Last checked at 27 Apr 2018 12:15
27 April 2018
Aminex plc
("Aminex" or "the Company")
PRELIMINARY RESULTS FOR THE YEAR ENDED 31 DECEMBER 2017
Aminex PLC ("Aminex" or "the Group" or "the Company") today announces its preliminary results for the year ended 31 December 2017.
Operating Highlights:
• Successful completion and testing of the Ntorya-2 well at approximately 17 MMcfd
• Ntorya-2 well encountered 31 metres of high quality net gas pay
• Kiliwani North-1 gross production for year 3.60 BCF (2016: 2.78 BCF)
Financial Highlights:
• Revenue up 34% to $6.63 million (2016: $4.93 million)
• Cash balance of $6.23 million at 31 December 2017
• Gross receivables owed for gas sales $6.94 million; $2.70 million net to Aminex at 31 December 2017
• Repayment in full of the corporate loan in June 2017
Post year-end:
• Independent audit increases Ntorya 2C Contingent resource to 763 BCF: Pmean GIIP increased to 1.87 TCF
• Kiliwani North ascribed 2P reserves 1.94 BCF and with 30.8 BCF Pmean GIIP
• Discussions for farm-out of partial interest in the Ruvuma PSA to the Zubair Corporation
Aminex Chief Executive Officer, Jay Bhattacherjee, commented: "The success of the Ntorya-2 well and subsequent technical work has contributed to a substantial increase in the 2C Contingent resource for Ntorya to 763 BCF. The well planning for Chikumbi-1 is at an advanced stage and we are in discussions with the Zubair Corporation for a possible farm-out of part of Aminex's interest in Ruvuma."
For further information:
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Aminex PLC | +44 20 3198 8415 |
Jay Bhattacherjee, Chief Executive Officer |
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Max Williams, Finance Director |
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Corporate Brokers |
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Shore Capital Stockbrokers - Jerry Keen | +44 20 7408 4090 |
Davy Corporate Finance - Brian Garrahy | +35 3 1679 7788 |
Investec Bank - Chris Sim | +44 207 597 4000 |
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Camarco PR (Financial PR) |
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Billy Clegg / Gordon Poole / James Crothers | +44 20 3757 4980 |
CHAIRMAN'S STATEMENT
Dear Shareholder,
Herewith are Aminex PLC's results for the year ended 31 December 2017. The loss for the year was $2.28 million compared with $2.53 million for the year ended 31 December 2016. At the end of the year net current assets were $6.03 million and during the year a corporate loan was repaid in full. You will find a full commentary in the Financial Review section.
Aminex made significant progress in the year. During the first quarter the Ntorya-2 appraisal well was successfully drilled and subsequently tested at a stabilised rate of approximately 17 MMcfd. This well in conjunction with ongoing technical work has allowed us to gain a much better understanding of the basin. A new Competent Person's Report, commissioned by the Company during the year and reported since the year end, showed gas in place almost eleven times greater than the last time the assets were independently audited. Production revenues from Kiliwani North enabled us to close out a loan facility, leaving the Company free of debt.
During the year we continued to build up our management and technical personnel as we move forward with development of the Ruvuma PSA and review opportunities to expand beyond Tanzania. At management level, Aaron LeBlanc was appointed Chief Operating Officer and Brian Cassidy appointed General Counsel.
As already announced, work is in progress on a farm-out of a part interest in the Ruvuma PSA, with the aim of accelerating development of the Ntorya discoveries. We expect to conclude this agreement, which is subject among other conditions to shareholder approval, early in the second half of 2018.
The AGM will be held in London on 11 July 2018, where we hope to meet as many of you as possible and will be pleased to answer your questions and generally discuss the Company. I would like to thank you for your support during the year.
Yours sincerely,
Brian Hall
Chairman
CHIEF EXECUTIVE'S REVIEW
During the year, the Company reported the successful Ntorya-2 appraisal well. This well further enhanced the Company's understanding of the Ntorya discovery, leading to a substantial increase in contingent and prospective resources for the Ntorya field. Revenues from Kiliwani North enabled Aminex to repay in full the balance of its corporate debt during the first six months of the year, significantly ahead of the revised final repayment date.
Review of Tanzania operations
In February 2017, the Group successfully reached final drilling depth of 2,795 metres on its operated Ntorya-2 appraisal well in the onshore Ruvuma Basin, Tanzania, encountering a gross gas-bearing reservoir unit of approximately 51 metres. The well was subsequently tested at a stabilised rate of approximately 17 MMcfd.
Following the successful testing of the well, the Company concluded an independent audit of its resources, conducted by RPS Energy, over its Tanzanian assets. 2C Contingent resources for the Ntorya discovery were increased to a gross Pmean GIIP of 763 BCF with a gross mean GIIP of approximately 1.9 TCF, significantly exceeding management's own estimates and justifying the Company's longstanding commitment to the region.
Further momentum for the Ntorya project follows a commercialisation study prepared by io oil & gas consulting, a joint venture between major US service companies Baker Hughes (a GE company) and McDermott. This report confirmed the project to be commercially viable assuming three producing gas wells and a raw gas pipeline to the Madimba gas processing plant. Additional wells could then be drilled in line with the increasing demand forecast in Tanzania's state industrialisation plan. 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, supported by the Tanzania Petroleum Development Corporation ("TPDC"), the state oil and gas company.
The Kiliwani North-1 well ("KN-1") has been producing since April 2016 and has been providing Aminex with gas revenues since then. The gas is being sold at wellhead and achieved an average price of $3.27 per MCF in the year. To date the well has generated $18.4 million in revenue for the joint venture partners. While the well continued to produce in the first half of 2017 at approximately 15 MMcfd, it experienced decline thereafter and options are being explored to maximise production and thereby gas recovered from the in-place resources.
Analysis of technical data over the Company's licence for the Nyuni Area has identified several areas of interest, over which Aminex is planning to acquire 3D seismic, with the objective of fast-tracking potential development opportunities. Production from any discoveries in this area could be tied back to the Songo Songo Island Gas Processing Plant relatively quickly and economically. The deep-water sector of Nyuni remains of long term interest but the inshore shelf area is the Company's priority, offering early production opportunities.
Financial Position
On 20 June 2017, Aminex repaid the balance of its corporate loan which has strengthened the balance sheet. At 31 December 2017, net cash balances were $6.23 million.
On 11 April 2018, Aminex received formal notification from the TPDC of certain claims amounting to US$5.97 million for liabilities arising on revenues from gas sales, of which Aminex's share is estimated to be $2.73 million. Aminex has advised the TPDC that it does not accept the claims and no provision has been made in the financial statements beyond amounts Aminex had already accrued. Further details are disclosed in Note 13(c) to the preliminary financial information.
