Aminex Regulatory News (AEX)

2017 HALF-YEARLY REPORT

Aminex PLC ("Aminex" or "the Group" or "the Company") announces its half-yearly report for the six months ended 30 June 2017.

FINANCIAL HIGHLIGHTS

· Profit for the period of $1.01 million (30 June 2016: loss $2.45 million)

· Repayment of the corporate loan: Aminex now debt-free

· Cash balance of $6.91 million at 30 June 2017

OPERATING HIGHLIGHTS

· Successful completion and testing of the Ntorya-2 appraisal well at 17 MMcfd

· Ntorya-2 well encountered 31 metres of high quality net gas pay

· Average production from Kiliwani North-1 of approximately 15 MMcfd for the first half of 2017

POST PERIOD

· Upgrade of management estimate of Ntorya field to unrisked Pmean gas initially in place to 1.3 TCF

· Submission of development plan and application for Ntorya field development licence

· Commissioning of gas commercialisation study

Aminex CEO, Jay Bhattacherjee, commented:

"We are pleased to report to shareholders a return to profit during the first half of the year. During 2017, Aminex successfully drilled the Ntorya-2 appraisal well, which tested at approximately 17 million cubic feet per day, increased management's estimate of the Pmean unrisked resource estimates for the Ntorya field to approximately 1.3 TCF and submitted a development plan for, together with the application for, a development licence over the Ntorya field. The Company also repaid all of its outstanding corporate debt so that it is now a debt-free company. With this base, the Board believes the Company is well placed to build on success."

Chief Executive's Review

Aminex PLC's Interim Results for the six months ended 30 June 2017 are set out below. During the reporting period the Company returned to profit, repaid its corporate loan facility in full and completed a significant appraisal well in the onshore Ruvuma basin of Tanzania. Work completed since the period end has enabled the Company to announce a major increase in its gas resources.

Profit for the period was $1.01 million compared to a loss of $2.45 million for the six-month period ended 30 June 2016. A commentary on the results is provided in the Financial Review section below.

In February, the Group successfully reached final drilling depth on its operated Ntorya-2 appraisal well in the onshore Ruvuma Basin, Tanzania. At 2,593 metres drilling depth the well encountered a gross gas bearing reservoir unit of approximately 51 metres. The well was subsequently tested at a stabilised rate of 17 MMcfd, although only a limited section of the reservoir was perforated due to mud-induced damage. Since the completion of testing the Company has updated its basin model, including mapping, and management unrisked Pmean resource estimates over the Ntorya area are now approximately 1.3 TCF. The Company is currently in the process of engaging a third-party reserves auditor to update its reserves and resources.

With increasing resource estimates in the Ntorya area, the Company has engaged io oil & gas consulting, a joint venture between Baker Hughes (a GE company) and McDermott, to prepare a gas commercialisation study which will assist with and accelerate the development of the field and, most importantly, identify possible early monetisation opportunities for the project. A development plan has been submitted and application made to the Ministry of Energy and Minerals for a 25-year development licence for the Ntorya area, which is supported by the TPDC.

The Kiliwani North-1 well continues to provide positive cash flow and averaged approximately 15 MMcfd during the first six months of 2017. The gas is sold and paid for in US Dollars and the current gas price is $3.27 Mcf (based on $3.00 per mmBTU, annually adjustable through indexation): the contract price is not affected by movements in global markets for oil and natural gas. Although some delays in payment were experienced early in the year, regular payments have been received from the TPDC in recent months.

During the first half of 2017 Aminex has strengthened its financial base, significantly increased its resource potential and further strengthened its team through the appointment of key new executives. All these will enable the Company to progress the onshore Ruvuma Basin to the next stage and the Board looks forward to the future with confidence.

Jay Bhattacherjee

Chief Executive

28 September 2017

Operations Report

Tanzania - Kiliwani North

Production from the Kiliwani North-1 well during 2017 averaged approximately 15 MMcfd during the reporting period. In the comparative period, production which commenced on from 4 April 2016 was limited to support the testing and commissioning of the new Songo Songo Island Gas Processing Plant ("SSIGPP").

Production rates are determined by the plant operator and are based on normal requirements for testing and commissioning procedures for the SSIGPP. This plant has a 140 MMcfd processing capacity. 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.

The Company has prepared a programme to re-enter the Kiliwani North-1 well to gather downhole data later in the year and shareholders will be advised accordingly. 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 possible 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 maximise 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 for this asset as well as for its other assets in Tanzania. Due to a higher than specified calorific value for the gas and an advantageous effect of the sales contract's indexation allowance, gas has been sold during the reporting period at approximately $3.27 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.

Tanzania - Ruvuma PSA

Aminex spudded the Ntorya-2 appraisal well on 21 December 2016 and this was successfully drilled to a total vertical depth of 2,795 metres. At 2,593 metres drilling depth the well encountered a gross gas-bearing reservoir unit of approximately 51 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 identified 31 metres of net pay.

