia. Austral is also monitoring Australian government climate change initiatives in this regard.
In regard to natural gas, given that New Zealand gas sales from January 2010 are likely to be covered by the emissions trading scheme, Austral is in the process of reviewing sales contracts to ensure Austral is able to pass on the costs of purchasing emission trading units. It is also assessing the longer term potential impact on the NZ market for natural gas given the proposed ban on new thermal generation. Austral does not expect the proposed ban to reduce gas demand in the short term. In addition, Austral has in place fixed gas sale contracts which require the buyer to take Austral gas for the life of the Cardiff, Kahili and Cheal fields.
Employees
As of December 31, 2007, the Company employed 18 people in permanent full time positions, and four part-time or on a temporary basis, in its Wellington, New Zealand office, and one part-time in New Plymouth, New Zealand. The persons employed in the Wellington office are occupied with technical management and support, company and joint venture accounting, financial reporting, and office and company management. The Branch office employs operational supervisory staff. The Company also has a number of consultants who are contracted for particular projects or on-site work.
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Principal Properties
Where its “ownership interest” in a property is less than 100%, this is because the Company holds its interests through a joint venture with one or more other industry participants. Substantially all of the Company’s exploration and development activities are conducted jointly with third parties under joint venture agreements. Joint venture agreements are considered ordinary course contracts and hence are not attached hereto as exhibits. The terms of the joint venture agreements generally provide that the Company must bear its pro rata share of exploration and development costs and is entitled to that share of production income or proceeds of sale of the property. If a participant in a joint venture fails to pay its share of joint venture approved costs, it will be subject to dilution of its interest in the joint venture, and hence in the permit. In certain events the Company, like any other participant in the joint venture, can lose its entire interests in the joint venture (and hence in the property) for failure to pay its share of costs or for material breaches of the joint venture agreement.
The Company’s properties and the Company’s interests in the joint ventures related to them, as at March 28, 2008 are summarized as follows:
New Zealand
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Field/Prospect Name |
| Permit |
| Permit |
| Ownership |
| Gross Area |
| Net Area (km2 |
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Kahili |
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| PMP 38153 * |
| Aug 31, 2019 |
| 85.00 |
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| 5.99 (1,480) |
| 5.09 (1,258) |
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Cheal |
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| PMP 38156-01 * |
| Jul 25, 2016 |
| 69.50 |
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| 30.3 (7,487) |
| 17.33 (4,283)(2) |
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Cardiff |
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| PMP 38156-02 * |
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| 44.90 | (1) |
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Greater Cheal (Shallow) |
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| PEP 38738-01 * |
| Jan 14, 2010 |
| 69.50 |
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| 46.51 (11,493) |
| 26.6 (6,574)(2) |
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Greater Cheal (Deep) |
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| PEP 38738-02 * |
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| 44.90 | (1) |
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Heaphy |
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| PEP 38746 * |
| Aug 7, 2012 |
| 83.33 |
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| 27.01 (6,674) |
| 22.51 (5,562) |
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Winchester |
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| PEP 38748 * |
| Aug 7, 2012 |
| 66.66 |
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| 32.01 (7,910) |
| 21.34 (5,273) |
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D’Urville Island |
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| PEP 38524 * |
| Mar 31, 2012 |
| 100.00 | (3) |
| 2,187 (540,419) |
| 2,187 (540,419) |
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* | The Company is the operator of these permits. |
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(1) | Due to the acquisition of International Resource Management Corporation Ltd in November 2007, the Company increased its percentage interest from 25.1% to 44.9% effective November 2007. The Company has entered into an agreement to purchase from another joint venture participant an additional 5.1% interest contingent upon completion by that party of the purchase of a further 15.1% interest in these permits. Accordingly the Company’s interest may increase by a further 5.1%, after report date. |
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(2) | The Company holds different percentage net interests in each of two joint ventures over the same permit area, which area is divided stratigraphically between the two permits. The Company uses an average net percentage of 57.2% to approximate net interest. Although Cardiff is not yet Developed, the permit area is Developed via the Cheal Field wells, and therefore the entire permit area is treated by the Company as Developed. |
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(3) | The Company is actively seeking farm-in participants for future activities in this permit. |
PEPs 38766 and 38258 were surrendered during 2007, after an analysis of the Company’s prospects inventory and forward plans. PEP 38745 expired during 2007, at the end of its second 5-year term. PEPs 38765 and 38741 were surrendered after balance date in February 2008, after further
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assessment of the prospects, exploration risks and financial commitments required in each permit area.
The following figure shows the locations of the Company’s permits in New Zealand, as at March 28, 2008:
The following key activities were carried out during the year ended December 31, 2007:
Cheal (Shallow) and Cardiff (Deep) Fields
PMP 38156 and PEP 38738
(Shallow 69.5%; Deep – 44.9%)
PEP 38738 and PMP 3156 are divided into deep (-02) and remainder or shallow (-01) strata sections. The separate strata sections are held by separate joint ventures. The Company holds interests in both the deep and shallow sections, and in both the mining and surrounding exploration areas.
Cheal Field (Shallow – PMP 38156-01)
In Q4 2006, four wells (Cheal-B1, B2, B3 and B4) were drilled from a second site, Cheal B, located to the north of the original Cheal (A) site. Cheal-B1, B2 and B3 were completed as producers during early 2007. 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 two upper levels, increasing confidence in the resource potential of the north western extension of the Cheal Oil Field. This well will be sidetracked in 2008 and completed as a producer.
Construction of the Cheal Production Facilities at the Cheal A site commenced in Q3 2006. 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
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production 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.
Commercial arrangements for the transportation, storage, processing and sale of both crude oil and gas production have been completed and are in operation. In fiscal 2007, the Cheal Oil Field produced a total of 132,805 barrels of oil (100%). The oil was transported to the Waihapa Production Station where it was sold to Swift Energy NZ Ltd. Gas produced in association with crude oil production is used to generate electricity for on-site use, with the excess electricity initially being sold into the local grid. The export of excess gas via a pipeline to the Waihapa Production Station commenced in December 2007. Production during February 2008 averaged a rate of 616 barrels oil per day and 558 mscf gas per day (100%; Company share 69.5%).
