Aminex Regulatory News (AEX)

Aminex plc

("Aminex" or "the Company")

PRELIMINARY RESULTS FOR THE YEAR ENDED 31 DECEMBER 2016

Aminex PLC ("Aminex" or "the Group" or "the Company") today announces its preliminary results for the year ended 31 December 2016.

Financial Highlights:

Operating Highlights:

Post year-end:

Aminex Chief Executive Officer, Jay Bhattacherjee, commented: "2016 was a transformative year with Aminex achieving first gas production from its Kiliwani North field, the introduction of a strategic investor and spudding the Ntorya-2 appraisal well, which subsequently tested at an average rate of 17 MMcfd. The Company is now looking forward to developing the resources in the onshore Ruvuma Basin, while gas revenues assist with the early repayment of corporate debt. We appreciate the continued trust that shareholders have put in management."

CHAIRMAN'S LETTER

Dear Shareholder,

Herewith are Aminex PLC's results for the year ended 31 December 2016. During the year, the Group recorded a loss of $2.53 million compared with a loss of $3.78 million in the previous year. Net assets at year end totalled $106.35 million, including net current assets of $11.00 million.

2016 was a landmark year for your Company in Tanzania.

In the early part of the year we started producing from the Kiliwani North-1 well into the new Tanzanian national pipeline system and production continues at approximately 16 MMcfd at the time of writing. Kiliwani North is Aminex's first African production and is making a positive impact on the Company's finances.

In the summer, the Company completed a placing of new shares together with an open offer to existing shareholders which raised $24.37 million after expenses in order to move forward a development-led work programme. The largest contributor to the placing was Eclipse Investments LLC, a division of the Zubair Corporation of Oman, which now holds a strategic stake of just under 30% of the Company's issued share capital. The Zubair Corporation, through its interest in ARA Petroleum LLC ("ARA"), had identified the long-term potential of our acreage in Tanzania and we have subsequently been pleased to welcome Mr. Ola Fjeld of ARA to our Board. Ola has a strong track record of successful operations in our industry and his participation and support is warmly appreciated. Since the fund raising, Philip Thompson, who joined Aminex in 2013, left the Company for personal reasons and we wish him well in the future.

Just before the year-end we spudded the Ntorya-2 appraisal well in the Ruvuma Basin, a follow-up to our earlier Ntorya-1 gas discovery. Since the year-end, we have successfully finished drilling this well, recording a 51-metre gross reservoir section with approximately 31 metres of net pay. Evidence of trace oil was found while drilling the reservoir section. The well was successfully tested and the Company is currently updating its basin model so as to determine the optimal development plan.

We have been working in Tanzania for a long time and have never lost our conviction that there is a major hydrocarbons play to be exploited. Earlier drilling successes at Kiliwani North and Ntorya were important milestones but our latest discovery at Ntorya-2 opens up a new era of development possibilities. We were also pleased to receive an extension to the Nyuni Area PSA in December 2016, which will enable us to accelerate activity on that licence. The Company remains focused on projects that have the potential for early cash flow and with infrastructure available, the Ruvuma PSA provides us with a great opportunity for development.

Aminex management and technical team has done a fine job in persevering with these projects through many difficulties, while all of us at the Company appreciate the support of shareholders who have stayed with us through good times and bad, as we look forward to an exciting future.

Yours sincerely,

Brian Hall

Chairman

 CHIEF EXECUTIVE'S REVIEW

Aminex has progressed strongly on many fronts during 2016 and early 2017, becoming a Tanzanian gas producer for the first time following Kiliwani North start-up and significantly advancing the production potential of the Ntorya Prospect in the Ruvuma Basin with the success of the recent Ntorya-2 appraisal well.

The loss for the period was $2.53 million compared with $3.78 million for the previous year. A full commentary on the results is provided in the Financial Review section.

Tanzania

Aminex's principal assets are its three interests in Tanzania.

(1) Ruvuma PSA. The results of the Ntorya-2 well test, announced since the year-end, endorse the Board's belief in the quality of the assets held by Aminex in the Ruvuma Basin. This well was drilled to a final total vertical depth of 2,795 metres and at 2,593 metres encountered a gross gas-bearing reservoir unit of approximately 51 metres with significant gas influx and high associated pressures. The well was tested and flowed dry, high quality gas at an average rate of 17 MMscfd (2,833 BOED) on a 40/64" choke. Strong pressure build-up occurred in all instances during the well test. Ntorya-2 also encountered traces of oil in the gross reservoir interval and the Company is updating its basin model to determine the optimal drilling depths for Ntorya-3 and for future development wells. Post analysis, Aminex will be able to revise its interpretation of in-place volumes.

Aminex will now apply for a 25-year development licence. Subject to tie-in, gas from the field can be produced into the National Gas Gathering System and the Company is also evaluating, with the Tanzania Petroleum Development Corporation ('TPDC'), early production options for monetising the gas. To allow for an effective review of the Ntorya-2 well results and development licence application, Aminex is requesting a further extension of time for the Mtwara Licence within the Ruvuma PSA. Discussions are ongoing simultaneously on an extension of the other part of the Ruvuma PSA, the neighbouring Lindi Licence, which officially ended in January 2017, as the Ntorya-Likonde prospects straddle the licence boundaries and development may be conducted in both licences for greater efficiency. The Board has a reasonable expectation of achieving a favourable outcome with the Tanzanian authorities.