The well was perforated over a gross interval of 34 metres and underwent a testing programme for a period of 160 hours, flowing gas across a variety of choke sizes. The well flow-tested at an average rate of 17 MMcfd (approximately 2,800 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. Data from Ntorya-2 is being incorporated into an updated basin model for the Ruvuma PSA in order to evaluate the additional targets and liquids potential in the basin.

Utilising data acquired during the drilling of Ntorya-2, Aminex has been able to update the Pmean un-risked GIIP resource estimates for the Ntorya discovery to approximately 1.3 TCF. The continuing work on mapping and basin model studies may further refine these estimates. These management estimates substantially exceed an independent resource report by LR Senergy, completed in May 2015, which attributed an approximately 70 BCF gross best estimate Contingent Resource to the Cretaceous channel associated with the Ntorya-1 gas discovery. Using the well results, updated mapping and the commercialisation study the Group plans to commission a new independent resources report in due course.

Ntorya-2 was drilled in the onshore Ruvuma Basin to appraise further the Ntorya location area where the Ntorya-1 gas discovery previously drilled by the Company showed net pay of 3.5 metres and flow-tested at 20 MMcfd, 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.

In September 2017, the Group submitted a development plan for the Ntorya appraisal area and has applied for the grant of a 25-year development licence. The development plan is subject to the review and approval of the Tanzanian authorities and the Company will provide an update on this and the timing for spudding the Ntorya-3 well during Q4 2017. As part of the development licence application and also to identify ways to maximise returns from the discovery by the Company, Aminex appointed io oil & gas consulting, a joint venture between Baker Hughes (a GE company) and McDermott, to prepare a gas commercialisation study to assist with the development of the Ntorya field. The study has been designed to identify gas monetisation options available to the Company including potential early development facilities to supply gas to local market and enable near term revenue generation.

The Ruvuma PSA comprises two licence areas: the Mtwara Licence and the Lindi Licence. As well as the Ntorya wells, several further prospects in the Ruvuma acreage on both Licences have been identified from the 2014/2015 mapping, including potential prospects at Likonde and Namisange. During 2016, Aminex received formal ministerial approval for a one-year extension to 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 an extension to this licence to enable the work commitments to be carried out in conjunction with the Mtwara Licence area. The Company has also applied for a two-year extension to the Mtwara Licence, which includes the Ntorya appraisal licence, and the Directors have a reasonable expectation that both extensions will be granted pending ministerial approval.

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

Tanzania - Nyuni Area

Aminex remains focused on projects which will deliver commercial gas in the near term. A new 3D seismic programme is being prepared based on the licence area post relinquishment. Aminex expects to re-tender based on the new programme in order 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.

Aminex 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.

The First Extension Period was granted in December 2016 backdated to October 2015. The Company, which believes that the four-year extension period should start in December 2016, is seeking clarification from the TPDC on the start date for the current licence extension period.

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

Financial Review

Financing and Future Operations

In the first six months of 2017, Aminex has achieved a number of significant advances in securing the foundations for its future growth.

During the period, Aminex applied the cash flow from Kiliwani North operations to the repayment of the corporate loan and in June Aminex repaid the outstanding balance. The loan repayment was assisted by the exercise of warrants in May which gave rise to the gross receipt of $2.18 million in new equity issued. Full repayment of the corporate debt has been part of the Company's strategy and the Board is pleased that this has been achieved earlier than anticipated in this financial year.

Continued average daily production from Kiliwani North of approximately 15 MMcf has enabled the Company to report a profit of $1.01 million for the first six months of 2017 compared to a loss of $2.45 million for the first six months of 2016. At 30 June 2017 Aminex was therefore a debt-free and profitable production company.

The Board continues to assess alternative means of financing its operations following completion of the successful Ntorya-2 appraisal well in March which flowed gas at approximately 17 MMcfd. As well as planning Ntorya-3, Aminex is seeking alternative methods of funding future development operations at Ntorya, including early production options which could provide additional revenues to the Group.

Revenue Producing Operations

Revenues from continuing operations amounted to $4.59 million (30 June 2016: $0.26 million). The significant growth reflects Kiliwani North gas revenues which averaged approximately 15 MMcfd. Production from the Kiliwani North field started on 4 April 2016 and was only at low rates during the period to 30 June 2016 while the new Songo Songo Island Gas Processing Plant and related infrastructure were being tested and brought online. During the first six months of 2017, gross production from the Kiliwani North-1 well was 2.62 BCF of which Aminex's share was 1.32 BCF. Following the application of the agreed indexation allowance at the start of the year, Aminex has achieved an average sales price of $3.27 per Mcf. Revenues also arose from oilfield services comprising the provision of technical and administrative services to joint venture operations: the revenues were $0.26 million for the period ended 30 June 2017 (30 June 2016: $0.18 million), with the increase arising from the drilling activity at Ntorya. Cost of sales was $0.35 million (30 June 2016: $0.24 million) with the cost of sales for production increasing from $0.06 million for the first six months of 2016 to $0.09 million for the first six months of 2017 because of a full period of production from Kiliwani North. The balance of the cost of sales amounting to $0.26 million (30 June 2016: $0.18 million) related to the oilfield services operations. The depletion charge for Kiliwani North production amounted to $1.18 million (30 June 2016: $0.02 million). Accordingly, there was a gross profit of $3.06 million for the period compared with a gross loss of $0.01 million for the comparative period.

