TIDMAEX
RNS Number : 0176S
Aminex PLC
28 September 2017
2017 HALF-YEARLY REPORT
Aminex PLC ("Aminex" or "the Group" or "the Company") announces
its half-yearly report for the six months ended 30 June 2017.
FINANCIAL HIGHLIGHTS
-- Profit for the period of $1.01 million (30 June 2016: loss $2.45 million)
-- Repayment of the corporate loan: Aminex now debt-free
-- Cash balance of $6.91 million at 30 June 2017
OPERATING HIGHLIGHTS
-- Successful completion and testing of the Ntorya-2 appraisal well at 17 MMcfd
-- Ntorya-2 well encountered 31 metres of high quality net gas pay
-- Average production from Kiliwani North-1 of approximately 15 MMcfd for the first half of 2017
POST PERIOD
-- Upgrade of management estimate of Ntorya field to unrisked Pmean gas initially in place to 1.3 TCF
-- Submission of development plan and application for Ntorya field development licence
-- Commissioning of gas commercialisation study
Aminex CEO, Jay Bhattacherjee, commented:
"We are pleased to report to shareholders a return to profit
during the first half of the year. During 2017, Aminex successfully
drilled the Ntorya-2 appraisal well, which tested at approximately
17 million cubic feet per day, increased management's estimate of
the Pmean unrisked resource estimates for the Ntorya field to
approximately 1.3 TCF and submitted a development plan for,
together with the application for, a development licence over the
Ntorya field. The Company also repaid all of its outstanding
corporate debt so that it is now a debt-free company. With this
base, the Board believes the Company is well placed to build on
success."
For further information:
Aminex PLC +44 20 3198 8415
Jay Bhattacherjee, Chief
Executive Officer
Max Williams, Chief
Financial Officer
Corporate Brokers
Investec Bank plc -
Chris Sim +44 20 7597 4000
Shore Capital Stockbrokers
- Jerry Keen +44 20 7408 4090
Davy - Brian Garrahy +35 3 1679 7788
Camarco (Financial PR) +44 020 3757 4980
Billy Clegg/Gordon Poole/James
Crothers
Glossary of terms used
PSA Production Sharing Agreement
BCF Billions of cubic feet
of natural gas
TCF Trillions of cubic feet
of natural gas
BOED Barrels of oil equivalent
per day
Mcf Thousands of cubic feet
of natural gas per day
MMcfd Millions of cubic feet
of natural gas per day
mmBTU One million British
Thermal Units
Km Kilometres
TPDC Tanzania Petroleum Development
Corporation
GIIP Gas Initially in Place
GSA Gas Sales Agreement
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Chief Executive's Review
Aminex PLC's Interim Results for the six months ended 30 June
2017 are set out below. During the reporting period the Company
returned to profit, repaid its corporate loan facility in full and
completed a significant appraisal well in the onshore Ruvuma basin
of Tanzania. Work completed since the period end has enabled the
Company to announce a major increase in its gas resources.
Profit for the period was $1.01 million compared to a loss of
$2.45 million for the six-month period ended 30 June 2016. A
commentary on the results is provided in the Financial Review
section below.
In February, the Group successfully reached final drilling depth
on its operated Ntorya-2 appraisal well in the onshore Ruvuma
Basin, Tanzania. At 2,593 metres drilling depth the well
encountered a gross gas bearing reservoir unit of approximately 51
metres. The well was subsequently tested at a stabilised rate of 17
MMcfd, although only a limited section of the reservoir was
perforated due to mud-induced damage. Since the completion of
testing the Company has updated its basin model, including mapping,
and management unrisked Pmean resource estimates over the Ntorya
area are now approximately 1.3 TCF. The Company is currently in the
process of engaging a third-party reserves auditor to update its
reserves and resources.