The joint venture parties are expected to finalise the Cheal drilling programme in Q2 2008 and it is anticipated that drilling operations will commence in Q2 2008, targeting an additional production of 400-500 bpd by Q4 2008.
The Company is the operator of the Cheal project on behalf of the joint venture, and owns a 69.5% beneficial interest in the Cheal Field. An independent report by Sproule International Ltd (dated December 31, 2007) ascribes 2,906 million BOE’s (100%) of 2P (proved and probable) reserves to the Cheal Field (see the Company’s Reserves Report filed on SEDAR atwww.sedar.com).
Cardiff Field (Deep – PMP 38156-02)
The joint venture participants obtained specialist fracture technology advice which, combined with the results of the in-house reservoir simulation studies which have been undertaken, has enabled them to determine an optimum testing programme for the K3E interval. Additional desk-top and simulation studies have also been undertaken during 2007.
In August 2007, field operations re-commenced for the workover of the Cardiff-2A ST1 well, ahead of a flow test of the K3E reservoir interval. The upper McKee Formation was isolated and a drilling rig was mobilised to the site in November 2007. The workover of the Cardiff 2A-ST1 well was completed in January 2008. Testing operations on the K3E zone commenced on February 25, 2008, and are expected to be completed by end March. Results will then be thoroughly evaluated before any forward programme is finalised.
No reserves have yet been assigned to this property.
The Company is the operator of the Cardiff Field. In September 2007 the company entered into an agreement to acquire all of the shares of International Resource Management Corporation Limited (IRM). IRM held a 19.8% interest in the Cardiff Field. The purchase of the shares of IRM was completed in November 2007. On completion of the purchase of IRM, the Company’s interest in the Cardiff Field increased to 44.9%. On 8 January 2008, the Company entered into an agreement to purchase from Genesis an additional 5.1% of PEP 38738-02 and PMP 38156-02 (Cardiff) contingent upon Genesis Power Limited completing the purchase of another participant’s 15.1% interest in these permits.
Kahili Field PMP 38153 (85%)
A seismic survey within the PEP 38736 permit area was undertaken in May 2005 and a further seismic line was acquired in March 2006. This infill seismic data suggested that the Kahili Field contains considerable updip potential. Subject to securing a farm-in participant or funding, the Company intends to drill the Kahili-2 well 140 metres updip and in the same structure as the original Kahili-1 well, which produced for a short period. If successful, Kahili gas-condensate could come back on-stream relatively quickly because of existing infrastructure, including a small gas treatment plant.
The Company holds an 85 percent interest in the Kahili Field and is the operator.
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Other New Zealand Exploration Operations
In March 2007, the Company was granted PEP 38524 in the southern offshore Taranaki Basin. PEP 38524 is located immediately west and north of D’Urville Island and covers an area of 2,187 square kilometres. The first stage of the work programme requires Austral to undertake seismic reprocessing, acquire aeromagnetic data and complete either a 2D or 3D seismic survey by 1 April 2008. The Company has completed seismic reprocessing, and in June 2007, the Company acquired 418km of aeromagnetic data. Preparations for acquisition of 2D or 3D seismic in Q2 2008 are underway.
Management intends to continue an exploration programme in Taranaki by undertaking rigorous studies to mature, and high grade other high impact, drillable prospects in the portfolio.
Papua New Guinea
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Field/Prospect |
| Permit |
| Permit Expiry |
| Ownership |
| Gross Area |
| Net Area (km2 |
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Douglas |
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| PPL 235 |
| Aug 29, 2009 |
| 35.00 |
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| 2910 (719,076) |
| 1,018 (251,676) |
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| PPL 261 |
| Nov 23, 2012 |
| 50.00 |
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| 4200 (1,037,841) |
| 2,100 (518,921) |
| |||
Stanley |
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| PRL 4 *(1) |
| Aug 31, 2010 |
| 28.92 |
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| 340 (84,016) |
| 98.33 (24,297) |
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Ketu, Elevala |
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| PRL 5 *(1) |
| Feb 14, 2010 |
| 10.712 |
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| 770 (190,271) |
| 82.48 (20,382) |
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* | The Company is the operator of these permits. |
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(1) | After balance date, the Company assigned operatorship of PRL 4 to InterOil, by agreement with the joint venture parties, with effect from March 3, 2008, and agreed to sell its interests in PRL’s 4 & 5 to another joint venture participant, which sale remains subject to certain conditions precedent. |
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The following figure shows the locations of the Company’s permits in Papua New Guinea, as at March 28, 2008:
‘
Douglas Field PPL 235 (35%)
A 2D seismic survey was undertaken within PPL 235 in Q3 2007. The data acquired confirmed drilling locations on the northern sector of the Douglas Gas Field and has also confirmed the nearby Puk Puk prospect as being a valid exploration drilling target.
In September 2007, the joint venture received from the Department of Petroleum and Energy a years 5 and 6 work programme for the licence. The work programme requires the joint venture to drill an exploration well (Puk Puk-1), acquire 70km seismic and drill an optional well contingent upon the results of the earlier well.
The Company has approved preparations for the drilling, and testing if warranted, of the Puk Puk-1 well, and the joint venture parties are in discussion regarding the drilling timetable for the Puk Puk-1 well.
A new licence, PPL 261, adjacent to the PPL 235 area, in which Austral holds a 50% interest with Rift, was awarded in late 2006.
Stanley Gas Field PRL 4 (28.92%)
In September 2007, a five year extension was granted to the term of PRL 4. The extension to the term of the licence was backdated to September 2005.
In Q4 2007, the Company acquired 44km of 2D seismic, designed to firm up the structural interpretation of the Stanley Field and assist with the selection of a Stanley-2 well location. The joint venture is also reprocessing the historic K89 survey and this data will be integrated with the 2007 Stanley Seismic data.