New Opportunities
While making good progress in developing its Tanzanian projects, the Company is actively seeking to expand its operations beyond Tanzania.
Looking Forward
Aminex is currently completing the design of its next well, Chikumbi-1 (formerly Ntorya-3), at Ruvuma. Aminex will continue to work with the TPDC to progress the grant of a 25-year development licence for Ntorya, for which application was made in September 2017. The Company proposes to monetise gas from Ruvuma as quickly as possible, selling via a raw gas pipeline to the National Gas Gathering System at Madimba, based on the commercialisation report prepared by io oil & gas consulting. With the progress made at Ntorya and the repayment of its corporate debt, Aminex has been reviewing different funding options and is currently working on a farm-out of part of the Group's interest in the Ruvuma PSA to an affiliate of the Zubair Corporation, as previously announced. The Company expects to receive an extension to the Mtwara Licence, possibly until January 2020, during which time the development licence for Ntorya is expected to be finalised. Aminex is also pursuing the TPDC's recommendation to apply for an entirely new production sharing agreement over the Lindi area where the current licence expired in January 2017 and for which the Company has been negotiating an extension or renewal terms.
I would like to thank our shareholders for their continued support and trust.
Jay Bhattacherjee
Chief Executive
FINANCIAL REVIEW
Financing and future operations
During the period, Aminex applied the cash flow from Kiliwani North operations to the repayment of its 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 the Company was able to clear the corporate loan and strengthen the Group balance sheet.
The Company benefited from continued average daily production at Kiliwani North of approximately 15 MMcfd for the first six months of the year, as reported in the Half-Yearly Report, but during the second half of the year production from the well started to decline faster than expected. Aminex has identified various remedial actions to enhance production and is currently investigating options to increase production.
The success of the Ntorya-2 appraisal well and the subsequent work on the basin model has led to a significant increase in the independently ascribed resources for Ntorya, which justifies Aminex's commitment to the region over the years. The resource potential should be commercially viable with increasing national demand in Tanzania coupled with the proximity of the National Gas Gathering System enabling near-term production from the field.
The Board continues to assess alternative means of financing Group operations and is currently in talks with the Zubair Corporation for a farm-out of part of its interest in Ruvuma, as already announced. Early production options could provide revenues from Ntorya for the Group within the next two years. In conjunction with revenues from Ntorya, Aminex is also seeking to expand cash-generating operations on the Kiliwani North Development Licence through the development of a newly-identified lead, Kiliwani South. If proved successful, this lead's proximity to the Songo Songo Island gas processing plant would enable the Company to generate revenues from two separate projects in Tanzania.
Revenue Producing Operations
Revenues from continuing operations amounted to $6.63 million (2016: $4.93 million). Gross production in 2017 was 3.60 BCF (2016: 2.78 BCF), of which Aminex's share was 1.82 BCF (2016: 1.45 BCF). Following the application of the contract-specified indexation allowance at the start of the year, Aminex has achieved an average sales price of $3.27 per MCF (2016 $3.25 per MCF). Revenues from gas operations amounted to $5.95 million (2016: $4.57 million). Revenues also arose from oilfield services comprising the provision of technical and administrative services to joint venture operations: the revenues were $0.68 million for the year ended 31 December 2017 (2016: $0.36 million), the increase arising from drilling activity at Ntorya. Cost of sales was $5.46 million (2016: $1.69 million) with the cost of sales for production increasing from $0.09 million for 2016 to $0.26 million for 2017 due to a full period of production from Kiliwani North and an increase in the depletion charge for Kiliwani North production amounting to $4.57 million (2016: $1.24 million). The increase in depletion arose on the acceleration of the depletion rate per thousand cubic feet of production due to the reduction in the estimated reserves remaining as well as due to increased production year on year. The balance of the cost of sales amounting to $0.63 million (2016: $0.36 million) related to the oilfield services operations. Accordingly, there was a gross profit of $1.17 million for the period compared with a gross profit of $3.25 million for the comparative period.
Group administrative expenses, net of costs capitalised against projects, were $2.29 million (2016: $2.85 million). The expenses for the current period include a share-based payment charge of $0.29 million relating to share 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 $2.00 million in line with administrative expenses of $2.04 million for the comparative year. Management has continued to maintain strict expenditure controls and, where possible, to reduce overhead costs. The Group's resulting net loss from operating activities was $1.13 million (2016: $1.25 million after a gain on disposal of the development assets and an impairment of other receivables).
Finance costs amount to $1.17 million (2016: $1.30 million). Of this, a charge of $0.54 million (2016: $1.26 million) related to the corporate loan which was fully repaid in June 2017. The unwinding of the discount on the decommissioning provision was $0.08 million (2016: $0.04 million). The loss on foreign exchange amounted to $0.55 million (2016: nil).
The Group's net loss for the period amounted to $2.28 million (2016: $2.53 million).
Balance sheet
As a result of the review of technical data over the Kiliwani North Development Licence block, the Company has identified the Kiliwani South structure as a viable lead for further exploration with management estimating a Pmean gross GIIP of 57 BCF. The Directors have assessed the impact of the new technical interpretation and believe it is appropriate to reclassify costs of $4.54 million previously incurred in relation to this structure from property plant and equipment to exploration and evaluation assets. In accordance with IAS 1, the reclassification has also been reflected in the comparative financial statements resulting in an increase of $4.54 million in the carrying value of exploration and evaluation assets and a reduction of $4.54 million in the carrying value of property plant and equipment as at 31 December 2016.
The Group's investment in exploration and evaluation assets increased from $89.16 million at 31 December 2016 (restated) to $99.59 million at 31 December 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 application for a development licence for the Ntorya prospect, the extension of the Mtwara Licence and the expected application for a new production sharing agreement for the Lindi Licence, both of which have expired. The carrying value of property, plant and equipment has decreased from $6.67 million at 31 December 2016 (restated) to $2.43 million at 31 December 2017, following the depletion charge of $4.57 million on production from the Kiliwani North field. This was charged at an accelerated rate compared with the previous year with reference to the reserves independently ascribed to the field at 1 January 2018. Current assets amounting to $15.00 million mainly consist of trade and other receivables of $8.78 million, including the gross receivable of $6.94 million due from the TPDC for gas revenues, which as operator includes joint venture partners' interests in gas revenues. On 11 April 2018, Aminex received formal notification from the TPDC of certain claims amounting to US$5.97 million for liabilities arising on revenues from gas sales, of which Aminex's share is estimated to be $2.73 million. Aminex has advised the TPDC that it does not accept the claims and no provision has been made in the financial statements beyond amounts Aminex had already accrued. Further details are disclosed in Note 13(c) to the preliminary financial information. However, Aminex believes the debt remains fully recoverable, with Aminex's net share of the receivable amounting to $2.70 million. Cash and cash equivalents were $6.23 million (2016: $19.6 million).