(2) Kiliwani North. KN-1 has been producing gas into the new Songo Songo Island Gas Processing Plant since April 2016 and, since July, commercial rates have been averaging approximately 15 MMcfd. The gas is being sold at wellhead and has achieved an average price of $3.25 per Mcf, ahead of the predicted $3.07 per Mcf. The higher price is a result of (i) a higher calorific value than expected and (ii) price indexation. TPDC has not yet confirmed a commercial operations date and therefore has not finalised the agreed credit guarantees but production rates remain constant and regular payments are being received by Aminex in US Dollars.

(3) Nyuni Area PSA. The Company received the formal extension of the licence into the First Extension Period, currently due to end in October 2019. However due to delays in finalising the new arrangements, Aminex has requested that the four-year extension be effective from the date of grant of the First Extension Period in December 2016 and this is currently being considered by the authorities. Aminex now plans to re-tender for 3D seismic acquisition over the deep-water sector of the licence and in parallel is conducting a review of potential leads in the licence area and over the adjoining Kiliwani North block. The objective of this is to fast-track potential development opportunities, production from which could be tied back to the Songo Songo Island Gas Processing Plant.

Financial Position

The Company's successful capital raise in August 2016 was supported by Eclipse Investments LLC, part of the Zubair Corporation of Oman, which is now a 29.9% shareholder, and Majedie Asset Management, which now holds just under 10%. Strong, supportive shareholders will greatly assist development and the Company has now been able to advance its capital expenditure programme in Tanzania. At 31 December 2016, cash balances were $19.57 million while corporate debt had been reduced substantially to $4.93 million with repayments funded primarily from gas revenues. The Company has continued to pay down debt after the year-end and this remains a priority.

Evaluation of New Opportunities

The Company's management and technical team continues to evaluate and analyse new production-led business opportunities with a view to creating a well-balanced and larger company.

Looking Forward

Following the success of the Ntorya-2 well, the interpretation of results will be used to finalise the design for the Ntorya-3 well. Aminex is prioritising preparation of a development plan for Ntorya and will submit an application to the Tanzanian authorities for a 25-year development licence over the prospect with the intention of identifying and drilling development wells in the most cost effective manner. The Company proposes to monetise gas from Ruvuma as quickly as possible and will continue to work with TPDC on suitable early production systems, with the ultimate aim of supplying gas into the National Gas Gathering System. Production from Kiliwani North is being used to accelerate repayment of the Company's corporate debt facility in full ahead of the 31 January 2018 repayment date. The Group's ongoing overhead expenses are closely monitored although, as attention turns to development and production, the in-house technical team will be strengthened to meet expanding operations.

I would like to thank our staff and all those that have been associated with the Company's progress for their consistent hard work but most of all our shareholders for their continued support and trust.

Jay Bhattacherjee

Chief Executive

FINANCIAL REVIEW

Financing and future operations

In April 2016, the Kiliwani North gas field started production, initially for the supply of gas for testing and commissioning the new Songo Songo Island Gas Processing Plant. From July 2016, production was increased to a consistent rate which has averaged approximately 16 MMcfd during the second half of 2016, providing a strong revenue stream which has supported operations and contributed to retiring corporate debt.

In August 2016, Aminex completed a capital raising of approximately $24.37 million net of expenses, assisted by the introduction of a strategic investor, the Zubair Corporation, which now has a 29.9% shareholding in the Company. The funds raised were primarily to enable the drilling of the Ntorya-2 appraisal well and the planned Ntorya-3 exploration well. Ntorya-2 was spudded on 21 December 2016 and on 6 February 2017 reached a total depth of 2,795 metres. This well was subsequently tested and achieved an average flow rate of 17 MMcfd. Aminex plans to apply for a Ntorya development licence as the next stage for Ntorya.

As previously advised, the repayment of the corporate loan is a priority for the Board. In June 2016 Aminex negotiated and agreed an eighteen-month extension to the repayment date which expires on 31 January 2018. During the second half of 2016, Aminex repaid $4.5 million against the corporate loan from the receipt of gas revenues and the application of part of the Open Offer funds. Since the year-end, a further $2.40 million has been repaid reducing the corporate debt to approximately $3.0 million at the date of this report. Over the last two years, the Board has considered a number of refinancing options primarily to reduce the cost of the loan but with the regular revenues from Kiliwani North has concluded that the Company should focus on repaying the loan in full, targeting final repayment during the third quarter of 2017, well ahead of the agreed repayment date of 31 January 2018. Early repayment will reduce the interest burden from the loan and, by not refinancing the loan, the Company will not incur new loan and legal fees.