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The joint venture is currently in the planning stage for an appraisal programme for the Stanley Field. However, the Company assigned operatorship of PRL 4 to InterOil with effect from March 3, 2008, On March 17, 2008, the Company formally accepted an offer from Horizon Oil Ltd of the Company’s licence interests in PRL’s 4 & 5. The offer is subject to the pre-emptive right provisions in the relevant joint venture agreements and PNG government regulatory approvals.
Reserves
The Company’s report in the form of:
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| - | Form 51-101F1, Statement of Reserves Data and Other Oil and Gas Information; |
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| - | Form 51-101F2 Report on Reserves Data by Independent Qualified Reserves Evaluator or Auditor and; |
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| - | Form 51-101F3 Report of Management and Directors on Oil and Gas Disclosure |
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are incorporated by reference in this Annual Information Form. A copy of the foregoing documents may be obtained upon request from the Company, and are also available on the SEDAR website atwww.sedar.com. |
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The common shares of the Company must be considered to be a speculative investment due to a number of factors primarily related to the Company’s involvement in the exploration, development and production of oil and natural gas, and its present stage of development. There can be no assurance that the Company’s shares will increase in value. The following risk factors should be considered. The order of seriousness and likelihood of occurrence is a subjective assessment and the order in which they are presented should only be considered representative.
Exploration, Development and Production Risks
The Company’s future oil and natural gas reserves, production and cash flows to be derived therefrom are highly dependent on the Company’s success in exploiting its current reserve base and acquiring or discovering additional reserves. Without the addition of reserves through exploration, acquisition or development activities, the Company’s reserves and production will decline over time as reserves are depleted. A future increase in the Company’s reserves will depend not only on the Company’s ability to develop its present properties, but also on its ability to select and acquire suitable producing properties or prospects.
There is no assurance that the Company’s future exploration and development efforts will result in the discovery or development of additional commercial accumulations of oil and natural gas. There is also no assurance can be given that the Company will be able to locate satisfactory properties for acquisition or participation. Moreover, if such acquisitions or participations are identified, the Company may determine that current markets, terms of acquisition and participation or pricing conditions make such acquisitions or participations uneconomic.
Future oil and gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs. Completion of a well does not assure a profit on the investment or recovery of drilling, completion and operating costs. Geological conditions are variable and of limited predictability. Even if production is commenced from a well or field, production will inevitably decline over the course of time, reducing the operating profitability of the enterprise and eventually causing its termination.
The amounts attributed to properties in the Company’s financial statements represent acquisition and exploration expenditures only, and should not be taken to in any way reflect realizable value.
Any development of oil and gas production facilities is subject to risks which may adversely impact on the commercial viability of a project, as the realized revenues from the project may be less than anticipated, and the capital and operating costs may be greater than anticipated. The risks to revenue include the development wells not producing predicted rates of oil and gas production, decreases in the market prices of oil and gas, and increased processing, storage and transportation costs.
Funding Requirements
Oil exploration involves a high degree of technical and commercial risk and is characterized by a continuous need for fresh capital. Management seeks to minimize and spread this risk by joint-venturing oil exploration projects with other companies, and by participating in properties exhibiting a range of risk profiles, thereby reducing its cost exposure to any one project. The development of any reserves found on the Company’s exploration properties may depend upon the Company’s ability to obtain further financing through farming-out part of its interest in a particular project, debt financing or equity financing.
There is no assurance that market conditions will continue to permit the Company to raise funds if required, or that the Company will be able to enter into agreements with third parties to fund permit obligations, or be able to renegotiate such obligations with the relevant government agency. The Company faces competition from other oil companies for oil and gas properties and investor dollars.
If the Company’s cash flow from operations is not sufficient to satisfy its capital expenditure requirements and existing debt obligations, there can be no assurance that additional debt or equity financing will be available to meet these requirements. If the Company is unable to fund its permit
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obligations by additional debt or equity financing, or by farm-out agreements or renegotiating such obligations, the Company may be unable to carry out its plan of operations and may be forced to abandon or forfeit some of its permit interests, or reduce or terminate its operations.
Operating Hazards and Environmental Liabilities
Drilling hazards or environmental damage can greatly increase the cost of operations, and various field operating conditions may adversely affect the production from successful wells. These conditions include, but are not limited to, delays in obtaining governmental approvals or consents, shut-ins of connected wells resulting from extreme weather conditions, encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, cratering, sour gas releases, fires and spills, premature decline of reservoirs, the invasion of water into producing formations, insufficient storage or transportation capacity or other geological and mechanical conditions. While close well supervision and effective maintenance operations can contribute to maximizing production rates and recoveries over time, production delays and declines from normal field operating conditions cannot be eliminated and can be expected to adversely affect the long term continuity of revenue and cash flow levels to varying degrees.
Also see the disclosures in the sections “Description of the Business – Environmental Risks” “Description of the Business – Carbon Emissions Regime” of this Form.
Oil and Natural Gas Markets
The operations and earnings of the Company are also affected by local, regional and global events or conditions that affect supply and demand for oil and natural gas. These events or conditions are generally not predictable and include, among other things, the development of new supply sources; supply disruptions; weather; international political events; technological advances; restricted access to infrastructure (pipelines, storage, shipping or load-out facilities, etc), and the competitiveness of alternative energy sources or product substitutes.
Both oil and natural gas prices are unstable and are subject to fluctuation. The economics of producing from some wells may change as a result of lower prices, which could result in a reduction in the volumes produced by the Company. Any material decline in prices could result in a reduction of the Company’s net production revenue. Management might also elect not to produce from certain wells at lower prices. These factors could result in a material decrease in the Company’s net production revenue causing a reduction in its oil and gas acquisition and development activities.
Management has established a policy to partially hedge the effect of fluctuating oil and natural gas prices, in order to fix the price that the Company will receive on a portion of its production for a specified period of time.
Competition
See the disclosures in the section “Description of the Business – Competitive Conditions” of this Form.
Reliance on Operators and Key Employees
To the extent the Company is not the operator of its oil and gas properties, the Company depends on such operators for the timing of activities related to such properties and may be largely unable to direct or control the activities of the operators, except through joint venture participation and voting.
