Aminex Announces 2021 Half Yearly Report

Source: 9/30/2021, Location: Africa

Aminex PLC announces its unaudited half-yearly report for the six months ended 30 June 2021.

· Loss for the period of US$1.59 million (30 June 2020: loss of US$1.15 million), an increase of 38% on the same period last year
· Continued reduction in overheads (before one-offs and exceptional items) with like-for-like expenditure down over 20% compared with the same six-month period in 2020

· Ministry of Energy of Tanzania granted a two-year licence extension under the Ruvuma PSA, effective from 15 August 2021
· Seismic acquisition contract for approximately 338 km2 of 3D seismic awarded by the Ruvuma joint venture to Africa Geophysical Services Limited following an extensive tendering exercise by the operator
· Significant progress in negotiations with the Tanzania Petroleum Development Corporation on Kiliwani North gas sales receivables

Charles Santos, Executive Chairman of Aminex commented:
"We are excited that the Ntorya gas development is entering a period of operational activity by acquiring 3D seismic and well execution, representing significant steps towards monetising this large gas resource into existing infrastructure and an established market in Tanzania. Moreover, we want to recognise the steadfast and efficient efforts of APT in moving the Ruvuma project forward. Finally, we are appreciative of the continued support of the Tanzanian Ministry of Energy most recently demonstrated by its granting of a two-year license extension for the Ruvuma PSA and of the TPDC for their continued constructive negotiations regarding the outstanding Kiliwani receivables."


Executive Chairman's Review

Aminex PLC's results for the six months ended 30 June 2021 are set out below.

The Company reports a loss for the period of US$1.59 million (30 June 2020: US$1.15 million). Further information is provided in the Financial Review.

The Company is pleased to report that ARA Petroleum Tanzania Limited ("APT") has made meaningful progress on the Ruvuma project within the last two months. APT has secured a two-year license extension under the Ruvuma PSA from the Ministry of Energy of Tanzania and awarded the Seismic Acquisition Contract. The seismic acquisition operations are scheduled to commence imminently. APT efficiently completed the procurement process and secured highly competitive acquisition rates that benefit the project with considerable financial savings. The Ntorya gas development is entering a period of operational activity by acquiring 3D seismic and well execution, representing significant steps towards monetising this large gas resource into existing infrastructure and an established market in Tanzania. APT has demonstrated focused determination and commitment to move the project forward, for which the Company is pleased.

The Company can also report that our negotiations with the Tanzania Petroleum Development Corporation ("TPDC") have made substantial progress in seeking resolution of the outstanding payments for past gas sales from the Kiliwani North development licence. The Company appreciates the TPDC's constructive approach to the negotiations and believes that both parties agree that these matters need to be resolved satisfactorily and swiftly to benefit the local gas industry and enable Tanzania to secure further investment and upstream gas development.

The Company believes that these developments together with other positive developments in-country represent a strong commitment by the Tanzanian authorities to create an attractive investment climate to enable the success of their oil and gas industry, giving us much hope about the future success of our Tanzanian endeavours.

We continued to cut costs and reduce corporate overheads, including reducing General and Administrative costs ("G&A"). Although the Company saw an increase in G&A expenditure during the period compared to the same period in 2020, this increase represents the one-off associated costs of actions taken during the period to realise further cost savings. On a like-for-like basis, the cost savings made in the period compared to the same period in 2020 are over 20%. I am happy to report the Company still targets a reduction in gross G&A costs (before one-off costs and exceptional items) to less than £1 million per annum by 2022, representing a 75% reduction from 2018 levels. Through making these initiatives the Company has established an appropriate structure of capabilities and competencies that match the current requirements of the business with a more flexible approach that de-risks our business and can help create or attract strategic opportunities.

Aminex continues to focus on a non-operating strategy. The Board believes that this focus will allow it to ultimately improve shareholder value. Having successfully identified a farm-in partner on its key Ruvuma asset, the Company continues to actively seek various options for its other assets that will align with its strategy of reducing risk, securing investment and reducing costs.

Kiliwani North and Kiliwani South - Kiliwani North Development Licence ("KNDL")
As a result of reservoir pressure decline and compartmentalisation, the Kiliwani North-1 well has not produced during the period. The well has produced approximately 6.5 BCF of gas to date, from a compartment estimated to contain approximately 10 BCF. Estimated gas resources have been independently audited by RPS, who show the Kiliwani North structure to contain approximately 31 BCF (gross mean GIIP).