In April 2016 Aminex entered into an asset sale agreement for the sale of a 4.0263% interest (or a 3.825% interest net of a back-in for 5% by the Tanzania Petroleum Development Corporation ("TPDC")) in the Kiliwani North Development Licence to Solo Oil plc for a consideration of approximately $2.17 million. The first tranche of the sale, being $0.57 million for a 1.0526% interest, was concluded in April 2016. The second tranche for a 1.3158% interest did not meet the condition of completion within fifteen days of receipt of first revenue payments by the TPDC, although a third instalment for a 1.6579% interest remains effective. TPDC has indicated to the Company that it would like to participate in the joint venture by taking a 5% interest as permitted under the terms of the Nyuni East Songo Songo Production Sharing Agreement but as at the date of this report the transfer of interest has not concluded.

Revenues from Kiliwani North, the extension of the repayment period for and the planned early repayment of the corporate loan, the capital raising and the commitment of the new strategic investor all provide a strong financial base to enable Aminex to become a debt-free company, to meet its work commitments over the next twelve months and to fast-track its existing projects as well as seek new development opportunities.

Revenue producing operations

Revenues from continuing operations amounted to $4.93 million (2015: $0.35 million). The revenues included Aminex's share of gas production of 1.45 BCF from Kiliwani North-1, giving rise to gas revenues of $4.57 million (2015: $nil). The remaining revenues of $0.36 million (2015: $0.35 million) related to oilfield services comprising the provision of technical and administrative services to joint venture operations and sales of equipment to third parties. Cost of sales was $1.69 million (2015: $0.34 million) of which the depletion charge on Kiliwani North production amounted to $1.24 million (2015: $nil), with production costs for gas operations of $0.09 (2015: $nil) and $0.36 million (2015: $0.34 million) for oilfield services. The low gas production costs reflect the sale of gas from Kiliwani North-1 at wellhead. Accordingly, there was a gross profit of $3.25 million for the year compared with a gross profit of $0.01 million for the previous year.

Group administrative expenses, including depreciation and net of costs capitalised against projects, were $2.85 million (2015: $1.63 million). The expenses for the current period include a share-based payment charge of $0.81 million relating to executive share options granted in May 2016. No options were granted in the comparative period. On a like-for-like basis, excluding the share-based payment charge, the Group's administrative expenses for the period under review were $2.04 million, an increase of $0.41 million. The increase includes administrative expenses of $0.12 million for production operations which were previously capitalised to development assets. Management has continued to maintain strict expenditure controls and, where possible, to reduce overhead costs but continues to strengthen the technical team as the Company moves from exploration to production and development. The partial disposal of the Group's interest in the Kiliwani North Development Licence gave rise to a gain of $0.34 million (2015: gain $1.77 million). Following a review of the carrying value of assets, the Board has decided to reduce the fair value of the production payment receivable to $nil: the provision arising of $1.97 million recognises continuing non-payment of amounts due by Mayan Energy Limited (formerly Northcote Energy Limited), although Aminex is seeking settlement of outstanding receivables related to the 2014 sale of US assets. A further impairment provision of $0.02 million was made against available for sale assets. Impairment provisions and losses in the comparative year amounted to $2.24 million. The Group's resulting net loss from operating activities was $1.25 million (2015: $2.10 million).

Finance costs reflect an interest charge of $1.30 million (2015: $1.69 million). Of this, a charge of $1.26 million (2015: $1.64 million) relates to the corporate loan, while the unwinding of the discount on the decommissioning provision was $0.04 million (2015: $0.04 million).

The Group's net loss for the period amounted to $2.53 million (2015: $3.78 million).

Balance sheet

The Group's investment in exploration and evaluation assets increased from $79.86 million at 31 December 2015 to $84.62 million at 31 December 2016. The increase reflected well planning for two Ntorya wells, the initial costs of the Ntorya-2 appraisal well spudded on 21 December 2016, as well as licence expenses for the Ruvuma PSA and the Nyuni Area PSA. After review, the Directors have concluded that there is no impairment to these assets, which include the cost of the Ntorya-1 gas discovery. The carrying value of property, plant and equipment has decreased from $12.42 million at 31 December 2015 to $11.22 million at 31 December 2016. The net decrease of $1.20 million reflected the depletion charge of $1.24 million and the amount of $0.13 million released on the part disposal of an interest in the field in April 2016 offset by additions of $0.17 million. Non-current trade and other receivables relate to the fair value of production payments due from the US amounting to $1.97 million at 31 December 2015, which has reduced to a fair value of $nil in the year under review. Current assets comprise trade and other receivables of $9.18 million, including the gross receivable of $5.90 million due from TPDC for gas revenues, and cash and cash equivalents of $19.57 million.