In addition, see the disclosures under the section “Description of the Business – Specialised Skill and Knowledge” of this Form.
Uncertainty of Reserves Figures
Actual production expenditures, revenues and reserves will likely vary from those estimated, and these variances may be material. Estimates of oil and gas reserves are interpreted from geological, petrophysical and reservoir engineering data. Reservoir engineering is a subjective process of estimating underground accumulations that cannot be measured precisely, and the accuracy of any
- 23 -
estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. Such interpretations are inherently uncertain, as are the projections of future rates of production and timing of development expenditures. Factors such as historical production from the area compared with production from other producing areas, assumed effects of governmental regulations, assumptions of future oil and gas prices, future operating costs, development costs and remedial and workover costs, will affect the estimates of economically recoverable quantities and of future net cash flow. Any significant variance in the assumptions could materially affect the estimated quantity and value of reserves. The Company’s reserves are evaluated by an independent reservoir engineering firm each year.
Currency Fluctuations and Foreign Exchange
The Company’s practice is to raise its equity in United States dollars. However when the Company listed on the New Zealand Stock Exchange, equity was also raised in New Zealand dollars. The Company holds cash denominated in both United States and New Zealand currency. The Company’s current property acquisition and exploration commitments are denominated in United States and New Zealand dollars and, to a much lesser extent, in currencies of other countries.
The Company has established a policy to hedge its exposure to foreign currency exchange rate risk.
Papua New Guinea, in which the Company operates, may impose foreign exchange restrictions that may materially affect the Company’s financial position and results of operations in that country.
No Assurance of Earnings
The Company currently has one oil and gas property in production. The Company has an accumulated deficit from its historical operating results and there is no assurance that the business of the Company will continue to be profitable in the future. Management cannot guarantee that the Company will continue generating revenues in the future. A failure to generate revenues may cause the Company to eventually go out of business. The Company has not paid dividends at any time in its history to date and there is no assurance that the Company will pay a dividend at any time in the future.
Regulatory Requirements
The current and future operations of the Company, including development activities and commencement of production on its properties, require permits from various foreign and local governmental authorities, and are governed by laws and regulations relating to oil and gas exploration and development, prices, royalties, allowable production, import and export of hydrocarbons, restrictions on the withdrawal of capital from a country in which the Company is operating, taxes, labour standards, occupational health, waste disposal, toxic substances, land use, environmental protection and other matters.
The Company’s operations require licences, permits and renewals of these from various governmental authorities. Management believes that the Company currently holds or has applied for all necessary licences and permits to carry on the activities which it is currently conducting under applicable laws and regulations in respect of its properties, and also believes that the Company is complying in all material respects with the terms of such licences and permits. However, the Company’s ability to obtain, sustain or renew such licences and permits on acceptable terms is subject to changes in regulations and policies and the discretion of the applicable governments.
Failure to comply with applicable laws, regulations and permitting requirements may result in enforcement actions, including orders to cease or curtail operations, and may include corrective measures requiring capital expenditures, installation of additional equipment, or remedial actions. Parties engaged in oil and gas operations may be required to compensate those suffering loss or damage by reason of such activities and may have civil or criminal fines or penalties imposed for violations of applicable laws or regulations. Amendments to current laws, regulations and permits governing operations and activities of oil and gas companies, or more stringent implementation of these, could have a material adverse impact on the Company and could cause increases in capital expenditures or production costs or reduction in levels of production at producing properties or require
- 24 -
abandonment or delays in development of new properties.
Management believes that its operations comply with all applicable legislation and regulations and that the existence of such regulations have no more restrictive effect on the Company’s method of operations than on similar companies in the industry.
Also see disclosures in the section “Description of the Business – Regulatory Regime” of this Form.
Insurance
The Company’s involvement in the exploration for and development of oil and gas properties may result in the Company becoming subject to liability for pollution, blow outs, property damage, personal injury or other hazards. Although the Company has obtained insurance in accordance with industry standards to address such risks, such insurance has limitations on liability that may not be sufficient to cover the full extent of such liabilities. In addition, such risks may not be insurable in all circumstances, or management may elect, in certain circumstances, not to obtain insurance to deal with specific risks due to the high premiums associated with such insurance, or for other reasons. The payment of such uninsured liabilities would reduce the funds available to the Company. The occurrence of a significant event that the Company is not fully insured against, or the insolvency of the insurer of such event, could have a material adverse effect on the Company’s financial position, results of operations or prospects.
Risks Relating to Papua New Guinea
See the disclosures under the section “Description of the Business – Foreign Operations” of this Form.
Labour Requirements
The Company may be required to hire and train local workers in its petroleum and natural gas operations. Some of these workers may be organised into labour unions. Any strike activity or labour unrest could adversely affect the Company’s ongoing operations and its ability to explore for, produce and market its oil and gas production.
Title Matters
Management has investigated the rights to explore the various oil and gas properties it holds or proposes to acquire or to participate in and, to the best of its knowledge, those rights are in good standing.
No assurance can be given that applicable governments will not revoke, or significantly alter the conditions of, the applicable exploration and development authorisations and that such exploration and development authorisations will not be challenged.
In all cases, the terms and conditions of the permit or licence granting the right to the Company to explore for, and develop, hydrocarbons, prescribe a work programme and the date or dates by which such work programme must be done. Varying circumstances, including the financial resources available to the Company, the inability to secure equipment when required, and reliance on third party operators in respect of its permits and licences, may result in the failure to satisfy the terms and conditions of a permit or licence and result in the complete loss of the interest in the permit or licence without compensation to the Company. Such terms and conditions may be renegotiated with applicable regulatory authorities, but there is no assurance that the applicable authority will agree to the renegotiation offer.
The Company does not have sole control over the future course of development in most of its properties. Such property interests are subject to joint venture agreements which can give rise to disputes as to geological interpretation or commercial imperatives with other parties who are financially interested in the property.