With increasing resource estimates in the Ntorya area, the
Company has engaged io oil & gas consulting, a joint venture
between Baker Hughes (a GE company) and McDermott, to prepare a gas
commercialisation study which will assist with and accelerate the
development of the field and, most importantly, identify possible
early monetisation opportunities for the project. A development
plan has been submitted and application made to the Ministry of
Energy and Minerals for a 25-year development licence for the
Ntorya area, which is supported by the TPDC.
The Kiliwani North-1 well continues to provide positive cash
flow and averaged approximately 15 MMcfd during the first six
months of 2017. The gas is sold and paid for in US Dollars and the
current gas price is $3.27 Mcf (based on $3.00 per mmBTU, annually
adjustable through indexation): the contract price is not affected
by movements in global markets for oil and natural gas. Although
some delays in payment were experienced early in the year, regular
payments have been received from the TPDC in recent months.
During the first half of 2017 Aminex has strengthened its
financial base, significantly increased its resource potential and
further strengthened its team through the appointment of key new
executives. All these will enable the Company to progress the
onshore Ruvuma Basin to the next stage and the Board looks forward
to the future with confidence.
Jay Bhattacherjee
Chief Executive
28 September 2017
Operations Report
Tanzania - Kiliwani North
Production from the Kiliwani North-1 well during 2017 averaged
approximately 15 MMcfd during the reporting period. In the
comparative period, production which commenced on from 4 April 2016
was limited to support the testing and commissioning of the new
Songo Songo Island Gas Processing Plant ("SSIGPP").
Production rates are determined by the plant operator and are
based on normal requirements for testing and commissioning
procedures for the SSIGPP. This plant has a 140 MMcfd processing
capacity. Gas from Kiliwani North is sold at wellhead and is being
delivered into the Tanzanian National Gas Gathering System. A
24-inch spur line from the SSIGPP connects Kiliwani North to a 532
Km 36-inch pipeline which transmits gas to Dar es Salaam.
The Company has prepared a programme to re-enter the Kiliwani
North-1 well to gather downhole data later in the year and
shareholders will be advised accordingly. A resource report by LR
Senergy, completed in May 2015, attributed approximately 28 BCF
gross best estimate Contingent Resource to the Kiliwani North
field. The Company notes that, as a possible result of continued
production following a long period when the well was shut-in, the
wellhead pressure is declining and the Company is reviewing
possible alternatives for remediation in the near future to
maximise recoverable resources. In the absence of a commercial
operations date for the Kiliwani North-1 well, the Company is
planning to update its resource report for this asset as well as
for its other assets in Tanzania. Due to a higher than specified
calorific value for the gas and an advantageous effect of the sales
contract's indexation allowance, gas has been sold during the
reporting period at approximately $3.27 per Mcf.
As part of continuing work over its near-shore interests under
the Kiliwani North Development Licence and the Nyuni Area PSA,
Aminex is conducting a review of existing seismic data to identify
drillable prospects which could be tied back to the National Gas
Gathering System on Songo Songo Island.
Tanzania - Ruvuma PSA
Aminex spudded the Ntorya-2 appraisal well on 21 December 2016
and this was successfully drilled to a total vertical depth of
2,795 metres. At 2,593 metres drilling depth the well encountered a
gross gas-bearing reservoir unit of approximately 51 metres.
Drilling of the reservoir section was associated with significant
gas influxes with high associated pressures. Subsequent to wireline
logging, a 7-inch liner was run and cemented in place from 1,967 to
2,795 metres. Detailed petrophysical analysis identified 31 metres
of net pay.
The well was perforated over a gross interval of 34 metres and
underwent a testing programme for a period of 160 hours, flowing
gas across a variety of choke sizes. The well flow-tested at an
average rate of 17 MMcfd (approximately 2,800 BOED) on a 40/64"
choke. Strong pressure build-up occurred in all instances during
the well test.
According to wireline logs, Ntorya-2 encountered the equivalent
reservoir section at approximately 74 metres higher than in the
Ntorya-1 well. Data from Ntorya-2 is being incorporated into an
updated basin model for the Ruvuma PSA in order to evaluate the
additional targets and liquids potential in the basin.