Under current liabilities, loans and borrowings of $4.93 million relate to the corporate loan (see commentary under Going Concern below) which had reduced from $8.56 million at the 31 December 2015 following repayments amounting to $4.5 million offset by additional interest. The outstanding loan amount has been reduced by repayments of a further $2.4 million since the period end. Trade payables amounted to $12.83 million. The non-current decommissioning provision increased from $0.45 million at 31 December 2015 to $0.48 million, the net increase arising on the release of $0.01 million on the partial disposal of the interest in Kiliwani North offsetting the unwinding of the discount charge of $0.04 million for the period. Total equity has increased by $21.48 million between 31 December 2015 and 31 December 2016 to $106.35 million. The net movement comprises the increase in issued capital and share premium of $25.92 million arising from the capital raise completed in August; the foreign currency translation reserve has increased by $1.56 million as a result of a stronger US dollar; and the movement of $3.48 million in retained earnings comprises the loss of $2.53 million for the year and the cost of $1.55 million for the capital raise offset by a release of $0.60 million from the share option reserve.

Cash Flows

The net increase in cash and cash equivalents for the year ended 31 December 2016 was $17.44 million compared with an increase of $0.36 million for the comparative period. The Company raised net proceeds of $24.37 million on the issue of new equity through a capital raise in August 2016. During the period, the Group also received $0.57 million net consideration for the part-disposal of the Kiliwani North Development Licence. Net cash outflows from operating activities amounted to $3.20 million (2015: $2.50 million). Expenditure on exploration and evaluation assets in the current period amounted to $2.11 million (2015: $1.00 million), relating to the Ntorya-2 appraisal well spudded on 21 December 2016 on the Ruvuma PSA acreage, together with continuing licence costs. Expenditure on property, plant and equipment was $0.13 million for pre-production expenditure on the Kiliwani North licence and the acquisition and installation of a new wellhead control panel since production started. The cash balance at 31 December 2016 was $19.57 million (31 December 2015: $2.13 million).

Going concern

The Directors have given careful consideration to the Group's ability to continue as a going concern. The Group continuously monitors and manages its cash flow and liquidity risk. Cash forecasts are regularly updated and sensitivities are run for different scenarios, including the production flow and timing of cash flow from the Group's Kiliwani North producing asset, the timing and cost of the Group's drilling and exploration activities and the timing of corporate loan repayments. The Directors have concluded that, following consideration of the Group's cash forecasts and taking account of the capital raise in August 2016 which raised approximately $24.37 million net of transaction costs, the Group has sufficient capital resources from both ongoing operating cash flows and existing cash resources to continue as a going concern for the foreseeable future, that is a period of not less than 12 months from the date of approval of this preliminary statement and accordingly, they are satisfied that it is appropriate to adopt the going concern basis of accounting in the preparation of the financial statements. The Group's ability to continue to make planned capital expenditure, in particular on its main licence interests in Tanzania, can be assisted if necessary by the successful sale of assets, deferral of planned expenditure or an alternative method of raising capital. The Directors have a reasonable expectation that the Group would be able to implement one or more of these mitigating actions should it be required.

Max Williams

Finance Director

OPERATIONS REPORT

TANZANIA

Kiliwani North Development Licence - Production

The Kiliwani North-1 gas well ("KN-1") came on stream on 4 April 2016, representing Aminex's first production in Tanzania. Production rates for the period to 30 June 2016 were determined by the plant operator and in line with normal requirements for testing and commissioning procedures for the new Songo Songo Island Gas Processing Plant ("SSIGPP"). This plant has a 140 MMscfd processing capacity. Since early July, the well has been producing at commercial rates but remains under commissioning conditions. Average production during the second half of the year was approximately 15 MMcfd with up to 100 barrels of condensate. The rate has continued at this level post year-end and in February 2017 a new well head control panel, purchased in late 2016, was installed. Commercial gas from Kiliwani North is sold at wellhead and is being delivered into the Tanzanian National Gas Gathering System. A 24-inch spur line from the SSIGPP connects Kiliwani North to a 532 km 36-inch pipeline which transmits gas to Dar es Salaam.

A resource report by LR Senergy, completed in May 2015, attributed approximately 28 BCF gross best estimate Contingent Resource to the Kiliwani North field. The Company notes that, as a result of continued production following a long period when the well was shut-in, the wellhead pressure is declining and the Company is reviewing possible alternatives for remediation in the near future to maximize recoverable resources. In the absence of a commercial operations date for the Kiliwani North-1 well, the Company is planning to update its resource report. First revenues were received during August 2016 and, although credit guarantees from Tanzania Petroleum Development Corporation ("TPDC") are only required to be completed once TPDC has formally declared a commercial operations date under the Kiliwani North Gas Sales Agreement ("GSA") which was signed at the start of the year, production continues at commercial levels and regular payments have been received. The GSA guarantees pricing at $3.00 per mmbtu (approximately $3.07 per mcf) with yearly adjustment based on a United States Consumer Price Index. Due to a higher calorific value for the gas than anticipated and the effect of the indexation allowance, the gas has in practice been sold at an average of approximately $3.25 per mcf.

As part of continuing work over its near-shore interests under the Kiliwani North Development Licence and the Nyuni Area PSA, Aminex is conducting a review of existing seismic data to identify drillable prospects which could be tied back to the National Gas Gathering System on Songo Songo Island.