The Company participates in its permits or licences with other industry participants, some of whom have access to greater or less resources from which to meet their joint venture capital commitments. If
- 25 -
the Company is unable to meet its commitments, the other joint venture participants may assume some or all of the Company’s deficiency and thereby assume a pro-rata portion of the Company’s interest in any production from the joint venture area. If another participant in a joint venture, which participant has fewer resources than the Company, is unable to meet its commitments, it may delay or veto exploration or development plans which it cannot afford, or it might default on its commitments. This may delay the Company’s desired exploration or development programme and/or lead to the Company and other participants assuming all or some of that entity’s interest, and therefore meeting a pro rata share of its required contributions (as well as receiving a pro rata share of any production).
General claims by native peoples in New Zealand and Papua New Guinea may adversely affect the rights or operations of the Company, although the Company has not received any notice of any direct challenge to any of the Company’s titles or tenures.
Non-Canadian Assets and Management
The Company is incorporated under the laws of British Columbia, Canada, but the majority of the Company’s directors and officers are residents of countries other than the Canada. Substantially all of the assets of the Company are located outside North America. Consequently, it may be difficult for Canadian investors to enforce, in Canada, judgments of Canadian courts against assets of the Company. Furthermore, it may be difficult for investors to enforce judgments of the Canadian courts based on civil liability against the Company’s non- Canadian resident officers or directors.
Public Market Risks
The Company’s shares are relatively illiquid in that they do not trade large volumes relative to other public companies. There can be no assurance that a stable market for the Company’s common shares will be maintained. If the Company fails to remain current in its filings with the SEC, Canadian and New Zealand regulatory authorities, the Company may lose any one or more of its AMEX, Canadian and New Zealand listings, which would adversely affect the liquidity of an investment in the Company.
Dilution, Change of Control
The Company’s Articles authorise the issuance of an unlimited number of shares of common and preferred stock. The Company’s Board of Directors has the legal power to issue any number of further shares without stockholder approval (although the policies of the TSX-V and AMEX require shareholders’ approval in certain situations). The Company’s Board of Directors may issue shares to acquire further capital, in order to carry out its intended operations, to expand its current operations, or to provide additional financing for future activities. The issuance of any such shares may result in a reduction of the book value or market price of the outstanding shares of the Company’s common shares. If the Company does issue any such additional shares, such issuance will also cause a reduction in the proportionate ownership and voting power of all existing shareholders. Further, any such issuance may result in a change of control of the Company. TSX-V policies require the Company to obtain shareholder approval of any transaction which will result in the creation of a new control person (as defined).
Conflicts of Interest
The Company owns shares in Rift Oil plc (approximately 0.21% of issued share capital) to whom it has transferred an interest in a Papua New Guinea exploration licence under a farm-out arrangement, and is a joint venture participant in another licence in Papua New Guinea.
Also see the disclosures under the section “Directors and Officers – Conflicts of Interest” of this Form.
- 26 -
DESCRIPTION OF CAPITAL STRUCTURE
The authorised share capital of the Company consists of an unlimited number of Common and Preferred Shares. As at March 28, 2008, 44,916,142 Common Shares and 7,692,308 Preferred Shares are issued and outstanding and there are potentially 634,176 shares issuable pursuant to vested incentive options.
As at the date of this report, the Company has reached an agreement in principle with:
|
|
|
| • | the holders of the preferred shares for the conversion of the preferred shares into convertible debentures, with effect from January 1, 2008. The convertible debentures would have similar commercial terms, but would not be entitled to any voting rights. The conversion will be subject to a number of conditions precedent, including the approval of the TSX; |
|
|
|
| • | Investec Bank Australia Ltd to issue shares in payment of a restructuring fee (as discussed in the section “General Development of the Business – Corporate Developments” of this Form). |
The Common Shares of Austral are voting shares. The holders of Common Shares are entitled to receive dividends if, as and when declared by the Board of Directors of Austral, and to one vote per share at meetings of shareholders of Austral. On the liquidation, dissolution, or winding up of Austral, all holders of Common Shares shall rank equally on the distribution of all or any part of the property and assets of Austral.
The preferred shares have the following rights and are subject to the following limitations:
|
|
|
| • | convertible into common shares at a conversion price of $1.30 per share; |
|
|
|
| • | redeemable at par by the Company after four years; |
|
|
|
| • | retractable by the holder after three years; |
|
|
|
| • | voting rights as if converted from January 1, 2008; |
|
|
|
| • | entitled to the payment of cumulative dividends at the rate of 8% per annum; and |
|
|
|
| • | entitled to a liquidation preference over the common shares in an amount equal to the par value plus accumulated unpaid dividends. |
The rights of the Company’s common shareholders have been materially modified by the creation and issuance of the preferred shares to the extent that the preferred shares are entitled to preferential dividends, a preference on liquidation and current voting rights. In addition, conversion of the preferred shares into common shares would result in dilution to existing holders of common shares.
As at December 31, 2007, there were 2.65 million share warrants outstanding, and 15.15 million by March 28, 2008 (terms as noted in the section “General Development of the Business – Corporate Developments” of this Form).
The Company does not intend to pay dividends on its common shares in the foreseeable future. The future payment of dividends will depend on the earnings and financial condition of the Company and such other factors as the Board of Directors of the Company consider appropriate.
The Common Shares of Austral are listed and quoted for trading on the TSX Venture Exchange (“TSX-V”) and the New Zealand Stock Exchange (“NZSX”) under the symbol “APX”, and in the United States on the American Stock Exchange (“AMEX”) under the symbol “AEN”.