Utilising data acquired during the drilling of Ntorya-2, Aminex
has been able to update the Pmean un-risked GIIP resource estimates
for the Ntorya discovery to approximately 1.3 TCF. The continuing
work on mapping and basin model studies may further refine these
estimates. These management estimates substantially exceed an
independent resource report by LR Senergy, completed in May 2015,
which attributed an approximately 70 BCF gross best estimate
Contingent Resource to the Cretaceous channel associated with the
Ntorya-1 gas discovery. Using the well results, updated mapping and
the commercialisation study the Group plans to commission a new
independent resources report in due course.
Ntorya-2 was drilled in the onshore Ruvuma Basin to appraise
further the Ntorya location area where the Ntorya-1 gas discovery
previously drilled by the Company showed net pay of 3.5 metres and
flow-tested at 20 MMcfd, with 139 barrels of associated condensate.
The Ntorya field is approximately 40 kilometres from the Madimba
gas processing plant, which receives gas into the Tanzanian
National Gas Pipeline system. Ntorya-2 completes the appraisal
drilling obligations for the Ntorya location area.
In September 2017, the Group submitted a development plan for
the Ntorya appraisal area and has applied for the grant of a
25-year development licence. The development plan is subject to the
review and approval of the Tanzanian authorities and the Company
will provide an update on this and the timing for spudding the
Ntorya-3 well during Q4 2017. As part of the development licence
application and also to identify ways to maximise returns from the
discovery by the Company, Aminex appointed io oil & gas
consulting, a joint venture between Baker Hughes (a GE company) and
McDermott, to prepare a gas commercialisation study to assist with
the development of the Ntorya field. The study has been designed to
identify gas monetisation options available to the Company
including potential early development facilities to supply gas to
local market and enable near term revenue generation.
The Ruvuma PSA comprises two licence areas: the Mtwara Licence
and the Lindi Licence. As well as the Ntorya wells, several further
prospects in the Ruvuma acreage on both Licences have been
identified from the 2014/2015 mapping, including potential
prospects at Likonde and Namisange. During 2016, Aminex received
formal ministerial approval for a one-year extension to the Mtwara
Licence of the Ruvuma PSA, to 8 December 2017. Although the Lindi
Licence technically expired on 28 January 2017, negotiations are
ongoing for an extension to this licence to enable the work
commitments to be carried out in conjunction with the Mtwara
Licence area. The Company has also applied for a two-year extension
to the Mtwara Licence, which includes the Ntorya appraisal licence,
and the Directors have a reasonable expectation that both
extensions will be granted pending ministerial approval.
Under the terms of the Ruvuma PSA, after the grant of a
development plan, the TPDC may elect to contribute 15% of
development costs in order to obtain a participating interest of
15% in production and revenues.
Tanzania - Nyuni Area
Aminex remains focused on projects which will deliver commercial
gas in the near term. A new 3D seismic programme is being prepared
based on the licence area post relinquishment. Aminex expects to
re-tender based on the new programme in order to select a 3D
seismic contractor capable of acquiring high quality 3D seismic
over the key Pande West lead and to identify other potential
prospects in the deep water with a view to bringing them to
drill-ready status. Pande West is analogous to some of the recent
major deep-water discoveries in the vicinity.
Aminex is reviewing ways to enable the potential monetisation of
discoveries on the shelf and deep water through delivery into the
National Gas Gathering System. Although the Company is unlikely to
be in a position to drill an expensive deep water well in the Nyuni
Area without introducing a larger company as a farm-in partner, the
possibility of drilling wells on the continental shelf more
economically remains an option. As part of continuing work over its
near-shore interests under the Kiliwani North Development Licence
and the Nyuni Area PSA, Aminex is conducting a review of existing
data to identify drillable prospects which could be tied back to
the National Gas Gathering System on Songo Songo Island.