The TPDC has notified Ndovu Resources Limited that it intends to take up its 5% share of production in accordance with the Nyuni East Songo Songo Production Sharing Agreement which governs the Kiliwani North Development Licence. However it has not yet finalised its participation in the joint operating agreement and Aminex's working interest, held through Ndovu Resources Limited, has therefore remained at 57.4474% (net revenue interest of 50.5537%) following a part disposal to Solo Oil plc in April 2016. The transfer of a 5% interest from partners to TPDC is now expected to be completed in 2017.

In April 2016 Aminex entered into an asset sale agreement for the sale of a 4.0263% interest (or 3.825% assuming the TPDC had completed the exercise of its right to participate with a 5% interest) in the Kiliwani North Development Licence to Solo Oil plc for a consideration of approximately $2.17 million. The first tranche of the sale, being $0.57 million for a 1.0526% interest was concluded in April. The second tranche for a 1.3158% interest did not complete, although a third instalment for a 1.6579% interest remains to be completed on the confirmation of the commercial operations date by TPDC.

Ruvuma PSA - Onshore Appraisal and Exploration

Aminex spudded the Ntorya-2 appraisal well on 21 December 2016 which was successfully drilled to a total vertical depth of 2,795 metres post year-end. At 2,593 metres drilling depth the well encountered a gross gas bearing reservoir unit of approximately 51 metres. Petrophysical analysis indicated a net hydrocarbon bearing reservoir section of approximately 31 metres. Drilling of the reservoir section was associated with significant gas influxes with high associated pressures. Subsequent to wireline logging, a 7-inch liner was run and cemented in place from 1,967 to 2,795 metres. Detailed petrophysical analysis will be conducted on both the LWD and wireline logs.

The well was perforated over a gross interval of 34 metres. It underwent a testing programme for a period of 160 hours and flowed gas across a variety of choke sizes. The well flow tested at an average rate of 17 MMscfd (2,833 BOED) on a 40/64" choke. Strong pressure build-up occurred in all instances during the well test.

According to wireline logs, Ntorya-2 encountered the equivalent reservoir section at approximately 74 metres higher than in the Ntorya-1 well. Ntorya-2 also encountered traces of oil in the gross reservoir interval and the Company is updating its basin model to determine the optimal drilling depths for Ntorya-3 and for future development wells. Post analysis, Aminex will be able to revise its interpretation of in-place volumes.

Ntorya-2 was drilled in the onshore Ruvuma Basin to appraise further the Ntorya location area where the Ntorya-1 gas discovery drilled by the Company showed net pay of 3.5 metres and flow-tested at 20 million cubic feet per day, with 139 barrels of associated condensate. The Ntorya field is approximately 40 kilometres from the Madimba gas processing plant, which receives gas into the Tanzanian National Gas Pipeline system. Ntorya-2 completes the appraisal drilling obligations for the Ntorya location area.

The Company will apply for a 25-year development licence over the Ntorya prospect and is currently preparing a development plan to be submitted to the Tanzanian authorities for approval.

A resource report by LR Senergy, completed in May 2015, attributed approximately 70 BCF gross best estimate Contingent Resource to the Cretaceous channel associated with the Ntorya-1 gas discovery. The results of the Ntorya-2 well drilled into the same Cretaceous channel but updip to Ntorya 1 will now be integrated with the previous study and an updated independent resources report prepared.

The next well location in the programme, Ntorya-3, was identified from 2D seismic acquired in 2014 and intersects the thickest part of the main Cretaceous channel based on the 2D seismic data currently available. The Ntorya-3 reservoir is expected to be encountered further up-dip from Ntorya-1 and Ntorya-2 and envisages testing a further 323 BCF as independently attributed by LR Senergy gross best estimate Prospective Resource (945 BCF gross Pmean gas in-place) across multi-zone potential. The well pad was prepared following the completion of the pad for Ntorya-2, but the well design for Ntorya-3 will depend on final interpretation of Ntorya-2 in order to intersect multiple stratigraphic units in the area which are potentially both oil and gas bearing.

The Ruvuma PSA provides Aminex with a combination of exploration, appraisal and potential development activity. The key to unlocking the commercial potential for these opportunities is the common-user gas pipeline which runs from the south-east of Tanzania to Dar es Salaam. The pipeline and associated facilities have been operational since 2015 and provide a means of marketing gas discoveries at Ruvuma through selling gas to the TDPC. In addition, Aminex is reviewing options for an early production system, such as compressed natural gas or gas-to-power, in order to commercialise discoveries with an initial low capital outlay, although the long-term plan is to connect the gas field by a spur line to new infrastructure. As well as the Ntorya wells, several further prospects were identified from the 2014/2015 mapping, including potential prospects at Likonde and Namisange. During 2016, Aminex received formal Ministerial approval for the extension by one year of the Mtwara Licence of the Ruvuma PSA to 8 December 2017. Although the Lindi Licence technically expired on 28 January 2017, negotiations are ongoing for the extension of the Lindi Licence and its work commitments and, in conjunction with the Mtwara Licence discussions, the Directors have a reasonable expectation that an extension will be granted.