Aminex undertook preliminary remedial work to repair the downhole safety valve in late 2018 which resulted in the flow of a small volume of gas, to the gas facility, before the well quickly ceased flow, likely due to fluid build-up in the wellbore. Aminex has prepared a perforation strategy for a lower zone within the reservoir and an alternative remedial work programme intended to establish fluid levels in the wellbore, reservoir pressure and to unload potential fluid using foam treatment.

The Company is working with the TPDC on agreed methods to handle wellbore fluids which will potentially be unloaded during operations on the well. Agreement and planning will be required prior to undertaking operations, including resolution on the outstanding receivables of US$8.34 million for previous gas sales from KNDL and related late payment interest. As stated above, the past year has seen a series of constructive meetings held between the Company and the TPDC where substantial progress has been made in reaching a resolution for amounts due for past gas sales.

Ruvuma PSA
Aminex completed the Farm-Out of 50% of its participating interest in the Ruvuma PSA to ARA Petroleum Tanzania Limited ("APT") in October 2020, retaining a 25% non-operated interest. Upon completion, APT assumed operatorship of the Ruvuma PSA and the Group secured a US$35.0 million carry for its 25% participating interest in the Ruvuma PSA. It is expected that the carry, which is equivalent to US$140.0 million of gross field expenditure, will see the Company to potentially significant volumes of production. The Farm-Out includes a full carry for a minimum work programme including the drilling and testing of the Chikumbi-1 well, the acquisition of 3D seismic over a minimum of 200 km2 within the Ntorya Location area, and further production wells and infrastructure as required to propel the project to its estimated P50 production level of approximately 140 MMcf/d (gross project levels), as shown in an io Ntorya commercialisation study. The completion of the Farm-Out is the culmination of many successful years of exploration and evaluation work by Aminex, who recognised the underlying value and opportunities that could be gained in the Ruvuma basin.

During the period the operator, APT, completed the tendering process for the new high-resolution 3D seismic acquisition and performed a re-interpretation of the existing 2D seismic dataset and considers the Ntorya gas reservoir to be the product of a stacked, high-energy, channelised sand system. Their revised mapping and internal management estimates suggest a mean risked gas in place ("GIIP") for the Ntorya accumulation of 3,024 Bcf, in multiple lobes to be tested and a mean risked recoverable gas resource of 1,990 Bcf, which will be appraised by the planned seismic and drilling programme. In August, the Ruvuma joint venture was granted a two-year Licence extension, effective from 15 August 2021, over the Mtwara Licence in respect of the Ntorya Location. During the two-year extension period the operator APT is committed to undertake acquiring 200 km2 of 3D seismic (minimum expenditure of US$7.0 million), drill the Chikumbi-1 exploration well (minimum expenditure of US$15.0 million) and complete the negotiation of the Gas Terms for the Ruvuma PSA with the TPDC and, using the data gathered from the Chikumbi-1 and seismic acquisition, prepare and submit an application for a Development Licence for the Ntorya Location area. In September 2021, the Ruvuma joint venture announced award of the seismic acquisition contract to Africa Geophysical Services Limited ("AGS"). The award follows an extensive tendering exercise conducted by APT for the seismic programme during which the joint venture was able to take advantage of favourable market conditions securing a lumpsum contract considerably below the joint venture's expected budget for the activity. AGS intends to commence activities in the Ntorya location from October 2021. The acquisition will consist of approximately 338 km² of 3D seismic data focusing on the area of primary interest. AGS will mobilise, weather permitting, and focus on the proposed location for the Chikumbi-1 well ("CH-1") to acquire as much data as possible before the start of the rainy season with the programme re-commencing after that with no additional cost to joint venture partners.

Nyuni Area PSA
The First Extension Period to the Nyuni Area PSA expired on 27 October 2019. The Board concluded that the carrying value of the Nyuni asset was impaired and full provision was made at 31 December 2018 and subsequent expenditure, including in the reporting period, has also been charged to the Income Statement.

In July 2019, Aminex submitted an application to the TPDC to enter the Second Extension Period of three years together with a request for an amendment to the work programme obligation for the licence area. The proposed number of blocks to be retained under the licence would reduce to five, from the current ten blocks under licence. Although the proposed amended work programme and associated commitment is being supported by the TPDC and PURA, the Company continues in negotiations with the Minister of Energy.