The First Extension Period was granted in December 2016
backdated to October 2015. The Company, which believes that the
four-year extension period should start in December 2016, is
seeking clarification from the TPDC on the start date for the
current licence extension period.
Under the terms of the Nyuni Area PSA, after the grant of a
development plan the TPDC may elect to contribute 20% of costs,
excluding exploration costs, in order to obtain a participating
interest of 20% in production and revenues.
Financial Review
Financing and Future Operations
In the first six months of 2017, Aminex has achieved a number of
significant advances in securing the foundations for its future
growth.
During the period, Aminex applied the cash flow from Kiliwani
North operations to the repayment of the corporate loan and in June
Aminex repaid the outstanding balance. The loan repayment was
assisted by the exercise of warrants in May which gave rise to the
gross receipt of $2.18 million in new equity issued. Full repayment
of the corporate debt has been part of the Company's strategy and
the Board is pleased that this has been achieved earlier than
anticipated in this financial year.
Continued average daily production from Kiliwani North of
approximately 15 MMcf has enabled the Company to report a profit of
$1.01 million for the first six months of 2017 compared to a loss
of $2.45 million for the first six months of 2016. At 30 June 2017
Aminex was therefore a debt-free and profitable production
company.
The Board continues to assess alternative means of financing its
operations following completion of the successful Ntorya-2
appraisal well in March which flowed gas at approximately 17 MMcfd.
As well as planning Ntorya-3, Aminex is seeking alternative methods
of funding future development operations at Ntorya, including early
production options which could provide additional revenues to the
Group.
Revenue Producing Operations
Revenues from continuing operations amounted to $4.59 million
(30 June 2016: $0.26 million). The significant growth reflects
Kiliwani North gas revenues which averaged approximately 15 MMcfd.
Production from the Kiliwani North field started on 4 April 2016
and was only at low rates during the period to 30 June 2016 while
the new Songo Songo Island Gas Processing Plant and related
infrastructure were being tested and brought online. During the
first six months of 2017, gross production from the Kiliwani
North-1 well was 2.62 BCF of which Aminex's share was 1.32 BCF.
Following the application of the agreed indexation allowance at the
start of the year, Aminex has achieved an average sales price of
$3.27 per Mcf. Revenues also arose from oilfield services
comprising the provision of technical and administrative services
to joint venture operations: the revenues were $0.26 million for
the period ended 30 June 2017 (30 June 2016: $0.18 million), with
the increase arising from the drilling activity at Ntorya. Cost of
sales was $0.35 million (30 June 2016: $0.24 million) with the cost
of sales for production increasing from $0.06 million for the first
six months of 2016 to $0.09 million for the first six months of
2017 because of a full period of production from Kiliwani North.
The balance of the cost of sales amounting to $0.26 million (30
June 2016: $0.18 million) related to the oilfield services
operations. The depletion charge for Kiliwani North production
amounted to $1.18 million (30 June 2016: $0.02 million).
Accordingly, there was a gross profit of $3.06 million for the
period compared with a gross loss of $0.01 million for the
comparative period.
Group administrative expenses, net of costs capitalised against
projects, were $1.49 million (30 June 2016: $1.35 million). The
expenses for the current period include a share-based payment
charge of $0.29 million relating to options granted to staff in May
2017 compared with a charge of $0.81 million for the comparative
period. On a like-for-like basis, excluding the share-based payment
charge, the Group's administrative expenses for the period under
review were $1.20 million (30 June 2016: $0.54 million), an
increase of $0.66 million. The increase in administrative expense
includes net realised foreign exchange losses of $0.27 million and
additional payroll costs as a result of the Group strengthening its
technical team. Management has continued to maintain strict
expenditure controls and, where possible, to reduce overhead costs.
The Group's resulting net profit from operating activities was
$1.56 million (30 June 2016: loss of $1.59 million).