Under the terms of the Ruvuma PSA, after the grant of a development plan, TPDC may elect to contribute 15% of development costs, in order to obtain a participating interest of 15% in production and revenues. 

Nyuni Area PSA - Onshore, Shelf and Deepwater Exploration

In December 2016, a four-year licence for the First Extension Period of the Nyuni Area PSA was granted. The work commitment for the new licence period reflects the amended terms of 3D seismic data acquisition over the deep-water sector of the licence and the drilling of four exploration wells. The licence post relinquishment covers ten blocks, providing a balance of leads in the deep-water and on the continental shelf close to Songo Songo Island. The licence period has been backdated to the end of the Initial Work Period and is therefore scheduled to expire in October 2019. However, Aminex, through its subsidiary company Ndovu Resources Limited, has appealed the start date on the grounds that the delays in finalising the grant of licence were outside the Company's control. The grant of the licence extension crystallised the deferral of the outstanding work commitments from the Initial Work Period into the First Extension Period, as well as the statutory relinquishment of 50% of the licence blocks. The Licence now comprises five blocks over the deep water and five over the continental shelf.

The Company focus remains on projects which will deliver commercial gas in the near term. A re-tender process is planned to select a 3D seismic contractor capable of acquiring high quality 3D seismic over the key Pande West lead and to identify other potential prospects in the deep water with a view to bringing them to drill-ready status. Pande West is analogous to some of the recent major deep water discoveries in the vicinity. The drilling success rate achieved by other operators, based on 3D seismic in the main fairway east of Nyuni Area, is over 90%. The Company is reviewing ways to enable the potential monetisation of discoveries on the shelf and deep water through delivery into the National Gas Gathering System. Although the Company is unlikely to be in a position to drill an expensive deep water well in the Nyuni Area without introducing a larger company as a farm-in partner, the possibility of drilling wells on the continental shelf more economically remains an option. As part of continuing work over its near-shore interests under the Kiliwani North Development Licence and the Nyuni Area PSA, Aminex is conducting a review of existing data to identify drillable prospects which could be tied back to the National Gas Gathering System on Songo Songo Island.

Following the withdrawal of RAK GAS LLC from the licence in 2015 and in accordance with the terms of the joint operating agreement, the partners assume their proportionate share of the withdrawing partner's interest. With the grant of the extension to the licence, Aminex expects the partners to determine their interests going forward.

Under the terms of the Nyuni Area PSA, after the grant of a development plan TPDC may elect to contribute 20% of costs, excluding exploration costs, in order to obtain a participating interest of 20% in production and revenues.

EGYPT - Onshore Exploration

Aminex retains a 1% gross overriding royalty on all sales revenues from the South Malak-2 gas discovery well in excess of $2.5 million. This well is not yet on production.

Group Income Statement

for the year ended 31 December 2016

Group Statement of Comprehensive Income

for the year ended 31 December 2016

Group Balance Sheet

 at 31 December 2016

Group Statement of Changes in Equity

for the year ended 31 December 2016

Group Statement of Cashflows

for the year ended 31 December 2016

Notes to the Financial Information for the year ended 31 December 2016

1 Statement of accounting policies

The financial information has been prepared in accordance with International Financial Reporting Standards as adopted by the EU (EU IFRSs).

Basis of preparation

At the date of issue of this announcement the Group's statutory financial statements for the year ended 31 December 2016, and therefore the result showing in the announcement, are unaudited. In the opinion of the Directors, the announcement includes all adjustments necessary for a fair presentation of the results for the periods presented.

The accounting policies used are consistent with those set out in the audited Annual Report for the year ended 31 December 2015, which is available on the Company's website, www.aminex-plc.com, except as noted below.

i) New accounting standards and interpretations adopted

Below is a list of standards and interpretations that were required to be applied in the year ended 31 December 2016. There was no material impact to the financial statement in the current year from these standards set out below:

ii) New standards and interpretations not adopted

Standards that are not yet required to be applied but can be early adopted are set out below. None of these standards have been applied in the current period. There would not have been a material impact to the financial statements if these standards had been applied in the current accounting period. These will be applied as required on a prospective basis.

The following standards have been issued by the IASB but have not yet been endorsed by the EU, accordingly none of these standards have been applied in the current period and the Group is currently assessing whether these standards will have a material impact on the financial statements.

ii) New standards and interpretations not adopted (continued)

Going concern

The Directors have given careful consideration to the Group's ability to continue as a going concern. The Group continuously monitors and manages its cash flow and liquidity risk. Cash forecasts are regularly updated and sensitivities are run for different scenarios, including the production flow and timing of cash flow from the Group's Kiliwani North producing asset, the timing and cost of the Group's drilling and exploration activities and the timing of corporate loan repayments. The Directors have concluded that, following consideration of the Group's cash forecasts and taking account of the capital raise in August 2016 which raised approximately $24.37 million net of transaction costs, the Group has sufficient capital resources from both ongoing operating cash flows and existing cash resources to continue as a going concern for the foreseeable future, that is a period of not less than 12 months from the date of approval of this preliminary statement and accordingly, they are satisfied that it is appropriate to adopt the going concern basis of accounting in the preparation of the financial statements. The Group's ability to continue to make planned capital expenditure, in particular on its main licence interests in Tanzania, can be assisted if necessary by the successful sale of assets, deferral of planned expenditure or an alternative method of raising capital. The Directors have a reasonable expectation that the Group would be able to implement one or more of these mitigating actions should it be required.