Group administrative expenses, net of costs capitalised against projects, were $1.49 million (30 June 2016: $1.35 million). The expenses for the current period include a share-based payment charge of $0.29 million relating to options granted to staff in May 2017 compared with a charge of $0.81 million for 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 $1.20 million (30 June 2016: $0.54 million), an increase of $0.66 million. The increase in administrative expense includes net realised foreign exchange losses of $0.27 million and additional payroll costs as a result of the Group strengthening its technical team. Management has continued to maintain strict expenditure controls and, where possible, to reduce overhead costs. The Group's resulting net profit from operating activities was $1.56 million (30 June 2016: loss of $1.59 million).

Finance costs reflect an interest charge of $0.56 million (30 June 2016: $0.86 million). Of this, a charge of $0.54 million (30 June 2016: $0.84 million) relates to the corporate loan: the 36% reduction reflected the lower loan charge following debt repayments made during the second half of 2016 and the first half of 2017. The debt was fully repaid in June 2017 and there will be no further corporate loan charge in 2017. The remaining finance cost of $0.02 million arose from the unwinding of the discount on the decommissioning provision (30 June 2016: $0.02 million).

The Group's net profit for the period amounted to $1.01 million (30 June 2016: loss of $2.45 million).

Balance Sheet

The Group's investment in exploration and evaluation assets increased from $84.62 million at 31 December 2016 to $93.62 million at 30 June 2017. The increase included the completion of drilling operations for the Ntorya-2 well and the subsequent successful testing operations, 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, taking into account ongoing discussions with the Tanzanian authorities for the extension to licence interests under the Ruvuma PSA, which are pending ministerial approval. The carrying value of property, plant and equipment has decreased from $11.22 million at 31 December 2016 to $10.04 million at 30 June 2017, representing the depletion charge on production from the Kiliwani North field. Current assets amounting to $20.41 million mainly comprise trade and other receivables of $13.49 million, which as operator includes joint venture parties' interests in gas revenues, and cash and cash equivalents of $6.91 million.

Following the repayment of the corporate loan in June, loans and borrowings have been reduced to nil from the balance of $4.93 million at 31 December 2016. Trade payables amounted to $12.94 million compared with $12.83 at 31 December 2016. This balance included amounts payable to joint venture partners and the TPDC for their profit shares under the terms of the PSA. Payables also include VAT and excise tax payable on gas receivables. The non-current decommissioning provision increased from $0.46 million at 31 December 2016 to $0.58 million, the increase relating to the unwind discount charge of $0.02 million for the period.

Total equity has increased by $4.19 million between 31 December 2016 and 30 June 2017 to $110.54 million. The net movement comprises the increase in issued capital and share premium of $2.18 million arising from the issue of capital on the exercise of all outstanding warrants in May; the foreign currency translation reserve has decreased by $0.72 million; and the movement in retained earnings comprises the profit of $1.01 million for the period and the release of the share warrant reserve to retained earnings on the exercise of warrants in May offset by the transactions expense of $0.02 million for the shares issued on exercise of those warrants.

Cash Flows

The resulting net decrease in net cash from operating activities was $2.40 million (30 June 2016: $0.78 million), after an increase in debtors of $4.31 million primarily arising on the increase in the gross receivables from the TPDC (against which monthly payments have been received after the period end) offset by a reduction in creditors of $0.59 million and interest payments of $0.54 million. Net cash outflows from investing activities amounted to $7.49 million (30 June 2016: $16,000). Expenditure on exploration and evaluation assets in the current period amounted to $7.49 million, relating to the completion of drilling operations for and the subsequent testing of Ntorya-2 well planning drilled on the Ruvuma PSA acreage, together with continuing licence costs. Expenditure on property, plant and equipment was minimal in the period with no capital costs incurred on producing assets. The Group received $0.01 million in interest during the period. In May 2017, the warrant holder exercised all warrants outstanding and Aminex received $2.18 million on the issue of the related share capital excluding transaction expenses of $0.02 million. During the period, Aminex repaid the balance of the outstanding corporate debt of $4.93 million. Overall, the decrease in net cash and cash equivalents for the six months ended 30 June 2017 was $12.65 million compared with $0.79 million for the comparative half-year period. The balance of net cash and cash equivalents at 30 June 2017 was $6.91 million (31 December 2016: $19.57 million).

Related Party Transactions

There were no related party transactions during the six-month period to 30 June 2017 that have materially affected the financial position or performance of the Group. In addition, there were no changes in the related parties set out in Note 30 to the Financial Statements contained in the 2016 Annual Report that could have had a material effect on the financial position or performance of the Group during the six-month period.