Aminex remains focused on projects which will deliver commercial gas to the Tanzanian markets in the near term and Aminex believes the Nyuni Area acreage offers considerable upside exploration potential to complement the development projects at Ntorya and Kiliwani North. The proposed acreage to be retained generally lies in the shallow water areas adjacent to the Kiliwani North Development Licence, an area with existing gas infrastructure, which will require the acquisition of 3D seismic to move shallow water targets to drill ready status.

Tanzania has an energy deficit and has embarked on further industrialisation development programmes which has seen the planning and construction of numerous facilities along existing gas delivery infrastructure either directly connected to or in close proximity to Aminex's Tanzanian assets and which are expected to increase local gas demand significantly in the near future. In addition, it has been reported that discussions have been held between Tanzanian Government officials and their counterparts in neighbouring countries to explore the possibility of securing a long-term supply of gas from Tanzania and adding to future gas demand in the East African region. These positive developments in the Tanzanian gas sector bode well for the commercialisation of Aminex's assets in the future.

Financial Review

Revenue Producing Operations
Revenues from continuing operations amounted to US$0.09 million (30 June 2020: US$0.30 million). Group revenues during the first six months of 2021 are derived from the provision of technical and administrative services to joint venture operations.

Cost of sales was US$0.31 million (30 June 2020: US$0.39 million). The cost of sales for Kiliwani North operations amounted to US$0.20 million (30 June 2020: US$0.09 million) and included ongoing commercial discussions with the TPDC on recovery of the TPDC gas sales receivables as well as general licence related maintenance costs. There was no depletion charge for Kiliwani North as the period saw no production (30 June 2020: nil). The balance of the cost of sales amounting to US$0.11 million (30 June 2020: US$0.30 million) related to the oilfield services operations and minor non-operated costs related to the Group's interest in the Ruvuma PSA. Accordingly, there was a gross loss of US$0.22 million for the period compared with a gross loss of US$0.09 million for the comparative period.

Group administrative expenses, excluding depreciation and net of costs capitalised against projects, were US$0.82 million (30 June 2020: US$0.58 million), an increase of US$0.24 million. The increase in expenses during the period reflects one-off costs related to the implementation of cost saving actions including legal and redundancy costs. The cost saving initiatives implemented by the Company, which commenced in 2019, included savings in respect of Directors' fees, employment costs, advisors' fees, office and travel related costs. Initially in response to the ongoing delays in completion of the Farm-Out transaction on the Ruvuma PSA, this has enabled the Company to weather the economic downturn as a result of the global COVID-19 pandemic and oil price fall during 2020 both of which have had an adverse effect for the industry. Management maintains strict expenditure controls and continues to seek cost saving solutions and efficiencies across the Group. The Company forecasts by 2022, these cost-saving efforts will reduce gross general and administrative expenditure (before one-off costs and exceptional items) to less than £1 million per annum, representing a 75% reduction from 2018 levels. Depreciation charged in the period was US$0.11 million (30 June 2020: US$0.11 million) and related predominantly to right of use assets.

In accordance with IFRS 9, the Group calculated an expected credit loss based on its exposure to credit risk on its trade receivables at the end of the period and recognised an impairment on trade receivables of US$0.09 million (30 June 2020: US$0.09 million). This expected credit loss ("ECL") reflected the continued delays by the TPDC to settle amounts due as discussions continue in respect of amounts claimed by the TPDC. The ECL is calculated on the full amount of US$8.34 million due to the Group for gas sales and interest on late payment, with an equivalent reduction in the liability due to JV partners representing their share of the provision.

The Group recognised an impairment during the six-month period against exploration and evaluation assets. The impairment recognised against exploration and evaluation assets of US$0.30 million (30 June 2020: US$0.37 million) relates to expenditure incurred on the Nyuni Area PSA predominantly related to own costs for geological, geophysical and administrative work and licence maintenance costs, along with training and licence fees. All expenditure on the Nyuni Licence Area continues to be impaired immediately to the income statement upon recognition following the full impairment of the Nyuni Area Licence in 2018. The Group's resulting net loss from operating activities was US$1.54 million (30 June 2020: loss of US$1.15 million).