Under current liabilities, following the repayment of the corporate loan in June, loans and borrowings have been reduced from $4.93 million at 31 December 2016 to nil. Trade payables amounted to $8.97 million compared with $12.83 million at 31 December 2016. This balance included amounts payable to joint venture partners and to 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 $0.48 million at 31 December 2016 to $0.64 million, this increase relating to the fair value of an additional provision $0.08 million for the Ntorya-2 well drilled during the year and the unwind discount charge of $0.08 million for the period.
Total equity increased by $1.06 million between 31 December 2016 and 31 December 2017 to $107.41 million. The net movement comprises an 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 $0.88 million as a result of a weaker US dollar; and the movement of $2.79 million in retained earnings comprises the loss of $2.28 million for the year and the cost of $0.02 million for the capital raise offset by a release of $1.65 million from the share option reserve and by a release of $3.44 million from the share warrant reserve.
Cash Flows
The net inflow in cash from operating activities was $0.60 million (2016: net outflow $3.20 million), after a decrease in debtors of $0.40 million primarily arising on the increase in the gross receivables from the TPDC but offset by a reduction in creditors of $3.01 million, interest payments of $0.54 million and a foreign exchange loss of $0.55 million. Net cash outflows from investing activities amounted to $10.63 million (2016: $1.66 million). Expenditure on exploration and evaluation assets in the reporting period amounted to $10.62 million, relating to the completion of drilling operations for and the subsequent testing of Ntorya-2 well, together with continuing licence costs. Expenditure on property, plant and equipment was $0.02 million in the year. The Group received $0.02 million in interest during the year. In May 2017, the warrant holder exercised all warrants outstanding and Aminex received $2.18 million on the issue of the related share capital, before deducting transaction expenses of $0.02 million. During the year, Aminex repaid the balance of the outstanding corporate loan debt of $4.93 million. Overall, the decrease in net cash and cash equivalents for the year ended 31 December 2017 was $13.34 million compared with an increase of $17.44 million for the comparative period. After a foreign exchange loss of $0.55 million (2016: $nil), the balance of net cash and cash equivalents at 31 December 2017 was $6.23 million (31 December 2016: $19.57 million).
Max Williams
Finance Director
OPERATIONS REPORT
TANZANIA
Kiliwani North Development Licence - Production
Aminex (operator) 57.4474%
RAK Gas LLC 25%
Bounty Oil & Gas NL 10%
Solo Oil plc 7.5526%
The Kiliwani North-1 well was drilled in 2008 and commenced production in April 2016 following the commissioning of the Songo Songo Island Gas Processing Plant ("SSIGPP"). Since commencing production the well has produced 6.4 BCF. 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.
The Kiliwani North-1 well averaged approximately 15 MMcfd during the first half of 2017, as reported in the Half-Yearly Report, but thereafter the well began to experience a decline in production rates and well head pressure. In November the well head pressure had reduced to a point where it was lower than the minimum inlet pressure required by the plant and as a result the well was produced at fluctuating rates below 1.0 MMcfd. By mid-December 2017 the well head pressure had recovered sufficiently for the well to be put back on production with rates of up to approximately 9 MMcfd.
Production rates are determined by the plant operator and are based on normal requirements for the SSIGPP. The plant has a 140 MMcfd processing capacity. Gas from Kiliwani North is sold at wellhead and is 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 analysed production and pressure data acquired throughout 2017 and concluded that the well is probably draining a small portion of the greater Kiliwani North structure. The data also suggests that the well is showing signs of a slow recharge from elsewhere in the surrounding structure via leaky faults or baffles within the reservoir. The Company continues to investigate various options to increase production and recovery of resources from the well. RPS Energy (RPS) was engaged late in 2017 to compile an independent Competent Person's Report (CPR) on all Aminex's Tanzanian assets and this was finalised in February 2018. The new CPR assigned 1.94 BCF of 2P reserves remaining to be produced from the Kiliwani North-1 well. The Company continues to produce from its Kiliwani North-1 well at restricted rates while it seeks alternatives remediate the well. Due to inlet pressure limitations and fluid build-up in the wellbore, the well has been produced infrequently in order to maintain basic plant operations.
During 2018, the Company has undertaken a simulation study on the field and, based on a history match of past reservoir performance, the Company believes that an opportunity may exist to access unperforated reservoir capable of recovering additional gas volumes. Equipment required to conduct this workover has already been identified and pending further work on plant specifications and appropriate government approvals, the Company intends to re-enter the well.
As part of continuing work over its near-shore interests under the Kiliwani North Development Licence and the Nyuni Area PSA, Aminex's expanded technical team has conducted an extensive review of existing seismic data to identify drillable prospects which could be tied back to the National Gas Gathering System on Songo Songo Island. Aminex is planning to acquire 3D seismic over several areas on the shelf close to Songo Songo Island and these will include 3D seismic over the Kiliwani North and Kiliwani South structures. Kiliwani South is estimated by management to contain 57 BCF gross Pmean GIIP. As a result of the additional work required, the carrying cost of Kiliwani South has been reclassified to exploration and evaluation assets.
Under the terms of the Nyuni East Songo Songo PSA which governs the Kiliwani North Development Licence, the TPDC may elect to contribute 5% of development costs in order to obtain a participating interest of 5% in production and revenues.
Ruvuma PSA - Onshore Appraisal and Exploration
Aminex (operator) 75%
Solo Oil plc 25%
Aminex drilled and tested the Ntorya-2 appraisal well during the early part of 2017. This well reached a total vertical depth of 2,795 metres and subsequently tested at a stabilised rate of approximately 17 MMcfd. The well successfully appraised the Cretaceous discovery 74 metres updip from the Ntorya-1 discovery well encountering gas bearing reservoir with 31 metres of net pay and 51 metres of gross reservoir.
Ongoing technical work incorporating the results of Ntorya-2, basin modelling and re-interpretation of the existing 2D seismic covering the Ruvuma PSA including the Ntorya discovery, resulted in a significant increase over management's previous estimated resources for the Ntorya discovery. During 2017 management increased the internally estimated GIIP resource numbers for the Ntorya discovery from a mean 155 BCF (assessed by LR Senergy in 2015) to 1.3 TCF Pmean GIIP. The new RPS CPR, reported to shareholders in early 2018, ascribed an estimated Pmean GIIP of 1.87 TCF of gas to the Ntorya field and also increased the 2C resources from the 2015 CPR by approximately 11 times, increasing from 70 BCF to 763 BCF.