Finance costs reflect an interest charge of $0.56 million (30
June 2016: $0.86 million). Of this, a charge of $0.54 million (30
June 2016: $0.84 million) relates to the corporate loan: the 36%
reduction reflected the lower loan charge following debt repayments
made during the second half of 2016 and the first half of 2017. The
debt was fully repaid in June 2017 and there will be no further
corporate loan charge in 2017. The remaining finance cost of $0.02
million arose from the unwinding of the discount on the
decommissioning provision (30 June 2016: $0.02 million).
The Group's net profit for the period amounted to $1.01 million
(30 June 2016: loss of $2.45 million).
Balance Sheet
The Group's investment in exploration and evaluation assets
increased from $84.62 million at 31 December 2016 to $93.62 million
at 30 June 2017. The increase included the completion of drilling
operations for the Ntorya-2 well and the subsequent successful
testing operations, as well as licence expenses for the Ruvuma PSA
and the Nyuni Area PSA. After review, the Directors have concluded
that there is no impairment to these assets, taking into account
ongoing discussions with the Tanzanian authorities for the
extension to licence interests under the Ruvuma PSA, which are
pending ministerial approval. The carrying value of property, plant
and equipment has decreased from $11.22 million at 31 December 2016
to $10.04 million at 30 June 2017, representing the depletion
charge on production from the Kiliwani North field. Current assets
amounting to $20.41 million mainly comprise trade and other
receivables of $13.49 million, which as operator includes joint
venture parties' interests in gas revenues, and cash and cash
equivalents of $6.91 million.
Following the repayment of the corporate loan in June, loans and
borrowings have been reduced to nil from the balance of $4.93
million at 31 December 2016. Trade payables amounted to $12.94
million compared with $12.83 at 31 December 2016. This balance
included amounts payable to joint venture partners and the TPDC for
their profit shares under the terms of the PSA. Payables also
include VAT and excise tax payable on gas receivables. The
non-current decommissioning provision increased from $0.46 million
at 31 December 2016 to $0.58 million, the increase relating to the
unwind discount charge of $0.02 million for the period.
Total equity has increased by $4.19 million between 31 December
2016 and 30 June 2017 to $110.54 million. The net movement
comprises the increase in issued capital and share premium of $2.18
million arising from the issue of capital on the exercise of all
outstanding warrants in May; the foreign currency translation
reserve has decreased by $0.72 million; and the movement in
retained earnings comprises the profit of $1.01 million for the
period and the release of the share warrant reserve to retained
earnings on the exercise of warrants in May offset by the
transactions expense of $0.02 million for the shares issued on
exercise of those warrants.
Cash Flows
The resulting net decrease in net cash from operating activities
was $2.40 million (30 June 2016: $0.78 million), after an increase
in debtors of $4.31 million primarily arising on the increase in
the gross receivables from the TPDC (against which monthly payments
have been received after the period end) offset by a reduction in
creditors of $0.59 million and interest payments of $0.54 million.
Net cash outflows from investing activities amounted to $7.49
million (30 June 2016: $16,000). Expenditure on exploration and
evaluation assets in the current period amounted to $7.49 million,
relating to the completion of drilling operations for and the
subsequent testing of Ntorya-2 well planning drilled on the Ruvuma
PSA acreage, together with continuing licence costs. Expenditure on
property, plant and equipment was minimal in the period with no
capital costs incurred on producing assets. The Group received
$0.01 million in interest during the period. In May 2017, the
warrant holder exercised all warrants outstanding and Aminex
received $2.18 million on the issue of the related share capital
excluding transaction expenses of $0.02 million. During the period,
Aminex repaid the balance of the outstanding corporate debt of
$4.93 million. Overall, the decrease in net cash and cash
equivalents for the six months ended 30 June 2017 was $12.65
million compared with $0.79 million for the comparative half-year
period. The balance of net cash and cash equivalents at 30 June
2017 was $6.91 million (31 December 2016: $19.57 million).
Related Party Transactions
There were no related party transactions during the six-month
period to 30 June 2017 that have materially affected the financial
position or performance of the Group. In addition, there were no
changes in the related parties set out in Note 30 to the Financial
Statements contained in the 2016 Annual Report that could have had
a material effect on the financial position or performance of the
Group during the six-month period.