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 re run for different scenarios, including the production flow and timing of cash flow from the Group's Kiliwani North producing asset, together with the timing and cost of the Group's drilling and exploration activities. The Directors have taken into account the capital raise of $2.18 million before transaction costs following the exercise of warrants in May 2017, the outstanding decision by partners to commit to drilling Ntorya-3 well pending the completion of ongoing technical work  and the final settlement of the corporate loan in June 2017 thereby enabling securities in relation to the corporate loan to be removed. In addition, the Group's ability to continue to fulfil capital expenditure commitments, in particular in its main licence interests, can be assisted if necessary by the successful sale of assets, discretion over the timing of planned expenditure or an alternative method of raising capital. The Directors concluded that 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 twelve months from the date of approval of these condensed consolidated interim financial statements and accordingly, they are satisfied that it is appropriate to adopt the going concern basis of accounting in the preparation of these condensed consolidated interim financial statements.

Principal Risks and Uncertainties

The Group's strategic objectives for its principal activities, being the production and development of and the exploration for oil and gas reserves, are only achievable if certain risks are managed effectively. The Board has overall accountability for determining the type and level of risk it is prepared to take. The Board is assisted by the Risk Committee which seeks to identify risks for Board consideration and which monitors other risks, the responsibility for those risks and how they are managed. The following are considered to be the key risks that may affect the Group's business, although there are other risks which they currently deem to be less material that may impact the Group's performance.

Strategic risks

Development of assets to production - The Group may fail to expand through the exploration and development of its licences for which it acts as operator with joint venture partners. The failure of joint venture partners to pay their working interests may impact on Aminex's strategy.

Mitigation - Aminex manages its assets to enable the growth of cash generative business streams with the strategy of generating cash flow to meet its commitments with internal funds. The Board considers that the focus of Aminex's activities on development projects, with exploration potential, will provide value creation for shareholders rather than an exploration-led strategy. The Group identifies joint venture partners who are capable of contributing to operations but Aminex maintains a majority interest in each of its licences which offers greater upside potential to shareholders or the possibility of further farmout opportunities to assist with funding.

Global market conditions and impact of low oil price - Difficult global market conditions and the decrease in oil prices may from time to time impact the Group's operations and in particular the ability to raise equity or debt finance or to allow the Group to enter into transactions on its assets.

Mitigation - The Group reviews global conditions and manages its exposure to risk through minimising capital expenditure on high risk assets and developing fixed price gas projects. Revenues from producing assets will be used to minimise exposure to global capital markets with the intention of generating cash flow to meet capital and debt commitments. Aminex monitors costs closely and will seek to take advantage of the low-cost environment for capital commitments where possible.

Operational risks

Exploration risk - Exploration and development activities may be delayed or adversely affected by factors including in particular: climatic and oceanographic conditions; equipment failure; performance of suppliers and exposure to rapid cost increases; unknown geological conditions resulting in dry or uneconomic wells or risk of blowout; remoteness of location.

Mitigation - Aminex mitigates exploration risk by reducing the risk of drilling failure through conducting appropriate studies including the acquisition, processing and interpretation of seismic. For drilling operations, the group contracts with international and local service providers with substantial industry experience and safety procedures according to Aminex's own high standards.

Production risks - Operational activities may be delayed or adversely affected by factors including: blowouts; unusual or unexpected geological conditions; performance of joint venture partners on non-operated and operated properties; seepages or leaks resulting in substantial environmental pollution; increased operational costs; uncertainty of oil and gas resource estimates; production, marketing and transportation conditions; actions of host governments or other regulatory authorities. The Company's gas revenues relate to production from a single well, Kiliwani North-1. Although the well continues to produce, wellhead pressure is in decline and the collection of downhole pressure data is being considered to determine the causes of the decline. In the event of adverse downhole pressure data, an increased rate of depletion or impairment against the carrying cost of the asset may be required.

Mitigation - Aminex develops, implements and maintains procedures in order to limit the risk of operational failures on production assets. Through gas sales agreements, Aminex has an agreed mechanism to enable reservoirs to be produced optimally while seeking to meet the requirements of the purchaser and thereby maximising resources. The Group sells gas at the wellhead which minimises additional costs by avoiding transportation and marketing expenses. The Company has prepared a programme to re-enter the Kiliwani North-1 well to gather downhole data later in the year and is reviewing possible alternatives for remediation in the near future to maximise recoverable resources.

Maintaining licence interests - The Group may be unable to meet or agree amendments to its work programme commitments which may give rise either to minimum work obligations needing to be paid or the implementation of default procedures against the Group as operator which may lead to a licence being rescinded. In the case of the Ruvuma PSA, Aminex has applied for extensions to both the Mtwara and Lindi Licences which are pending approval by the Tanzanian authorities. The TPDC holds security over up to 15% of profit share for the Kiliwani North Development Licence in the event that part or all of the work commitments under the terms of the Ruvuma PSA relating to either the Mtwara or Lindi Licences are not fulfilled.