Ntorya-2 was drilled in the onshore Ruvuma Basin to appraise the Ntorya field where the Ntorya-1 gas discovery previously drilled by the Company had shown net pay of 3.5 metres and had flow-tested at 20 MMcfd, with 139 barrels of associated condensate. The Ntorya field is approximately 33 kilometres from the Madimba gas processing plant in south-eastern Tanzania, which distributes gas into the Tanzanian National Gas Pipeline system. Ntorya-2 completed the appraisal drilling obligations for the Ntorya location area.
In September 2017, the Group submitted a development plan for the Ntorya appraisal area and applied for the grant of a 25-year development licence. 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 to prepare a gas commercialisation study to assist with development of the Ntorya field. The study was designed to identify gas monetisation options available to the Company, including potential early development facilities to supply gas to the local market and generate near-term revenues. The development plan is subject to review by and approval of the Tanzanian authorities and the Company will provide an update on its status in due course.
The Ruvuma PSA originally comprised two licence areas: the Mtwara Licence and the Lindi Licence. During 2016, Aminex received formal ministerial approval for a one-year extension to the Mtwara Licence, to January 2018 and expects to be granted a further extension to the Mtwara Licence. Although the Lindi Licence technically expired on 28 January 2017, negotiations are in progress. The Board had expected an extension to the Lindi Licence to be granted but subsequent discussions with the TPDC indicate the likelihood of being able to formalise an entirely new PSA in conjunction with the TPDC, which would enable further development and exploration to be carried out in conjunction with the Mtwara Licence area.
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.
Nyuni Area PSA - Onshore, Shelf and Deepwater Exploration
Aminex (operator) 93.3333%
Bounty Oil & Gas NL 6.6667%
Aminex remains focused on projects which will deliver commercial gas in the near term. A new 3D seismic programme is being prepared with the intent to map prospects capable of being economically drilled and tied into the SSIGPP.
Aminex has identified significant upside through the re-interpretation of existing 2D seismic over the licence area and continues to high-grade leads and prospects with the potential to deliver gas into the National Gas Gathering System. In the deep water part of the licence, the Company is unlikely to be in a position to drill a high cost well without the participation of a larger company as a farm-in partner. Despite the high potential in the deep water areas, drilling in the shallow transition zone remains the most economically near-term viable option.
The First Extension Period was granted in December 2016 and backdated to October 2015. However, the Company believes that the four-year extension period should have started from the date of grant in December 2016, and has requested 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 development costs in order to obtain a participating interest of 20% in production and revenues.
OTHER ASSETS
Egypt
Aminex retains a 1% gross overriding royalty on all sales revenues from the South Malak-2 gas discovery well in excess of $2.5 million. This well is not yet on production.
Group Income Statement
for the year ended 31 December 2017
2017 2016
Notes US$'000 US$'000
Continuing operations
Revenue 2 6,633 4,934
Cost of sales 2 (5,463) (1,688) _______ _______
Gross profit 1,170 3,246
Administrative expenses (2,291) (2,851)
_______ _______
(Loss)/profit from operating activities before other items (1,121) 395
Gain on disposal of development asset - 344
Impairment of other receivables - (1,971)
Impairment loss on available for sale assets (4) (18)
_______ _______
Loss from operating activities (1,125) (1,250)
Finance income 4 20 13
Finance costs 5 (1,173) (1,297)
_______ _______
Loss before tax (2,278) (2,534)
Income tax expense - - _______ _______
Loss for the financial year
attributable to equity holders of the Company (2,278) (2,534)
_______ _______
Basic and diluted loss per Ordinary Share (in US cents) 3 (0.06) (0.10) _______ _______
Group Statement of Other Comprehensive Income
for the year ended 31 December 2017
2017 2016
US$'000 US$'000
Loss for the financial year (2,278) (2,534)
Other comprehensive income:
Items that are or maybe reclassified to profit or loss:
Currency translation differences 876 (1,559)
_______ _______
Total comprehensive income for the financial year
attributable to the equity holders of the Company (1,402) (4,093)
_______ _______
Group Balance Sheet
at 31 December 2017
2017 2016 Notes US$'000 US$'000
(Restated
Assets Note 6)
Non-current assets
Exploration and evaluation assets 6 99,587 89,162
Property, plant and equipment 7 2,429 6,673
Available for sale assets - 4
_______ _______
Total non-current assets 102,016 95,839
_______ _______
Current assets
Trade and other receivables 8 8,777 9,179
Cash and cash equivalents 6,226 19,567
_______ _______
Total current assets 15,003 28,746
_______ _______
-
Total assets 117,019 124,585
_______ _______
Equity
Issued capital 12 69,062 68,874
Share premium 122,267 120,274
Other undenominated capital 234 234
Share option reserve 2,540 3,894
Share warrant reserve - 3,436
Foreign currency translation reserve (2,142) (3,018)
Retained earnings (84,551) (87,341)
_______ _______
Total equity 107,410 106,353
_______ _______ -
Liabilities
Non-current liabilities
Decommissioning provision 10 636 476
_______ _______
Total non-current liabilities 636 476
_______ _______
Current liabilities
Loans and borrowings 11 - 4,931
Trade and other payables 9 8,973 12,825
_______ _______
Total current liabilities 8,973 17,756
_______ _______
Total liabilities 9,609 18,232
_______ _______
Total equity and liabilities 117,019 124,585
_______ _______
Group Statement of Changes in Equity
for the year ended 31 December 2017
Attributable to equity shareholders of the Company | ||||||||
|
Share capital |
Share premium | Other unde-nominated capital |
Share option reserve |
Share warrant reserve | Foreign currency translation reserve |
Retained earnings |
Total |
| US$'000 | US$'000 | US$'000 | US$'000 | US$'000 | US$'000 | US$'000 | US$'000 |
|
|
|
|
|
|
|
|
|
At 1 January 2016 | 67,192 | 96,036 | 234 | 3,683 | 3,054 | (1,459) | (83,864) | 84,876 |
Transactions with shareholders recognised directly in equity |
|
|
|
|
|
|
|
|
Shares issued | 1,682 | 24,238 | - | - | - | - | (1,546) | 24,374 |
Share options granted | - | - | - | 814 | - | - | - | 814 |
Share option reserve transfer |
- |
- |
- |
(603) |
- |
- |
603 |
- |
Share warrants granted | - | - | - | - | 382 | - | - | 382 |
Comprehensive income: |
|
|
|
|
|
|
|
|
Currency translation differences |
- |
- |
- |
- |
- |
(1,559) |
- |
(1,559) |
Loss for the financial year | - | - | - | - | - | - | (2,534) | (2,534) |
At 1 January 2017 | 68,874 | 120,274 | 234 | 3,894 | 3,436 | (3,018) | (87,341) | 106,353 |
Transactions with shareholders recognised directly in equity |
|
|
|
|
|