2 Operating segments

The Group considers that its operating segments consist of (i) Producing Oil and Gas Properties, (ii) Exploration Activities and (iii) Oilfield Services and Supplies. These segments represent are those that are reviewed regularly by the Chief Executive Officer (Chief Operating Decision Maker) to make decisions about resources to be allocated to the segment and assess its performance and for which discrete financial information is available. However it further analyses these by region for information purposes. Segment results include items directly attributable to the segment as well as those that can be allocated on a reasonable basis. Unallocated items comprise mainly head office expenses, cash balances and certain other items.

3 Finance income

4 Finance costs

Included in finance costs for the period is an interest charge of US$1.26 million in respect of the US$8 million corporate loan facility which has been calculated using the effective interest rate method. As a consequence of the share placing during the year, a further 74,984,577 warrants were issued to the lender in accordance with the terms of the agreement. These were fair valued on the date of the grant at US$382,000 and this amount was expensed to the income statement using the effective interest rate method.

5 Loss per Ordinary Share

The basic loss per Ordinary Share is calculated using a numerator of the loss for the financial year and a denominator of the weighted average number of Ordinary Shares in issue for the financial year. The diluted loss per Ordinary Share is calculated using a numerator of the loss for the financial year and a denominator of the weighted average number of Ordinary Shares outstanding and adjusting for the effect of all potentially dilutive shares, including share options and share warrants, assuming that they had been converted.

The calculations for the basic loss per Ordinary Share for the years ended 31 December 2016 and 2015 are as follows:

There is no difference between the basic loss per Ordinary Share and the diluted loss per Ordinary Share for the years ended 31 December 2016 and 2015 as all potential Ordinary Shares outstanding are anti-dilutive. There were 128,475,000 (2015: 19,315,000) share options issued which are anti-dilutive as at 31 December 2016 and 167,561,032 (2015: 92,576,455) warrants in issue at 31 December 2016.

6 Exploration and evaluation assets

The Group does not hold any property, plant and equipment within exploration and evaluation assets.

The Directors have considered the licence, exploration and appraisal costs incurred in respect of its exploration and evaluation assets. These assets are carried at historical cost except for provisions against the Nyuni-1 well, the cost of seismic acquired over relinquished blocks and obsolete stock. These assets have been assessed for impairment and in particular with regard to the remaining licence terms, likelihood of renewal, likelihood of further expenditures and ongoing acquired data for each area, as more fully described in the Operations Report. During the year, the Tanzanian authorities granted an extension to the Nyuni Area licence which has a licence period ending in October 2019 and which crystallised previous arrangements for the deferral of licences commitments from the initial Work Period and proposed relinquishment blocks against which provision was made in the year ended 31 December 2015. The Tanzanian authorities also granted a one-year extension to the Mtwara Licence, which together with the Lindi Licence, comprises the Ruvuma Production Sharing Agreement. The Mtwara Licence, which includes the Ntorya appraisal area, has a scheduled expiry date in December 2017. The Directors have also taken into account ongoing negotiations with the Tanzanian authorities over the extension to the Lindi Licence. The Lindi Licence was scheduled to expire in January 2017 but the Directors have a reasonable expectation of obtaining an extension to the Lindi Licence. If the Lindi Licence is not extended, an impairment against the carrying value of the Lindi Licence, which includes the Likonde-1 well, may be necessary. The Directors are satisfied that there are no further indicators of impairment but recognise that future realisation of these oil and gas assets is dependent on further successful exploration, appraisal and development activities and the subsequent economic production of hydrocarbon reserves.

Prior to August 2015, Aminex had a 10% beneficial interest in the South Malak-2 well on the West Esh el Mallaha-2 concession in Egypt through its 12.5% shareholding in Aminex Petroleum Egypt Limited. Aminex's interest in this PSC was free-carried by a partner through to first commercial production and the Company therefore had no day-to-day control over the timing of drilling operations. In August 2015, Aminex entered into an agreement to sell its carried interest in the West Esh el Mallaha-2 licence, on which the South Malak-2 gas discovery was made earlier in the year. In order to optimise the Company's commercial interest in the discovery, over which it had no operational control, Aminex agreed to sell its shareholding in Aminex Petroleum Egypt Limited, together with its indirect carried interest, to a fellow shareholder in return for a 1% gross overriding royalty on all sales revenues from the discovery well in excess of US$2.5 million. The carrying value of this asset at 31 December 2016 and 31 December 2015 was US$nil.

7 Property, plant and equipment

As at 31 December 2016, "Other assets" comprises plant and equipment US$9,000 (2015: US$5,000), and fixtures and fittings US$5,000 (2015: US$1,000). In the prior year, "Other assets" included leasehold property of US$5,000.