Mitigation - Aminex is committed to fulfilling its commitments and seeks deferrals of or amendments to production sharing terms through negotiation with the TPDC in order to ensure that commitments are met even if not in the original timeframe expected. The Board believes that there is a reasonable expectation that Aminex will be able to obtain licence extensions to the Mtwara and Lindi Licences based on discussions with the Tanzanian authorities. Aminex also intends to meet its commitments with each exploration well on drilled on the Ruvuma PSA reducing the security over the Kiliwani North Development Licence.

Compliance risks

Political risks - Aminex may be subject to political, economic, regulatory, legal, and other uncertainties (including but not limited to terrorism, military repression, war or other unrest). As Aminex's principal activities are in a developing nation, there are risks of nationalisation or expropriation of property, changes in and interpretation of national laws and energy policies. The Tanzanian government passed three new laws in July 2017, affecting the mining and energy sectors - the Natural Wealth and Resources (Permanent Sovereignty) Act; the Written Laws (Miscellaneous Amendments) Act; and the Natural Wealth and Resources Contracts (Review and Re-Negotiation of Unconscionable Terms). This new legislation includes the right of the Tanzanian authorities to renegotiate 'unconscionable terms' in agreements.

Mitigation - Aminex monitors international and national political risk in relation to its interests, liaising with governmental and other key stakeholders in its countries of operations. The Company has reviewed and continues to monitor the new legislation. Based on the Board's current understanding of this new legislation and given the existing terms and conditions of our PSAs it is unclear if there will be any material impact on Aminex's operations in Tanzania. From time to time Aminex seeks to spread asset and regional risk in order to reduce exposure to one business or region.

Health and safety - The main health and safety risks for the Group occur during drilling operations and from production operations.

Mitigation - The Group develops, implements and maintains effective health and safety procedures, including environmental issues and security, to ensure robust safeguards for well control and drilling operations are in place. 

Legal compliance - The Group could suffer penalties or damage to reputation through failure to comply with legislation or other regulations, in particular those over bribery and corruption, and these risks may be increased when operating in certain regions of the world.

Mitigation - Aminex manages risk of legal compliance failure through the implementation and monitoring of high standards to minimise the risk of corrupt or anti-competitive behaviour. All employees and consultants are required to confirm their understanding of the Group's anti-bribery policy.

Financial risks

Credit risk - All of the Group's revenues arising from the sale of natural gas is to one customer, the TPDC, which is the gas aggregator and operator of the National Gas Pipeline in Tanzania. Sales of natural gas and the credit terms relating to the sales are governed by a gas sales agreement. The recoverability and timing of receipts are therefore dependent on one customer.

Mitigation - The credit risk arising from sales to TPDC can be mitigated by a letter of credit which is required under the gas sales agreement once a commercial operations date has been declared. In the absence of regular payments from TPDC, Aminex could suspend supply until the indebtedness has been reduced.

Currency risk - Although the reporting currency is the US dollar, which is the currency most commonly used in the pricing of petroleum commodities and for significant exploration and production costs, a significant proportion of the Group's other expenditure (in particular central administrative costs) is made in local currencies (as are the Company's equity fundings), and fluctuations in exchange rates may significantly impact the results of the Group and the results between periods, thus creating currency exposure.

Mitigation - The Group has a policy of minimising exposure to foreign currency rates by holding the majority of the Group's funds in US dollars.

Forward Looking Statements

Certain statements made in this half-yearly financial report are forward-looking statements. Such statements are based on current expectations and are subject to a number of risks and uncertainties that could cause actual events or results to differ materially from the expected future events or results referred to in these forward-looking statements.

Statement of the Directors in respect of the Half-Yearly Financial Report

Each of the directors who held office at the date of this report, confirm their responsibility for preparing the half-yearly financial report in accordance with the Transparency (Directive 2004/109/EC) Regulations 2007 (as amended), the Transparency Rules of the Central Bank of Ireland and the Disclosure and Transparency Rules of the UK Financial Conduct Authority and with IAS 34 Interim Financial Reporting, as adopted by the EU and to the best of each person's knowledge and belief:

● the condensed consolidated interim financial statements comprising the condensed consolidated interim income statement, the condensed consolidated interim statement of comprehensive income, the condensed consolidated interim balance sheet, the condensed consolidated interim statement of changes in equity, the condensed consolidated interim statement of cashflows and the related explanatory notes have been prepared in accordance with IAS 34 Interim Financial Reporting as adopted by the EU.

● the interim management report includes a fair review of the information required by:

(a) Regulation 8(2) of the Transparency (Directive 2004/109/EC) Regulations 2007, being an indication of important events that have occurred during the first six months of the financial year and their impact on the condensed set of financial statements; and a description of the principal risks and uncertainties for the remaining six months of the year; and

(b) Regulation 8(3) of the Transparency (Directive 2004/109/EC) Regulations 2007, being related party transactions that have taken place in the first six months of the current financial year and that have materially affected the financial position or performance of the entity during that period; and any changes in the related party transactions described in the last annual report that could do so.