The following table sets out the price range and trading volume of the Common Shares in respect to trading on the TSX-V for 2007:
|
|
|
|
|
|
|
|
|
2007 |
| High |
| Low |
| Volume |
| |
January |
| 1.89 |
| 1.54 |
| 136,300 |
|
|
February |
| 1.76 |
| 1.51 |
| 24,100 |
|
|
- 27 -
|
|
|
|
|
|
|
|
|
2007 |
| High |
| Low |
| Volume |
| |
March |
| 1.50 |
| 0.97 |
| 22,300 |
|
|
April |
| 1.40 |
| 1.05 |
| 9,400 |
|
|
May |
| 1.12 |
| 0.90 |
| 13,500 |
|
|
June |
| 1.22 |
| 0.91 |
| 50,900 |
|
|
July |
| 1.37 |
| 1.23 |
| 68,000 |
|
|
August |
| 1.38 |
| 1.16 |
| 213,300 |
|
|
September |
| 1.43 |
| 1.06 |
| 85,400 |
|
|
October |
| 1.73 |
| 1.19 |
| 168,400 |
|
|
November |
| 1.36 |
| 1.15 |
| 134,700 |
|
|
December |
| 1.12 |
| 0.89 |
| 42,300 |
|
|
Prior Sales
As at March 28, 2007 the Company also has outstanding, but not listed, 7,692,308 preferred shares and 15.15 million share purchase warrants, issued on the terms set out in the section “General Development of the Business – Corporate Developments” of this Form.
Escrowed Securities and Securities Subject to Contractual Restriction on Transfer
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|
|
|
|
Designation of |
| Number of Securities held in Escrow or |
| Percentage |
Incentive Stock Options |
| 1,987,500 (389,169 vested) |
| 100% |
- 28 -
Directors of the Company
The names and residence, and positions held by, those persons who have served the Company since January 1, 2007, as directors of the Company are as follows:
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|
|
|
|
|
Name; |
| Present and Principal |
| Positions Held |
| Period of |
Ronald Bertuzzi |
| Medical Sales Consultant (retired 2002) |
| Director |
| Oct 2, 1992 to |
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|
|
|
|
|
|
Douglas Ellenor |
| Consultant; Company Executive Principal, Jade Consulting Ltd (2000- present); |
| Director |
| January 1, |
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|
|
|
|
|
|
Charles Peter |
| Oil industry executive |
| Director |
| January 1, |
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|
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|
|
Peter Hill |
| Consultant; Oil industry executive Harvest Natural Resources, Inc., Houston, Texas, U.S.A. (President & CEO 2000-2005; director 2000-2006); |
| Chairman of the Board, |
| January 1, |
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|
|
|
|
|
Thompson Bruce |
| Oil industry executive |
| Chief Executive Officer(1), |
| May 4, 2007 to |
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|
|
|
|
|
David Newman Paraparaumu Beach, New Zealand |
| Company Director Infratil Limited (director 1994- present; chairman 2004- present); |
| Director |
| Sept 26, 2003 |
- 29 -
|
|
|
|
|
|
|
Name; |
| Present and Principal |
| Positions Held |
| Period of |
Bernhard Josef |
| Lawyer |
| Director |
| March 27, 2001 |
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|
|
|
|
|
Richard Webber |
| Company Executive |
| Chief Executive Officer(1), |
| March 2, 2006 |
|
|
(1) | Mr. Webber resigned as CEO with effect from April 30, 2007 and resigned as a director from April 20, 2007. Mr. Jewell was appointed as CEO from May 1, 2007, and as a director from May 4, 2007. |
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(2) | The term of office of each Director will expire at the next Annual General Meeting of shareholders, to be held on May 22, 2007. |
Officers of the Company
The names and residences of, and positions held by, the executive officers of the Company as at December 31, 2007 were as follows:
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|
|
|
Names and |
| Present and Principal Occupations (last 5 years) |
| Position Held in Company |
Derek Gardiner |
| Chief Financial Officer, Austral Pacific Energy Ltd. (2007- present); Finance Manager, Shell Petroleum (1994-2007) |
| Chief Financial Officer |
|
|
|
|
|
Thompson Bruce |
| Chief Executive Officer, Austral Pacific Energy Ltd. (2007- present); President, Birchcliff Enterprise, Evergreen Enterprises (2004-2007); Manager, Santos (2000-2004) |
| Chief Executive Officer(1), President(1) |
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|
|
Joseph Johnston |
| Petroleum Engineering Manager, Austral Pacific Energy Ltd. (2005- present); oil industry contractor (1992-2005) |
| Petroleum Engineering Manager |
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|
|
Christopher |
| Cheal Asset Manager; Austral Pacific Energy Ltd (2006- present); CEO, Arrowhead Energy Ltd (2006); manager, Contact Energy Ltd (2006); Business Development Manager, GNS Science (2002-2006) |
| Cheal Asset Manager |
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|
|
Carey Mills |
| Exploration Manager, Austral Pacific Energy Ltd. (2005- present); oil industry contractor (1999-2005) |
| Exploration Manager |
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|
|
David Pay |
| Head Legal Counsel, Austral Pacific Energy Ltd. (2007- present); Legal Counsel, Electricity Commission (2004-2007); Contact Energy Ltd (1999-2004) |
| Head Legal Counsel |
|
|
(1) | Mr. Jewell was appointed as CEO from May 1, 2007. |
- 30 -
The following executive officers resigned from the Company in the year ended December 31, 2007:
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|
Names and |
| Position Held in Company and resignation |
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| |||
Bruce McGregor |
| Chief Financial Officer – resigned with effect from February 23, 2007 |
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|
Richard Webber |
| Chief Executive Officer – resigned with effect from April 30, 2007 |
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Security Holdings
As at March 28, 2008, the directors and executive officers of Austral, as a group, beneficially own, or controlled or directed, directly or indirectly, 719,600 Common Shares of Austral, or approximately 1.60% of the 44,916,142 issued and outstanding Common Shares at that date, together with 225,834 vested incentive stock options.
Conflicts of Interest
Mr. Newman serves as a director and Chairman of Infratil Limited, the parent company of Infratil Gas Limited, a greater than 10% shareholder of the Company. He is not employed by Infratil or the Company, is remunerated only in his capacity as a director of each company, and serves as chairman in a part-time capacity of Infratil. The Board has determined that he does not have any “material relationship with the Company which might interfere with the exercise of his independent judgement”. He does not take part in discussions nor vote in relation to matters involving Infratil’s equity participation in the Company.