Following the award of the Kiliwani North Development Licence by the Tanzanian Government in April 2011, the carrying cost relating to the development licence was reclassified as a development asset under property, plant and equipment, in line with accounting standards and the Group's accounting policies. Production from the Kiliwani North-1 well commenced on 4 April 2016 and the depletion charge for the year has been calculated with reference to the contingent resources ascribed to the field in 2015. The resources remain contingent on the notification of a commercial operations date by the TPDC in accordance with the Gas Sales Agreement. The Directors have reviewed the carrying value of the asset at 31 December 2016 based on estimated discounted future cashflows and are satisfied that no impairment has occurred.

During the year, the Company disposed of 1.0526% of its interest in the Kiliwani North Development Licence. During the prior year, the Company disposed of 6.5% of its interest in the Kiliwani North Development Licence.

8 Decommissioning provision

Decommissioning costs are expected to be incurred over the remaining lives of the wells, which are estimated to be between 2021 and 2028. The provision for decommissioning is reviewed annually and at 31 December 2015 and 2016 relates to wells in Tanzania. The provision has been calculated assuming industry established oilfield decommissioning techniques and technology at current prices and is discounted at 10% per annum, reflecting the associated risk profile.

9 Trade and other long-term receivables

Non-current trade and other receivables that fall due after one year relate to part of the consideration arising from disposal in 2014 of Aminex USA, Inc. and comprise a production payment per barrel until a total of US$4.5 million has been recovered. The Directors have reviewed the timing of anticipated production payments and consider these are unlikely to be recovered and are satisfied that the net present value of US$nil (2015: US$1,971,000, using a discount factor of 15%) represents the fair value of future expected production payments. The impairment of US$1,971,000 has been expensed in the income statement in the current year.

10 Issued capital

At an Extraordinary General Meeting held on 2 August 2016, shareholders approved the increase in the authorised share capital by €2,000,000 to €64,000,000 comprising 2,000,000,000 Ordinary Shares of €0.001 each. At the same meeting, the shareholders approved a capital raise for proceeds of US$24.37 million (net of transaction expenses) through the issue of 1,499,691,550 Ordinary Shares of nominal value €0.001 each at Stg1.3 pence per Ordinary Share. The capital raise comprised a placing of 1,302,071,002 Ordinary Shares and an Open Offer whereby existing shareholders subscribed for 98,175,162 Ordinary Shares. On 4 August 2016, a further placing of 99,445,386 Ordinary Shares was completed at the same issue price.

The increase during the year in Ordinary Share capital and share premium of the Company related to the following:

11 Capital Commitments - exploration activity

In accordance with the relevant Production Sharing Agreements, Aminex has a commitment to contribute its share of the following outstanding work programmes:

(a) Following the grant of the extension to the Nyuni Area PSA, Tanzania, the terms of the licence require the acquisition of 600 kilometres of 3D seismic over the deep-water sector of the licence, and drilling of four wells, on the continental shelf or in the deep-water, by October 2019.

(b) The Ruvuma PSA, Tanzania, comprises two licences. The Mtwara Licence has been extended to December 2017 and two wells are required to be drilled, one of which is expected to be the Ntorya-3 location. The Company is seeking an extension to the Lindi Licence, which also requires two wells to be drilled.

12 Related party transactions

During the course of the year, the Group entered into the following related party transactions: fees amounting to US$27,000 (2015: $31,000) which were paid to Upstream Solutions Limited, a company connected with Mr. T.A. Mackay.

13 Post balance sheet events

In February 2017, Aminex, through its wholly-owned subsidiary company Ndovu Resources Limited, announced the completion of drilling operations for the Ntorya-2 appraisal well. The well was subsequently tested and in March 2017 it was announced that Ntorya-2 flowed at an average flow rate of 17 MMcfd.

14 Statutory information

The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2016 or 2015 within the meaning of the Companies Act, 2014. The statutory accounts for 2016 will be finalised on the basis of the financial information presented by the Directors in the preliminary announcement and together with the independent auditor's report thereon will be delivered to the Companies Registration Office following the Company's Annual General Meeting. The statutory accounts for 2015, including an unqualified audit report thereon, were filed with the Companies Registration Office.  The 2016 Annual Report and financial statements will be posted to shareholders shortly.

15 Estimates, key risks and uncertainties

The preparation of financial information requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, income and expense. Actual results may differ from these estimates. Key estimates and judgments related to the preparation of this financial information relate to notes 6 (Exploration and evaluation assets), 7 (Property, plant and equipment), 8 (Decommissioning provision) and 9 (Trade and other long-term receivables) and these were the same as those applied in the most recent published financial information for the Group. Principal risks and uncertainties affecting the Group relate to exploration and production risk, commodity and currency prices, finance risk relating to uncertain factors detailed in the basis of preparation relating to the Company as a going concern and other political risks particular to the countries in which we operate, as more fully described in the operations report, and in Aminex's most recent published financial statements.

16 Board approval

The Board of Directors approved the preliminary financial statements for the year ended 31 December 2016 on 6 April 2017.