On behalf of the Board

J.C. BHATTACHERJEE M.V. WILLIAMS

Chief Executive Officer/Director Chief Financial Officer/Director/Company Secretary

28 September 2017

Independent Review Report to Aminex PLC

Introduction

We have been engaged by the Company to review the condensed consolidated financial statements (the "interim financial statements") in the half-year financial report for the six months ended 30 June 2017, which comprise the condensed consolidated income statement, condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement, and the related explanatory notes. Our review was conducted having regard to the Financial Reporting Council's International Standard on Review Engagements (UK and Ireland) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' ("ISRE 2410").

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed consolidated interim financial statements in the half-year report for the six months ended 30 June 2017 are not prepared, in all material respects, in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union (the "EU"), the Transparency (Directive 2004/109/EC) Regulations 2007 as amended (''the TD Regulations''), the Transparency Rules of the Central Bank of Ireland and the Disclosure and Transparency Rules of the UK's Financial Conduct Authority (''FCA").

Basis of our report, responsibilities and restriction on use

The half-year financial report is the responsibility of, and has been approved by, the Directors. The Directors are responsible for preparing the half-year report in accordance with the TD Regulations and the Transparency Rules of the Central Bank of Ireland.

As disclosed in note 1, the interim financial statements of the Company are prepared in accordance with International Financial Reporting Standards ("IFRS") as adopted by the EU. The directors are responsible for ensuring that the condensed interim financial statements included in this half-year financial report have been prepared in accordance with IAS 34, Interim Financial Reporting, as adopted by the EU. Our responsibility is to express to the company a conclusion on the interim financial statements presented in the half-year financial report based on our review.

We conducted our review having regard to the Financial Reporting Council's International Standard on Review Engagements (UK and Ireland) 2410 Review of Interim Financial Information Performed by the Independent Auditor of the Entity. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

We read the other information contained in the half-year financial report and consider whether it contains any apparent misstatements or material inconsistencies with the information contained in the condensed consolidated interim financial statements. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.

This report is made solely to the company in accordance with the terms of our engagement to assist the company in meeting the requirements of the Transparency (Directive 2004/109/EC) Regulations 2007 as amended (''the TD Regulations''), the Transparency Rules of the Central Bank of Ireland and the Disclosure and Transparency Rules of the UK's FCA. Our review has been undertaken so that we might state to the company those matters we are required to state to it in this report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company for our review work, for this report, or for the conclusions we have reached.

KPMG

Chartered Accountants

1 Stokes Place

St. Stephen's Green,

Dublin 2

28 September 2017

Aminex PLC

CONDENSED CONSOLIDATED INTERIM INCOME STATEMENT

for the six months ended 30 June 2017

CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE INCOME

for the six months ended 30 June 2017

Aminex PLC

CONDENSED CONSOLIDATED INTERIM BALANCE SHEET

At 30 June 2017

Aminex PLC

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN EQUITY

for the six months ended 30 June 2017

Attributable to equity shareholders of the Company

Aminex PLC

CONDENSED CONSOLIDATED INTERIM STATEMENT OF CASHFLOWS

for the six months ended 30 June 2017

Aminex PLC

NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS (unaudited)

for the six months ended 30 June 2017

1. Basis of preparation

The condensed consolidated interim financial statements for the six months ended 30 June 2017 are unaudited but have been reviewed by the auditor, having regard to ISRE 2410 (UK & Ireland). The financial information presented herein does not amount to statutory financial statements that are required by Part 6 of Chapter 4 of the Companies Act 2014 to be annexed to the annual return of the Company. The statutory financial statements for the financial year ended 31 December 2016 were annexed to the annual return and filed with the Registrar of Companies. The audit report on those statutory financial statements was unqualified.

The condensed consolidated interim financial statements have been prepared in accordance with IAS 34 Interim Financial Reporting as adopted by the EU.

The financial information contained in the condensed interim financial statements has been prepared in accordance with the accounting policies set out in the 2016 Annual Report and Accounts.

These condensed consolidated interim financial statements were approved by the Board of Directors on 28 September 2017.

(i) Going concern

The condensed consolidated interim financial statements of the Company and the Group are prepared on a going concern basis.

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 re run for different scenarios, including the production flow and timing of cash flow from the Group's Kiliwani North producing asset, together with the timing and cost of the Group's drilling and exploration activities. The Directors have taken into account the capital raise of $2.18 million before transaction costs following the exercise of warrants in May 2017, the outstanding decision by partners to commit to drilling Ntorya-3 well pending the completion of ongoing technical work and the final settlement of the corporate loan in June 2017 thereby enabling securities in relation to the corporate loan to be removed. In addition, the Group's ability to continue to fulfil capital expenditure commitments, in particular in its main licence interests, can be assisted if necessary by the successful sale of assets, discretion over the timing of planned expenditure or an alternative method of raising capital. The Directors concluded that 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 twelve months from the date of approval of these condensed consolidated interim financial statements and accordingly, they are satisfied that it is appropriate to adopt the going concern basis of accounting in the preparation of these condensed consolidated interim financial statements.