Finance costs amounted to US$0.05 million (30 June 2020: US$0.08 million), comprising US$0.04 million (30 June 2020: US$0.03 million) for the decommissioning interest charge and finance costs of US$0.01 million related to foreign exchange losses on monetary assets (30 June 2020: gain of US$0.08 million). The Group incurred no interest expense in the six-month period (30 June 2020: US$0.04 million) as the Group became debt-free on the completion of the Farm-Out and the subsequent settlement of the $5.0 million loan funding from ARA. In the comparative six-month period the Group also recognised a US$0.03 million charge for the finance charges on finance leases.

The Group's net loss for the period amounted to US$1.59 million (30 June 2020: loss of US$1.15 million).

Balance Sheet
The Group's investment in exploration and evaluation assets increased from US$42.89 million at 31 December 2020 to US$42.93 million at 30 June 2021. The increase of US$0.04 million reflected exploration and evaluation expenditure on the Kiliwani South CGU. In accordance with the Group's accounting policy, the Group will not record subsequent expenditure for its share of costs that are carried by APT in relation to the Ruvuma PSA asset. The Group is carried for US$35.0 million of development expenditure on the Ruvuma PSA, and that carry stood at US$34.2 million at 30 June 2021 with expenditure in the period related to the operator establishing operations in Tanzania, remapping of existing seismic and progressing the acquisition of 3D seismic.

The carrying value of property, plant and equipment has decreased from US$1.11 million at 31 December 2020 to US$1.00 million at 30 June 2021. The decrease relates predominantly to the depreciation of right of use assets recognised in property, plant and equipment. Current assets amounted to US$8.11 million (31 December 2020: US$9.00 million) with trade and other receivables of US$7.62 million (31 December 2020: US$8.55 million), which as operator includes joint venture parties' interests in gas revenues, and cash and cash equivalents of US$0.49 million (31 December 2020: US$0.45 million). The decrease in current assets of US$0.89 million predominantly related to payment of interim period costs by ARA related to the Ruvuma PSA Farm-Out due following the completion of the Farm-Out.

Current liabilities amounted to US$11.36 million compared with US$10.66 million at 31 December 2020. This balance included amounts payable to the TPDC and joint venture partners for their profit shares from invoiced gas sales, along with related VAT and excise tax payable on the gas receivables invoices. The increase in current liabilities predominantly relates to expenditures on operated Tanzania gas assets and legal and redundancy costs incurred as a result of cost saving initiatives. Non-current liabilities amounting to US$0.92 million (31 December 2020: US$0.97 million) include the non-current decommissioning provision which increased during the period by US$0.04 million from US$0.87 million at 31 December 2020 to US$0.91 million, the increase relating to the unwind of the discount charge during the period, offset by the transfer of other long-term liabilities of US$0.67 million to current liabilities. Non-current liabilities also include long-term lease liabilities of US$0.01 million (31 December 2020: US$0.03 million) following the recognition of right-of-use assets and lease liabilities in accordance with IFRS 16: Leases.

Total equity has decreased by US$1.59 million between 31 December 2020 and 30 June 2021 to US$39.77 million (31 December 2020: US$41.36 million). A net decrease of US$0.56 million to the share option reserve, an increase in the foreign currency translation reserve of US$0.01 million and the net movement of US$1.03 million in retained earnings arising on the loss of US$1.59 million for the period, offset by the release from the share option reserve of US$0.56 million to retained earnings following the expiry of certain share options during the period.

Cash Flows
Net cash inflows due from operating activities was US$0.38 million during the period (30 June 2020: cash outflow of US$2.49 million). This was predominantly in relation to receipt of the interim costs from ARA under the terms of the Ruvuma PSA Farm-Out. This resulted in a decrease in debtors of US$1.01 million. Creditors increased in the period by US$0.41 million predominantly as a result of third-party costs on the Group's operated assets and costs incurred in cost saving initiatives. Net cash outflows from investing activities amounted to US$0.19 million (30 June 2020: cash inflow US$0.76 million) related to expenditure on the Group's exploration and evaluation assets, relating mostly to payments for general licence maintenance of the Nyuni Area and Kiliwani South gas assets. Net cash outflows from financing activities were US$0.14 million (30 June 2020: cash inflow US$1.90 million) due to payments of lease liabilities. Net cash and cash equivalents for the six months ended 30 June 2021 therefore increased by US$0.05 million compared with an increase of US$0.16 million for the comparative half-year period. The balance of net cash and cash equivalents at 30 June 2021 was US$0.49 million (30 June 2020: US$0.93 million).