|
|
|
Shares issued | 188 | 1,993 | - | - | - | - | (15) | 2,166 |
Share options granted | - | - | - | 293 | - | - | - | 293 |
Share option reserve transfer |
- |
- |
- |
(1,647) |
- |
- |
1,647 |
- |
Share warrants granted | - | - | - | - | (3,436) | - | 3,436 | - |
Comprehensive income: |
|
|
|
|
|
|
|
|
Currency translation differences |
- |
- |
- |
- |
- |
876 |
- |
876 |
Loss for the financial year | - | - | - | - | - | - | (2,278) | (2,278) |
At 31 December 2017 |
69,062 |
122,267 |
234 |
2,540 |
- |
(2,142) |
(84,551) |
107,410 |
Group Statement of Cashflows
for the year ended 31 December 2017
2017 2016
Notes US$'000 US$'000
Operating activities
Loss for the financial year (2,278) (2,534)
Depletion and depreciation 2 4,577 1,248
Equity-settled share-based payments 293 814
Finance income 4 (20) (13)
Finance costs 5 1,173 1,297
Gain on disposal of development asset - (344)
Impairment of other receivables - 1,971
Impairment of available for sale assets 4 18
Decrease/(increase) in trade and other receivables 403 (8,595)
(Decrease)/increase in trade and other payables (3,008) 5,361
_______ _______
Net cash absorbed by/(used in) operations 1,144 (777)
Interest paid (540) (2,419)
_______ _______
Net cash inflows/(outflows) from operating activities 604 (3,196)
_______ _______
Investing activities
Proceeds from sale of development asset - 567
Acquisition of property, plant and equipment (23) (128)
Expenditure on exploration and evaluation assets (10,623) (2,110)
Interest received 20 13 _______ _______
Net cash used in investing activities (10,626) (1,658)
_______ _______
Financing activities
Proceeds from issue of share capital 12 2,181 25,920
Payment of transaction expenses (15) (1,546)
Loans repaid 11 (4,931) (2,081)
_______ _______
Net cash (outflows)/inflows from financing activities (2,765) 22,293
_______ _______
Net (decrease)/increase in cash and cash equivalents (12,787) 17,439
Cash and cash equivalents at 1 January 19,567 2,128
Foreign exchange loss (554) -
_______ _______
Cash and cash equivalents at 31 December 6,226 19,567
_______ _______
Notes to the Financial Information for the year ended 31 December 2017
1 Statement of accounting policies
Aminex PLC (the "Company") is a company domiciled and incorporated in Ireland. The Group financial statements for the year ended 31 December 2017 consolidate the individual financial statements of the Company and its subsidiaries (together referred to as "the Group").
Basis of preparation
The financial information has been prepared in accordance with International Financial Reporting Standards (IFRS) as adopted by the European Union (EU).
At the date of issue of this announcement the Group's statutory financial statements for the year ended 31 December 2017, 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 2016, which is available on the Company's website, www.aminex-plc.com, except as set out in Note 6. Certain comparative amounts have been reclassified as a result of a change in the classification of certain expenditures during the current year.
Going concern
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 31 December 2019, review of the key assumptions on which these are based and sensitivity analysis. The Directors concluded that the Group would have sufficient 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 the financial statements, assuming receipt of payment of outstanding invoices for gas sales made to the Group's sole customer, the Tanzania Petroleum Development Corporation ("TPDC"), at 31 December 2017, as disclosed in Note 8 to the preliminary financial information, and for gas sales made after that date. The Directors updated their consideration of going concern to take account of the subsequent claim received from the TPDC on 11 April 2018, as disclosed in Note 13(c) to the preliminary financial information.
The Group's ability to make planned capital expenditure on its main licence interests in Tanzania and to fund its ongoing operational expenditure, can be assisted if necessary by the successful sale of assets, deferral of planned expenditure or by raising additional capital. The Directors have taken into account the current discussions with an affiliate of the Zubair Corporation regarding a possible farm out of part of Aminex's interest in the Ruvuma PSA, which includes the Ntorya prospect, for which Aminex has submitted a development licence application. A transaction with the Zubair Corporation, Aminex's largest shareholder through a shareholding held by Eclipse Investments LLC, would be a related party transaction.
Notwithstanding that the Directors have a reasonable expectation that the Group will be able to implement some or all of these actions, the TPDC claim and non-payment to date of the trade receivable balance due from TPDC to the Group at 31 December 2017, indicates the existence of a material uncertainty that may cast significant doubt on the Group's ability to continue as a going concern and that the Group and Company may, as a consequence, be unable to realise its assets and discharge its liabilities in the normal course of business. The Group and Company financial statements have been prepared on a going concern basis and do not include any adjustments that would be necessary if this basis were inappropriate.
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 2017:
· Amendments to IAS 7: Disclosure Initiative (29 January 2016) - effective 1 January 2017
· Amendments to IAS 12: Recognition of deferred tax assets for unrealised losses (19 January 2016) - effective 1 January 2017
· Annual improvements to IFRS 2014-2016 cycle
ii) Standards not affecting the reported results or the financial position
New and revised Standards and Interpretations adopted in the current year did not have any significant impact on the amounts reported in these Financial Statements.
The following Standards and Interpretations which have not been applied in the Financial Statements, but will have an impact on future Financial Statements, were in issue but not yet effective and in some cases had not yet been adopted by the EU:
· IFRS 9: Financial Instruments - effective 1 January 2018
· IFRS 15: Revenue from contracts with customers (May 2014) including amendments to IFRS 15 - effective 1 January 2018
· IFRS 16: Leases - effective 1 January 2019
· IFRS 14: Regulatory Deferral Accounts
· Amendments to IFRS 2: Classification and measurement of share-based payment transactions
· IFRIC 22: Foreign Currency transaction and advance consideration
· Amendments to IAS 40: Foreign Currency transaction and advance consideration
· IFRIC 23: Uncertainty over Income Tax Treatments
· Amendments to IFRS 9: Prepayment Features with Negative Compensation
· IFRS 17: Insurance Contracts (issued on 18 May 2017)
· Amendments to IFRS 10 and IAS 28: Sale or contribution of assets between an investor and its associate or joint venture
2 Segmental Information
An operating segment is a component of the Group that engages in business activities from which it may earn revenues and incur expenses, including revenues and expenses that relate to transactions with any of the Group's other components.