(ii) Use of judgments and estimates

The preparation of the condensed consolidated interim financial statements requires management to make judgments, estimates and assumptions that affect the application of accounting policies and the reported amounts of assets, liabilities, income and expenses. Actual results may differ from these estimates.

Estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimates are revised and in any future periods affected.

The Directors believe that the Group's critical judgments, which are those that require management's most subjective and complex judgments, are those described below. These critical accounting judgments and other uncertainties affecting application of the Group's accounting policies and the sensitivity of reported results to changes in conditions and assumptions, are factors to be considered in reviewing the interim financial statements.

The Directors consider the critical judgments in applying accounting policies to be related to the ability of the Group to continue as a going concern, valuation of exploration and evaluation assets and the depletion and decommissioning costs of property, plant and equipment and valuation of trade receivables. The Directors are required to estimate the expected remaining useful life of the oil and gas producing assets, the future capital expenditure required to recover oil and gas reserves and the future prices of oil and gas in assessing these balances. Future revisions to these estimates and their underlying assumptions could arise from results of drilling activity, movements in oil and gas prices and cost inflation in the industry. Further details are set out in Notes 9 and 10 to these financial statements. The Directors have also considered whether trade receivables due from the Tanzania Petroleum Development Corporation are impaired at 30 June 2017 and that no provision for impairment is required against the balance at that date. The Directors are required to consider the Group's ability to continue as a going concern. Further details are set out in the going concern paragraph above.

Measurement of fair values

Management use the fair value hierarchy, levels 1, 2 and 3 (as set out on page 52 of the 2016 Annual Report), for determining and disclosing the fair values of financial instruments by valuation technique. The carrying value of the Group's financial instruments are considered by management to reflect fair value given the short term nature of these.

 (iii) New accounting standards and interpretations adopted

Below is a list of standards and interpretations that were required to be applied in the period ended 30 June 2017. There was no material impact to the financial statements in the period from the application of these.

(a) New standards required to be applied to an entity with financial reporting period beginning on 1 January 2017

The standards adopted in the 2017 half yearly financial report are the same as those adopted in the 2016 Annual Report and Accounts.

(b) New standards endorsed by the EU and available for early adoption

The adoption of these standards may result in future changes to existing accounting policies and disclosures. The Company is currently evaluating the impact that these standards will have on results of operations and financial position.

IFRS 15: Revenue from Contracts with Customers. IFRS 15 specifies how and when an IFRS reporter will recognise revenue as well as requiring such entities to provide users of financial statements with more informative, relevant disclosures. The standard provides a single, principles based five-step model to be applied to all contracts with customers. The core principle of IFRS 15 is that an entity will recognise revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. With regard to the gas sales agreement with the Tanzania Petroleum Development Corporation the Company is still reviewing the impact that this has on its accounting policies and disclosures but currently believes there would not be any material impact.

IFRS 9: Financial Instruments. IFRS 9 which includes new requirements for the classification and measurement of financial assets. The Company is evaluating the impact of this standard on the consolidated financial statements.

2. Segmental disclosure - continuing operations

The Group considers that its continuing operating segments consist of (i) Producing Oil and Gas Assets, (ii) Exploration Assets and (iii) Oilfield Services and Group Costs. These segments 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 of head office expenses, cash balances and borrowings.

3. Share based payments

The following expenses have been recognised in the income statement arising on share based payments and included within administrative expenses:

The fair values of options granted in the period in accordance with the terms of the Aminex PLC Executive Share Option Scheme were calculated using the following inputs into the binomial option-pricing model:

The binomial option-pricing model is used to estimate the fair value of the Company's share options because it better reflects the possibility of exercise before the end of the options' life. The binomial option-pricing model also integrates possible variations in model inputs such as risk-free interest rates and other inputs, which may change over the life of the options.

4. Part disposal of property, plant and equipment

In the prior period, the Company completed the disposal of 1.0526% of its interest in the Kiliwani North Development Licence to Solo Oil plc for a consideration of US$0.57 million giving rise to a profit on disposal of US$0.34 million. There have been no further disposals of interest in the Kiliwani North Development Licence in the current period.

5. Finance income

6. Finance costs

Included in finance costs for the period is an interest charge of US$540,000 in respect of the US$8 million corporate loan facility, which has been calculated using the effective interest rate method. The outstanding loan balance was fully repaid in the period.

7. Tax

The Group has not provided any tax charge for the six month periods ended 30 June 2017 and 30 June 2016 or for the year ended 31 December 2016. The Group's operating divisions have accumulated losses which are expected to exceed profits earned by operating entities for the foreseeable future.