Related party transactions
There have been no material changes in the related party transactions affecting the financial position or the performance of the Group in the period since publication of the 2020 Annual Report other than those disclosed in Note 15 to the condensed consolidated financial statements.

Going Concern
The financial statements of 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 through review of cash flow forecasts prepared by management for the period to 30 September 2022, review of the key assumptions on which these forecasts are based and the sensitivity analysis. The forecasts reflect the Group's best estimate of expenditures and receipts for the period. The forecasts are regularly updated to enable continuous monitoring and management of the Group's cash flow and liquidity risk. The forecasts indicate that, taking account of the agreement between the Group and ARA to enter into a loan of US$1.7 million, the Group is required to source additional funding during the 12-month period to have sufficient capital resources for a period of 12 months from the date of approval of this annual report. It is the expectation of the Board that the Group will source this funding via an equity placement under its disapplication authority. The ARA loan agreement is not yet executed and, whilst the Board fully anticipate its completion, such funding is not guaranteed by ARA under the terms of the loan agreement.

As part of its analysis in making the going concern assumption, the Directors have considered the range of risks facing the business on an ongoing basis, as set out in the risk section of the 2020 Annual Report that remain applicable to the Group. The principal assumptions made in relation to the going concern assessment relate to the proposed US$1.7 million loan from ARA, historic gas sales to the TPDC, capital commitments on its operated assets in Tanzania and the ongoing objection to a tax assessment in Tanzania.

Trade receivables of US$8.3 million, of which Aminex's net share is US$3.5 million, have not been taken into account in the cash flow forecast due to the claims for certain amounts by the TPDC, set out in Note 14 to the financial statements. Although this trade receivable is due, the TPDC continue to delay payment until a resolution is reached in respect of the claims and the Directors consider it prudent not to take this receivable amount into consideration of the Group's ability to continue as a going concern. Any recovery of funds from the TPDC for past gas receivables and related late payment interest would assist the Group's working capital position.

As disclosed in Note 14, the Group received a tax assessment from the TRA of US$2.2 million in relation to an audit covering the period from 2013 to 2015 which is excluded from the cash forecast as any cash outflow during the going concern period is considered unlikely based on legal advice and the timeframes for tax cases in Tanzania. Additionally, development of the Group's other assets in Tanzania is excluded from the cash forecast as negotiations continue with the Tanzanian authorities on the three-year extension for the Nyuni PSA, including a revised work programme, as disclosed in Note 14, and consequently any capital expenditure in the period is unlikely to arise. However, a risk exists that the Group loses its objection to the tax assessment or is unable to renegotiate or defer commitments on its operated Licence interests during the period. Additional funding would be required to meet these potential liabilities. There remains significant uncertainty as regards the ability of Aminex to raise funds, if required, in the current market conditions due to the COVID-19 pandemic during the going concern period. This may result in the Company having to raise funds at whatever terms are available at the time.

These circumstances indicate that a material uncertainty exists that may cast significant doubt on the Group's ability to continue to apply the going concern basis of accounting. As a result of their review, and despite the aforementioned material uncertainty, the Directors have confidence in the Group's forecasts and have a reasonable expectation that the Group will continue in operational existence for the going concern assessment period and have therefore used the going concern basis in preparing these consolidated 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 Audit and Risk Committee, which oversees the process for review and monitoring of risks, and the implementation of mitigation actions, by management. The Audit and Risk Committee reviews management's findings regularly and reports to the Board accordingly. Assessment of risks is made under four categories: Strategic Risks, Operational Risks, Compliance Risks and Financial Risks.

Aminex has reviewed and assessed the principal risks and uncertainties at 30 June 2021 and concluded that the principal risks identified at 31 December 2020 and disclosed on pages 24 to 25 of the 2020 Annual Report are still appropriate. The following are considered to be the key principal risks facing the Group over the next six months although there are other risks which may impact the Group's performance:

· Ability to secure other financing for Group operations
· Ability to meet licence work commitments
· Delayed or non-payment of receivables from the TPDC
· Delay in approval of the Nyuni Area Second Extension Period with amended work commitments
· Political and fiscal uncertainties
· Lack of exploration, appraisal and development drilling success
· The ongoing impact of the COVID-19 pandemic

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