Certain of the directors of the Company are or were directors and/or officers of other corporations engaged in the petroleum exploration and development or related industries. It is possible that conflicts of interest may arise between their duties as director and/or officer of such companies, and as director or officer of the Company. The percentage participation of the Company and any other associated company in a property is determined by each board of directors of each such company independently, using the best business judgment of the Board.
Under the Company’s Articles and the relevant legislation, any such conflict of interest is required to be disclosed and any contract in which a director or officer has a material interest must be referred to the Board of Directors for approval, and the interested director will not vote on any resolution given such approval. The Company requires confidentiality obligations from all officers, employees and consultants.
These transactions were in the normal course of operations and were measured at the exchange amount, which is the consideration established and agreed to by the related parties.
Additional information concerning interest of management and others in material transactions during fiscal 2007 is set out in Note 15 of the Company’s audited financial statements for the year ended December 31, 2007, which statements are filed on and available for download fromwww.sedar.com or the Company’s website, and for previous years in the Notes to the Company’s audited financial statements for each such year, as filed on and available fromwww.sedar.com or the Company’s website.
The Company’s Audit and Risk Management Committee currently comprises David Newman (chairman), Ronald Bertuzzi, Douglas Ellenor, Peter Hazledine and Peter Hill, all of whom are “financially literate” as defined by relevant legislation. All are independent directors. Mr. Newman is a New Zealand Chartered Accountant and has been appointed by the Board as the Company’s “financial expert” on the Committee.
- 31 -
Mr. Newman is a Chartered Accountant and formerly Chief Executive Officer of the Institute of Directors in New Zealand. He previously had a 22 year career with British Petroleum, culminating in four years as Chief Executive and Managing Director of BP New Zealand Limited (1990 - 1994).
Mr. Bertuzzi has a Bachelor of Economics from the University of British Columbia in 1965 and has worked in the medical sales and product development industries since that time. He retired in August 2002, but for the 10 years previous, Mr. Bertuzzi worked as a sales manager.
Dr. Ellenor has over 35 years’ experience in the exploration and production (E&P) industry, culminating in his appointment as President and CEO of the Shell Companies of Colombia (1992-1996). He then became CEO of the Colombian E&P company, Hocol SA. After a posting as Business Development Director in London, UK, he established an oil and gas consulting company. In this capacity, he served as CEO of Hocol SA and later CEO of Orca Petroleum, Inc.
Mr. Hazledine has 35 years experience in the international E&P industry with the Royal/Dutch Shell Group internationally, and then in senior management positions with Vector Gas (formerly NGC), the principal gas distributor in the New Zealand market. He is a member of the Institute of Directors in New Zealand.
Dr. Hill has over 35 years’ experience in the exploration and production industry. He was President and CEO of Benton Oil and Gas Company, originally in Carpinteria, California, now in Houston, Texas, U.S.A. (now called Harvest Natural Resources, Inc.) from August 2000 until October 2005. He remained on the Board of that company until end May 2006.
The Audit and Risk Management Committee is directly responsible for the appointment (subject to shareholder ratification), compensation and oversight of the independent auditor of the Company, who reports directly to the Audit Committee. The Committee is also required to assist the Board in discharging its responsibility to exercise due care, diligence and skill in relation to oversight of:
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- | the integrity of external financial reporting; |
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|
- | the application of financial policy; |
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- | financial management; |
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|
- | internal control systems; |
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|
- | accounting policy and practice; |
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|
- | related party transactions: and |
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|
- | compliance with applicable laws, regulations and standards. |
The Board has established an Audit and Risk Management Committee Charter which sets out in full the Committee’s responsibilities, procedures for communication with the auditor, and against which the committee’s performance is measured. The Committee has also established a policy for the confidential and anonymous receipt, retention and treatment of complaints. The Audit and Risk Management Committee Charter has been filed on, and is available from, the SEDAR website atwww.sedar.com, and both the Committee’s Charter and the Audit & Risk Management Committee Complaints Policy are published on the Company’s website atwww.austral-pacific.com.
The Committee’s policy for the engagement of non-audit services is set out in the Committee Charter. The procedure used to implement this policy is to refer all requests for non-audit services to the Committee’s chairman, who reviews and determines the request.
The aggregate fees billed by the Company’s external auditor during fiscal 2006 and 2007 are:
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|
|
|
|
|
|
|
Service Category |
| 2007 |
| 2006 |
| ||
Audit Fees |
| $ | 337,337 |
| $ | 261,797 |
|
Audit-Related Fees(1) |
| $ | 16,496 |
| $ | 15,560 |
|
Tax Fees(2) |
| $ | 165,321 |
| $ | 38,870 |
|
All Other Fees |
| $ | 1,805 |
|
| Nil |
|
|
|
(1) | Audit-related fees were for assurance and related services and costs reasonably related to the performance of the audit or review of the annual statements that are not reported under “Audit Fees”. |
|
|
(2) | Tax fees were for tax compliance, tax advice and tax planning provided by the Company’s external auditor. |
- 32 -
Computershare Investor Services Inc. of Canada, at its principal offices in Vancouver, B.C. and Toronto, Ontario, and Computershare Investor Services Limited in Auckland, New Zealand are the registrars and transfer agents for the Common Shares.