The Group considers that its operating segments consist of (i) Producing Oil and Gas Properties, (ii) Exploration Activities and (iii) Oilfield Services. 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, the Group 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.
| Segmental revenue |
| 2017 US$'000 |
| 2016 US$'000 |
| Region of destination |
|
|
|
|
| Tanzania - producing oil and gas assets |
| 5,950 |
| 4,572 |
| Tanzania - provision of oilfield services |
| 683 |
| 362 |
|
|
| 6,633 |
| 4,934 |
|
|
|
|
| |
| Cost of sales | 2017 US$'000 |
| 2016 US$'000 | |
| Region of destination |
|
|
| |
| Tanzania - production costs | 264 |
| 90 | |
| Tanzania - depletion | 4,566 |
| 1,237 | |
| Tanzania - provision of oilfield services | 633 |
| 361 | |
|
| 5,463 |
| 1,688 | |
|
|
|
| ||
Segment profit/(loss) for the financial year | 2017 US$'000 |
| 2016 US$'000 | ||
|
|
|
| ||
Tanzania - producing oil and gas assets | 573 |
| 3,134 | ||
Tanzania - exploration activities | (59) |
| (388) | ||
Ireland - non-attributable corporate expenses (1) | (1,837) |
| (6,374) | ||
UK - oilfield services | (955) |
| 1,094 | ||
Total group loss for the financial year | (2,278) |
| (2,534) | ||
|
|
|
| ||
Segment assets | 2017 US$'000 |
| 2016 US$'000 | ||
|
|
| (Restated) | ||
Tanzania - producing oil and gas assets | 11,508 |
| 13,570 | ||
Tanzania - exploration activities | 101,919 |
| 95,808 | ||
Ireland - non-attributable assets (2) | 3,206 |
| 15,021 | ||
UK - oilfield services | 386 |
| 186 | ||
Total assets | 117,019 |
| 124,585 | ||
|
|
|
| ||
Segment liabilities | 2017 US$'000 |
| 2016 US$'000 | ||
|
|
|
| ||
Tanzania - producing oil and gas assets | 8,021 |
| 5,694 | ||
Tanzania - exploration activities | 784 |
| 7,122 | ||
Ireland - non-attributable liabilities (3) | 109 |
| 5,034 | ||
UK - oilfield liabilities | 695 |
| 382 | ||
Total liabilities | 9,609 |
| 18,232 | ||
Total non-current assets and liabilities by geographical region are set out in Notes 6 and 7 to the preliminary financial information. Details of changes in classification from property, plant and equipment to exploration and evaluation assets which occurred during the year are set out in Note 6. Segment assets have been restated accordingly.
(1) Non-attributable corporate expenses include amounts of a corporate nature not specifically attributable to an operating segment. They include impairment provisions, interest expense on financial liabilities and related costs.
(2) Non-attributable assets primarily comprise cash and working capital.
(3) Non-attributable liabilities primarily comprise loans and borrowings and trade payables.
2017 2016
US$'000 US$'000
Capital expenditure
Tanzania - exploration assets 10,344 4,754
Tanzania - producing assets 309 161
UK - oilfield assets 23 15
_______ _______
Total capital expenditure 10,676 4,930
_______ _______
2017 2016
US$'000 US$'000
Other non-cash items: continuing operations
Tanzania depletion - producing assets 4,566 1,237
UK depreciation - oilfield assets 11 11
Impairment of other receivables - 1,971
Interest expense on financial liabilities measured at amortised cost 79 42
Impairment provision against available for sale assets 4 18
_______ _______
3 Loss per Ordinary Share
The basic loss per Ordinary Share is calculated using a numerator of the loss for the financial year and a denominator of the weighted average number of Ordinary Shares in issue for the financial year. The diluted loss per Ordinary Share is calculated using a numerator of the loss for the financial year and a denominator of the weighted average number of Ordinary Shares outstanding and adjusting for the effect of all potentially dilutive shares, including share options and share warrants, assuming that they had been converted.
The calculations for the basic loss per share for the years ended 31 December 2017 and 2016 are as follows:
2017 2016
Loss for the financial year (US$'000) (2,278) (2,534)
_______ ______
Weighted average number of Ordinary Shares ('000) 3,578,729 2,600,190
_______ _______
Basic and diluted loss per Ordinary Share (US cents) (0.06) (0.10)
_______ _______
There is no difference between the basic loss per Ordinary Share and the diluted loss per Ordinary Share for the years ended 31 December 2017 and 2016 as all potential Ordinary Shares outstanding are anti-dilutive. There were 137,750,000 (2016: 128,475,000) share options issued which are anti-dilutive as at 31 December 2017 and no warrants (2016: 167,561,032) in issue at 31 December 2017.
4 Finance income
2017 2016
US$'000 US$'000Deposit interest income 20 13 _______ _______
5 Finance costs
2017 2016
US$'000 US$'000
Interest expense on financial liabilities measured at amortised cost (see Note 11) 540 1,255
Other finance costs - decommissioning provision interest charge (see Note 10) 79 42
Foreign exchange loss 554 -
_______ _______
1,173 1,297
_______ _______
Included in finance costs for the period is an interest charge of US$540,000 in respect of the US$8 million corporate loan facility, which has been calculated using the effective interest rate method. The outstanding loan balance was fully repaid in the period.
6 Exploration and evaluation assets
Tanzania and Total
US$'000
(Restated)
Cost
At 1 January 2016 - as originally reported 84,945
Reclassification from producing assets 4,544
_______
At 1 January 2016 - as restated 89,489
Additions 3,998
Employment costs capitalised 756
_______
At 1 January 2017 94,243
Additions 9,026
Employment costs capitalised 1,318
Increase in decommissioning provision 81
_______
At 31 December 2017 104,668
_______
Provisions for impairment
At 1 January 2016, 31 December 2016 and 31 December 2017 5,081
_______
Net book value
At 31 December 2017 99,587
_______
At 31 December 2016 (restated) 89,162
_______
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.
As a result of a review during the year of technical data obtained in prior years over the Kiliwani North Development Licence block, the Company has identified the Kiliwani South structure as a viable lead for further exploration with management estimating a Pmean gross gas in place resource of 57 BCF. The Directors have assessed the impact of the new technical interpretation and believe it is appropriate to reclassify costs of US$4.54 million previously incurred in relation to this structure from property, plant and equipment to exploration and evaluation assets. In accordance with IAS 1, the reclassification has also been reflected in the comparative financial statements resulting in an increase of US$4.54 million in the carrying value of exploration and evaluation assets and a reduction of US$4.54 million in the carrying value of property, plant and equipment as at 31 December 2016.