8. Earnings per share from continuing activities

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

The calculations for the basic and diluted earnings per share of the financial periods ended 30 June 2017, 30 June 2016 and the year ended 31 December 2016 are as follows:

The diluted earnings per share for the current period is adjusted to show the potential dilution if employee share options are converted into shares. The weighted average number of diluted shares is increased by 241.6 million compared to the weighted average number of basic shares, after adding back employee share options and share warrants that are deemed to be in issue for the whole of the period under review. This results in a diluted weighted average number of shares of 3,754.5 million. There were 143.5 million share options outstanding at 30 June 2017 with no share warrants in issue at the end of the period.

There is no difference between the basic loss per Ordinary Share and the diluted loss per Ordinary Share for the financial period ended 30 June 2016 and the year ended 31 December 2016 as all potentially dilutive Ordinary Shares outstanding were anti-dilutive. There were 156.7 million anti-dilutive share options at 30 June 2016 and 128.5 million at 31 December 2016. In addition to this there were 167.6 million share warrants in issue at both 30 June 2016 and 31 December 2016.

9. Exploration and evaluation assets

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

The additions to exploration and evaluation assets during the period relate mainly to the completion of drilling operations for the Ntorya-2 appraisal well and the subsequent successful testing of the well. Other additions include geophysical and geological work, administrative and licence costs associated with the Ruvuma and Nyuni Area PSAs.

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. In December 2016, the Tanzanian authorities granted an extension to the Nyuni Area licence which, pending confirmation from the TPDC, 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. Application has been made for extensions to both the Mtwara and Lindi Licences. 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.

10. Property, plant and equipment

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 with the TPDC. The Directors have reviewed the carrying value of the asset at 30 June 2017 based on estimated discounted future cashflows and are satisfied that no impairment has occurred.

11. Available for sale assets

An impairment against the carrying value of a listed investment has been expensed in the income statement.

12. Trade and other receivables

Trade and other receivables amounted to US$13.49 million at the period end (30 June 2016: US$1.21 million). The increase is largely due to debtors relating to gas sales from Kiliwani North. Included in trade and other receivables is an amount of US$9.20 million due from the TPDC for the gross receivables due to the joint venture parties for gas sales from Kiliwani North. Since the period end, the Group has received monthly payments from the TPDC to reduce the period end trade receivable. The receivable includes amounts received on behalf of joint venture parties and taxes which are included in payables and primarily only payable once funds have been received.

13. Cash and cash equivalents

Included in cash and cash equivalents is an amount of US$0.73 million (30 June 2016: US$0.18 million) held on behalf of partners in joint operations.

14. Loans and borrowings

During the period, the Company paid US$5.5 million comprising capital interest and redemption premium and thereby settled its corporate loan facility in full. Documentation for the release of related securities is being finalised.

An amount of US$0.54 million (30 June 2016: US$0.84 million) has been charged to the Group Income Statement in respect of the finance cost of the facility (see Note 6).

15. Financial instruments

(a) Carrying amounts and fair values

The following table shows the carrying amounts and fair values of financial assets and financial liabilities, including their levels in the fair value hierarchy for financial instruments measured at fair value for the prior year. It does not include fair value information for financial assets and liabilities not measured at fair value if the carrying amount is a reasonable approximation of fair value.

(b) Measurement of fair values

Where the market value of other investments is available, the fair values are determined using the bid market price without deduction of any transaction costs.

16. Share warrant reserve

On 22 May 2017, the sole warrant holder exercised 167,561,032 warrants over ordinary shares with a nominal value of €0.001 each ("Ordinary Shares"). All the warrants exercised had an exercise price of Stg 1 pence per warrant. Accordingly, 167,561,032 new Ordinary Shares were issued for which the Company received gross proceeds of US$2.18 million. The balance of US3.44 million relating to the warrants included in the share warrant reserve was therefore transferred to retained earnings. The warrants were exercisable by 30 June 2017. No warrants remain outstanding.

17. Commitments - exploration activity

In accordance with the relevant PSA, 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 square 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 (or December 2020 pending advice from the Tanzanian authorities as the First Extension Period was granted in December 2016).

(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 extensions to both the Mtwara Licence and the Lindi Licence, which also requires two wells to be drilled.

18. Related party transactions

There were no related party transactions during the six-month period to 30 June 2017 that have materially affected the financial position or performance of the Group.

19. Post balance sheet events

In early September 2017, Aminex reported an upgrade to its unrisked resource estimates from 466 BCF Pmean GIIP to approximately 1.3 TCF Pmean GIIP for the Ntorya appraisal area. The Company also submitted a development plan for the Ntorya appraisal area together with a request for the grant of a 25-year development licence.

20. Statutory information

The interim financial information to 30 June 2017 and 30 June 2016 is unaudited and does not constitute statutory financial information. The information given for the year ended 31 December 2016 does not constitute the statutory accounts within the meaning of Part 6 of Chapter 4 of the Companies Act 2014. The statutory accounts for the year ended 31 December 2016 has been filed with the Registrar of Companies in Ireland. This announcement is being sent to shareholders and will be made available at the Company's registered office at 6 Northbrook Road, Dublin 6 and at the Company's UK representative office at 60 Sloane Avenue, London SW3 3DD.