The following contracts, other than contracts entered into in the ordinary course of the Company’s business, are material to the Company and were entered into in the 2007 fiscal year or in a previous year but are still in effect:
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|
|
|
|
Document; Date |
| Parties |
| Particulars |
Gas Pre-payment |
| NGC Energy; |
| NGC lent the Company NZ$2 million for the right of first negotiation in respect to onshore NZ gas discoveries (refer to Note 20(a) of 2007 Financial Statements). |
|
|
|
|
|
Stock Option Plan |
| Employees & directors; |
| Stock Option Plan and grants thereunder pursuant to which 1,987,500 shares were reserved for issuance as at Dec 31, 2007. |
|
|
|
|
|
Gas Pre-Payment |
| NGC Energy |
| NGC lent IRM NZ$2.5 million for the right to purchase Kahili and Cheal gas at an agreed price (refer to Note 20(b) of 2007 Financial Statements). |
|
|
|
|
|
Asset Sale |
| International Resource Management Corporation (IRM) |
| Purchase by Arrowhead Energy of Cheal and Kahili assets from IRM, including transfer of obligations under Gas Pre-Payment Agreement (Feb 04). |
|
|
|
|
|
US$ Cash Advance |
| Investec Bank (Australia) Ltd; |
| Establishing a $23 million loan facility for a term of 4 years at commercial lending rates (refer to Note 21 of 2007 Financial Statements). |
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|
|
|
|
Warrant Agreement |
| Investec Bank; |
| Granted 2.5 million warrants to Investec exercisable at $2.11 per for 24 months share as partial consideration for the loan facility. |
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|
|
|
|
Unit Subscription |
| Various; |
| Private placement raising $3.25 million by the issue of 2,500,000 shares at $1.30 each, closing May 2007. |
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|
|
|
|
Share Sale |
| Shareholders of International Resource Management Corporation Ltd; |
| Purchase by Austral of all the shares in International Resource Management Corporation Ltd, later varied to clarify treatment of shareholder loans, closed November 12, 2007 (refer to Note 5(a) of 2007 Financial Statements). |
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|
|
|
|
Preferred Share |
| Eclectic/Republic; |
| Private placement raising $10 million by the issue of 7,692,308 Series 1 preferred shares at $1.30 each, closing September 20, 2007 (refer to “General Development of the Business – Corporate Developments”). |
- 33 -
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|
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|
|
Document; Date |
| Parties |
| Particulars |
Warrant Agreement |
| Morgan Keegan; |
| Granted 150,000 warrants to Morgan Keegan exercisable at $1.30 per share for 24 months as partial consideration for broker services (refer to “General Development of the Business – Corporate Developments”). |
| ||||
Unit Subscription |
| Various; |
| Private placement raising $15 million by the issue of 12.5 million units at $1.20 each (1 common share plus 1 12-month share purchase warrant exercisable at $2.25), closing February 28, 2008 (refer to “General Development of the Business – Corporate Developments”). |
The Company is not in legal proceedings with any other party. However, the following claims or disputes are in train:
i) Cheal Royalty: A dispute regarding the terms of a royalty payment required to be paid by the Company in respect of the Arrowhead interest acquired in the Cheal shallow joint operations. The total amount involved is unable to be accurately quantified because it relies on estimates of future oil price and production from the Cheal shallow oil joint operations for permit 38738. The estimated amount payable relating to historical production is $436,500. The company is in the process of seeking legal advice regarding the claim and is also in discussion with the party entitled to receive the royalty payment about the terms of the arrangement;
ii) Cheal Project: A number of interrelated claims and issues with TAG Oil (NZ) Limited (“TAG”) concerning the Cheal shallow joint operations and the development of the Cheal production facility. The Company is seeking legal advice to enforce the payment by TAG of its share of outstanding capital expenditure for completion of the production facility (amounting to approximately NZ$500k (US$388k)) and also payment of TAG’s share of operating expenditure for operation of the facility for 2008. TAG have written to the Company alleging the Company is liable for compensation to TAG in the amount of approximately NZ$7.78m (US$6.03m). The Company refutes the requirement to pay compensation to TAG and has received legal advice supporting the Company’s position;
iii) Douglas Permit: A dispute with Rift Oil regarding the performance of Rift as Operator for the PPL 235 license in Papua New Guinea in relation to the setting of the minimum work commitment for the year five and six (years 2008 and 2009) work program and the way the joint operations should give effect to the requirements. The Company is in the process of discussing its concerns with Rift, seeking clarification of circumstances and endeavouring to negotiate a resolution of its concerns with the operator. The Company has obtained legal advice supporting its position and, should a satisfactory resolution not be possible in discussion with the operator, the Company will be reviewing its legal options. Rift has commenced preparation for the drilling of a well and has cash called the Company share of that cost. The Company has rejected the validity of the cash call and Rift has now issued a notice of default. Legal advice received by the Company has challenged the validity of the cash call and the notice of default. The Company is in parallel endeavouring to resolve the issue with its joint operations party by discussion and agreement.
Those persons who are named as having prepared or certified a statement, report or valuation described or included in a filing or referred to in a filing made under National Instrument 51-102 by the Company during or relating to its December 31, 2007 year, and whose profession or business gives authority to the statement report or valuation made by the person or the Company are:
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| - Sproule International Limited, as to independent reports made on the Company’s reserves |
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| - KPMG, the Company’s auditors |
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To the best of the Company’s knowledge, none of these persons holds any interest in the securities of the Company.
Additional information about the Company may be found on the System for Electronic Document Analysis and Retrieval (“SEDAR”) atwww.sedar.com.
Additional financial information is contained in the Company’s audited financial statements and the Company’s Management’s Discussion and Analysis (“MD&A”) for the fiscal year ended 31 December 2007. These documents were filed electronically on SEDAR concurrently with this Form and are incorporated herein by reference and form an integral part of this Annual Information Form. Copies may be obtained from SEDAR website atwww.sedar.com.
Additional information including Directors’ and Officers’ remuneration and indebtedness (if any), principal holders of the Company’s securities and securities authorised for issuance under equity compensation plans is contained in the Company’s most recent Information Circular dated July 27, 2007, filed on SEDAR, and which will be updated for the Company’s Annual General Meeting to be held on May 22, 2008. A copy of the Circular may be obtained from the SEDAR website atwww.sedar.com.
The Company will provide to any company or person, upon request to the Secretary of the Company at its offices, a copy of this (its most recent) Annual Information Form, its Annual Report (which includes the Company’s audited financial statements and MD&A for the year ended December 31, 2007), its most recent Information Circular, financial statements including auditors’ report, and/or MD&A, provided that the Company may make a reasonable charge for copying and mailing if the request is made by a company or person who is not a registered or beneficial security holder of the Company. Such information is also available for download free of charge from the SEDAR website, as above, and from the Company’s website atwww.austral-pacific.com
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