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 has a licence period ending in October 2019. Aminex believes that the four year extension period should have started from the date of grant in December 2016 and has requested clarification from the TPDC. The Mtwara Licence, which includes the Ntorya appraisal area, was extended to January 2018 and Aminex is in discussions with the TPDC and has a reasonable expectation of the Licence being extended. In September 2017, Aminex applied for a 25-year development licence for Ntorya following the successful testing of the Ntorya-2 appraisal well. The extension to the Mtwara Licence would allow for the development licence process and also enables further exploration activity. Following discussions with the TPDC concerning the extension of the Lindi Licence under the terms of the Ruvuma PSA, the Directors now expect an application to be made for a new production sharing agreement for the Lindi Licence. While the new PSA terms may not be the same as those for the Ruvuma PSA, a new PSA would provide more time to explore and evaluate the leads in the Lindi Licence area and the Directors believe this would be a satisfactory outcome. While negotiations are held to agree terms for the new PSA, and as the Directors believe there is a reasonable expectation that a new PSA will be signed, the carrying cost of the Lindi Licence which amounts to US$10.4 million has not been impaired. The Directors have noted that the recoverable cost pool for the Lindi licence is transferable to the Mtwara licence under the Ruvuma PSA. The Directors are satisfied that there are no further indicators of impairment but recognise that future realisation of these oil and gas assets is dependent on further successful exploration, appraisal and development activities and the subsequent economic production of hydrocarbon reserves.
7 Property, plant and equipment
| Producing Assets - Tanzania US$’000 (Restated) | Other Assets US$’000 | Total US$’000 (Restated) |
Cost
At 1 January 2016 - as originally reported 12,405 450 12,855
Reclassification to exploration and evaluation assets (4,544) - (4,544)
_______ _______ _______
At 1 January 2016 - as restated 7,861 450 8,311
Additions in the year 161 15 176
Disposed of during the year (126) (273) (399)
Exchange rate adjustment - (65) (65)
_______ _______ _______
At 1 January 2017 7,896 127 8,023
Additions in the year 309 23 332
Disposed of during the year - (74) (74)
Exchange rate adjustment - 6 6
_______ _______ _______
At 31 December 2017 8,205 82 8,287
_______ _______ _______
Depreciation and impairment
At 1 January 2016 - 439 439
Charge for the year 1,237 11 1,248
Disposed of during the year - (273) (273)
Exchange rate adjustment - (64) (64)
_______ _______ _______
At 1 January 2017 1,237 113 1,350
Charge for the year 4,566 11 4,577
Disposed of during the year - (74) (74)
Exchange rate adjustment - 5 5
_______ _______ _______
At 31 December 2017 5,803 55 5,858
_______ _______ _______
Net book value
At 31 December 2017 2,402 27 2,429
_______ _______ _______
At 31 December 2016 (restated) 6,659 14 6,673
_______ _______ _______
As at 31 December 2017, "Other assets" comprises plant and equipment US$24,000 (2016: US$9,000), and fixtures and fittings US$3,000 (2016: US$5,000).
Following the award of the Kiliwani North Development Licence by the Tanzanian Government in April 2011, the carrying cost relating to the development licence, including the associated costs of Kiliwani-1 based on accounting estimates at the date of transfer, was reclassified as a development asset under property, plant and equipment, in line with accounting standards and the Group's accounting policies. Production from the Kiliwani North-1 well commenced on 4 April 2016 and the depletion charge for the year ended 31 December 2016 was calculated with reference to the contingent resources ascribed to the field in 2015. Although the resources remain contingent on the notification of a commercial operations date by the TPDC in accordance with the Gas Sales Agreement with the TPDC, an independent reserves report for Kiliwani North has ascribed reserves of 1.94 BCF gross as at 1 January 2018. The accelerated depletion charge for the year ended 31 December 2017 has been based on the reserves at that date although there remain contingent resources of 30.8 BCF as further identified in the report. As described in Note 6, Aminex's share of the carrying cost of the Kiliwani-1 well drilled in 2008 has been reclassified to exploration and evaluation assets with effect from 1 January 2016 in accordance with IAS 1 and the comparative year has been restated accordingly. Although the Kiliwani North-1 well-head pressure and therefore rates of production have declined, the Directors have reviewed the carrying value of the producing assets at 31 December 2017 based on estimated discounted future cashflows and are satisfied that no impairment charge is required against its carrying value at that date.
8 Trade and other receivables
|
| 2017 US$’000 | 2016 US$’000 |
Current
Trade receivables 6,956 5,923
Amounts due from partners in jointly controlled operations 1,359 674
VAT recoverable 30 389
Withholding
tax recoverable - 175
Other receivables 314 606
Prepayments and accrued income 118 1,412 _______ _______
8,777 9,179 _______ _______
Included in trade receivables is an amount of US$6.94 million due from TPDC in respect of Kiliwani North gas sales and interest due on late payment. Aminex's net share of the receivable is US$2.70 million (2016: US$1.94 million). No payments have been received from the TPDC since the year-end. As set out in Note 13(c) to the financial information, Aminex has received a letter from TPDC for certain claims amounting to US$5.97 million for liabilities arising on revenues from gas sales. All amounts fall due within one year.
9 Trade and other payables
|
| 2017 US$’000 | 2016 US$’000 |
Trade payables 332 2,546
Amounts due to partners in jointly controlled operations 2,076 2,117
Withholding tax payable 453 99
VAT payable 2,116 2,354
Capital gains tax payable 327 221
Other payables 2,320 1,272
Accruals 1,349 4,216
_______ _______
8,973 12,825 _______ _______
Amounts due to partners in jointly controlled operations, VAT payable and Other payables include amounts arising on gas sales and are payable on receipt of gas revenues from TPDC.
10 Provisions - decommissioning
US$'000
At 1 January 2016 448
Discount unwound in the year 42
Release from decommissioning
provision on disposal of property, plant and equipment (14) _______
At 1 January 2017 476
Discount unwound in the year (see Note 5) 79
Increase in decommissioning provision 81 _______
At 31 December 2017 636
______
2017 2016
US$'000 US$'000
Non-current 636 476
_______ _______
Total decommissioning provision 636 476 _______ _______
Decommissioning costs are expected to be incurred over the remaining lives of the wells, which are estimated to end between 2021 and 2028. The provision for decommissioning is reviewed annually and at 31 December 2016 and 2017 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.