Going Concern
The Directors have given careful consideration to the Group's
ability to continue as a going concern. The Group continuously
monitors and manages its cash flow and liquidity risk. Cash
forecasts are regularly updated and sensitivities re run for
different scenarios, including the production flow and timing of
cash flow from the Group's Kiliwani North producing asset, together
with the timing and cost of the Group's drilling and exploration
activities. The Directors have taken into account the capital raise
of $2.18 million before transaction costs following the exercise of
warrants in May 2017, the outstanding decision by partners to
commit to drilling Ntorya-3 well pending the completion of ongoing
technical work and the final settlement of the corporate loan in
June 2017 thereby enabling securities in relation to the corporate
loan to be removed. In addition, the Group's ability to continue to
fulfil capital expenditure commitments, in particular in its main
licence interests, can be assisted if necessary by the successful
sale of assets, discretion over the timing of planned expenditure
or an alternative method of raising capital. The Directors
concluded that the Group has sufficient capital resources from both
ongoing operating cash flows and existing cash resources to
continue as a going concern for the foreseeable future, that is a
period of not less than twelve months from the date of approval of
these condensed consolidated interim financial statements and
accordingly, they are satisfied that it is appropriate to adopt the
going concern basis of accounting in the preparation of these
condensed consolidated interim financial statements.
Principal Risks and Uncertainties
The Group's strategic objectives for its principal activities,
being the production and development of and the exploration for oil
and gas reserves, are only achievable if certain risks are managed
effectively. The Board has overall accountability for determining
the type and level of risk it is prepared to take. The Board is
assisted by the Risk Committee which seeks to identify risks for
Board consideration and which monitors other risks, the
responsibility for those risks and how they are managed. The
following are considered to be the key risks that may affect the
Group's business, although there are other risks which they
currently deem to be less material that may impact the Group's
performance.
Strategic risks
Development of assets to production - The Group may fail to
expand through the exploration and development of its licences for
which it acts as operator with joint venture partners. The failure
of joint venture partners to pay their working interests may impact
on Aminex's strategy.
Mitigation - Aminex manages its assets to enable the growth of
cash generative business streams with the strategy of generating
cash flow to meet its commitments with internal funds. The Board
considers that the focus of Aminex's activities on development
projects, with exploration potential, will provide value creation
for shareholders rather than an exploration-led strategy. The Group
identifies joint venture partners who are capable of contributing
to operations but Aminex maintains a majority interest in each of
its licences which offers greater upside potential to shareholders
or the possibility of further farmout opportunities to assist with
funding.
Global market conditions and impact of low oil price - Difficult
global market conditions and the decrease in oil prices may from
time to time impact the Group's operations and in particular the
ability to raise equity or debt finance or to allow the Group to
enter into transactions on its assets.
Mitigation - The Group reviews global conditions and manages its
exposure to risk through minimising capital expenditure on high
risk assets and developing fixed price gas projects. Revenues from
producing assets will be used to minimise exposure to global
capital markets with the intention of generating cash flow to meet
capital and debt commitments. Aminex monitors costs closely and
will seek to take advantage of the low-cost environment for capital
commitments where possible.
Operational risks
Exploration risk - Exploration and development activities may be
delayed or adversely affected by factors including in particular:
climatic and oceanographic conditions; equipment failure;
performance of suppliers and exposure to rapid cost increases;
unknown geological conditions resulting in dry or uneconomic wells
or risk of blowout; remoteness of location.
Mitigation - Aminex mitigates exploration risk by reducing the
risk of drilling failure through conducting appropriate studies
including the acquisition, processing and interpretation of
seismic. For drilling operations, the group contracts with
international and local service providers with substantial industry
experience and safety procedures according to Aminex's own high
standards.