11 Loans and borrowings
In 2017, the Group paid US$5.47 million comprising capital, interest and redemption premium and thereby settled its corporate loan facility in full. An amount of US$0.54 million (2016: US$1.26 million) has been charged to the Group Income Statement in respect of the finance cost of the loan facility (see Note 5).
12 Issued capital
Authorised Number Value €
Ordinary Shares of €0.001 each: 5,000,000,000 5,000,000
Deferred shares of €0.059 each: 1,000,000,000 59,000,000
_____________ __________
At 1 January and 31 December 2017 6,000,000,000 64,000,000
_____________ __________
Allotted, called up and fully paid Number € US$
Ordinary Shares of €0.001 each: 3,475,897,030 3,475,896 4,338,260
Deferred shares of €0.059 each: 818,658,421 48,300,847 64,535,665
_____________ __________ __________
At 31 December 2016 4,294,555,451 51,776,743 68,873,925
Issued during 2017 167,561,032 167,561 188,462
_____________ __________ __________
At 31 December 2017 4,462,116,483 51,944,304 69,062,387
_____________ __________ __________
Comprised of:
Ordinary Shares of €0.001 3,643,458,062
Deferred shares of €0.059 818,658,421
______________
4,462,116,483
______________
No voting rights are attached to the deferred shares.
The increase during the year in the Ordinary Share capital and share premium of the Company related to the following:
Price Issued Share
Stg pence capital premium Total
Details Date of issue per share Number US$'000 US$'000 US$'000
Exercise of warrants 22 May 2017 1.00 167,561,032 188 1,993 2,181
__________ _______ _______ _______
13 Commitments, guarantees and contingent liabilities
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, originally comprised two licences. The Mtwara Licence was extended to January 2018 and Aminex is in discussions for and has a reasonable expectation of receiving a further extension. On the licence, Two wells are required to be drilled, one of which is expected to be the Chikumbi-1 location. The Company has previously sought an extension to the Lindi Licence, for which there remains a two-well commitment, and is currently seeking a new Lindi PSA.
Guarantees and contingent liabilities
(a) Kiliwani North Development Licence. Under the terms of the Addendum to the Ruvuma PSA, Ndovu Resources Limited has provided security to the Tanzania Petroleum Development Corporation for up to 15% of the Kiliwani North Development Licence to guarantee the amended four-well drilling commitment under the Ruvuma PSA. For each well drilled the security interest will be reduced by 3% for the first well and 4% thereafter.
(b) The Company occasionally guarantees certain liabilities and commitments of subsidiary companies. These are considered to be insurance arrangements and are accounted for as such i.e. they are treated as a contingent liability until such time as it becomes probable that the Company will be required to make payment under the guarantee in which case a liability is recognised.
(c) On 11 April 2018, Ndovu Resources Limited, a subsidiary company of Aminex PLC, received formal notification from the TPDC of certain claims amounting to US$5.97 million with regard to unpaid royalties and amounts due under profit share arrangements which it proposes to offset against the receivable of US$6.94 million owing by TPDC to Aminex at 31 December 2017 (see Note 8). Of the amount claimed, Aminex has already accrued for the liabilities it considers appropriate based on its own calculations of amounts due as at 31 December 2017. Aminex has advised the TPDC that it does not accept the balance of the claims, which include computational inaccuracies. No further provision has been made in the financial statements for the additional amounts claimed as the Directors believe the claims are without merit and are satisfied that the US$6.94 million included in trade receivables as owing from the TPDC will be fully recovered.
14 Post balance sheet events
On 9 January 2018, the Company granted 42 million options over Ordinary Shares to Directors and staff. The exercise price was Stg3.08p with the exercise period not exceeding three years from date of grant. The share-based payment charge arising from the grant will be charged to the Income Statement in the year ending 31 December 2018.
On 5 February 2018, the Company advised that RPS Energy Consultants Limited had completed a Competent Person's Report over the Company's entire Tanzania asset base and that their findings have established a significant resource upgrade. This result, taken together with the results of the Ntorya Gas Commercialisation Study prepared by io oil & gas consulting in 2017, confirmed the feasibility of developing the Ntorya gas field for commercial production.
On 21 March 2018, the Company announced that it was in discussions with the Zubair Corporation for a possible farm out of part of its interest in the Ntorya Appraisal Area. The Zubair Corporation is a significant shareholder in Aminex PLC through its wholly-owned subsidiary company Eclipse Investments LLC.
On 11 April 2018, Aminex received formal notification from the TPDC of certain claims amounting to US$5.97 million for liabilities arising on revenues from gas sales, of which Aminex's share is estimated to be $2.73 million. Aminex has advised the TPDC that it does not accept the claims and no provision has been made in the financial statements beyond amounts Aminex had already accrued. Further details are disclosed in Note 13(c).
15 Statutory information
The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2017 or 2016 within the meaning of the Companies Act, 2014. The statutory accounts for 2017 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 2016, including an unqualified audit report thereon, were filed with the Companies Registration Office. The 2017 Annual Report and financial statements will be posted to shareholders shortly.
16 Use of estimates and key sources of estimation uncertainty
The preparation of the consolidated financial statements in conformity with IFRS requires management to make estimates and assumptions that affect the application of accounting policies and the reported amounts of assets and liabilities, as well as the disclosure of contingent assets and liabilities at the balance sheet date and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from these estimates.
The major sources of estimation uncertainty that have a significant risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are the impairment of exploration and evaluation assets (Note 6), the impairment of and the depletion of property, plant and equipment (Note 7), the decommissioning costs of arising from certain exploration and evaluation assets and property plant and equipment (Note 10), the recoverability of trade and other receivables (Note 8) and the estimation of share-based payment charges. In determining the treatment of exploration and evaluations assets, property plant and equipment and the provision for decommissioning, the Directors are required to make estimates and assumptions as to future costs and events. There are uncertainties inherent in making these assumptions, especially with regard to gas reserves and resources and these assumptions include the life of, and title to, an asset, gas recovery rates, gas prices, costs of production, and foreign exchange rates.
Assumptions that are valid at the time of estimation may change significantly as new information becomes available and changes in these assumptions may alter the economic status of and the estimates for exploration and evaluation assets and property plant and equipment and give rise to resources or reserves being restated. The estimation of recoverable amounts is dependent on finance being available to fund the development of the exploration and evaluation assets and property plant and equipment.
17 Board approval
The Board of Directors approved the preliminary financial statement for the year ended 31 December 2017 on 27 April 2018.