Production risks - Operational activities may be delayed or
adversely affected by factors including: blowouts; unusual or
unexpected geological conditions; performance of joint venture
partners on non-operated and operated properties; seepages or leaks
resulting in substantial environmental pollution; increased
operational costs; uncertainty of oil and gas resource estimates;
production, marketing and transportation conditions; actions of
host governments or other regulatory authorities. The Company's gas
revenues relate to production from a single well, Kiliwani North-1.
Although the well continues to produce, wellhead pressure is in
decline and the collection of downhole pressure data is being
considered to determine the causes of the decline. In the event of
adverse downhole pressure data, an increased rate of depletion or
impairment against the carrying cost of the asset may be
required.
Mitigation - Aminex develops, implements and maintains
procedures in order to limit the risk of operational failures on
production assets. Through gas sales agreements, Aminex has an
agreed mechanism to enable reservoirs to be produced optimally
while seeking to meet the requirements of the purchaser and thereby
maximising resources. The Group sells gas at the wellhead which
minimises additional costs by avoiding transportation and marketing
expenses. The Company has prepared a programme to re-enter the
Kiliwani North-1 well to gather downhole data later in the year and
is reviewing possible alternatives for remediation in the near
future to maximise recoverable resources.
Maintaining licence interests - The Group may be unable to meet
or agree amendments to its work programme commitments which may
give rise either to minimum work obligations needing to be paid or
the implementation of default procedures against the Group as
operator which may lead to a licence being rescinded. In the case
of the Ruvuma PSA, Aminex has applied for extensions to both the
Mtwara and Lindi Licences which are pending approval by the
Tanzanian authorities. The TPDC holds security over up to 15% of
profit share for the Kiliwani North Development Licence in the
event that part or all of the work commitments under the terms of
the Ruvuma PSA relating to either the Mtwara or Lindi Licences are
not fulfilled.
Mitigation - Aminex is committed to fulfilling its commitments
and seeks deferrals of or amendments to production sharing terms
through negotiation with the TPDC in order to ensure that
commitments are met even if not in the original timeframe expected.
The Board believes that there is a reasonable expectation that
Aminex will be able to obtain licence extensions to the Mtwara and
Lindi Licences based on discussions with the Tanzanian authorities.
Aminex also intends to meet its commitments with each exploration
well on drilled on the Ruvuma PSA reducing the security over the
Kiliwani North Development Licence.
Compliance risks
Political risks - Aminex may be subject to political, economic,
regulatory, legal, and other uncertainties (including but not
limited to terrorism, military repression, war or other unrest). As
Aminex's principal activities are in a developing nation, there are
risks of nationalisation or expropriation of property, changes in
and interpretation of national laws and energy policies. The
Tanzanian government passed three new laws in July 2017, affecting
the mining and energy sectors - the Natural Wealth and Resources
(Permanent Sovereignty) Act; the Written Laws (Miscellaneous
Amendments) Act; and the Natural Wealth and Resources Contracts
(Review and Re-Negotiation of Unconscionable Terms). This new
legislation includes the right of the Tanzanian authorities to
renegotiate 'unconscionable terms' in agreements.
Mitigation - Aminex monitors international and national
political risk in relation to its interests, liaising with
governmental and other key stakeholders in its countries of
operations. The Company has reviewed and continues to monitor the
new legislation. Based on the Board's current understanding of this
new legislation and given the existing terms and conditions of our
PSAs it is unclear if there will be any material impact on Aminex's
operations in Tanzania. From time to time Aminex seeks to spread
asset and regional risk in order to reduce exposure to one business
or region.
Health and safety - The main health and safety risks for the
Group occur during drilling operations and from production
operations.
Mitigation - The Group develops, implements and maintains
effective health and safety procedures, including environmental
issues and security, to ensure robust safeguards for well control
and drilling operations are in place.
Legal compliance - The Group could suffer penalties or damage to
reputation through failure to comply with legislation or other
regulations, in particular those over bribery and corruption, and
these risks may be increased when operating in certain regions of
the world.
Mitigation - Aminex manages risk of legal compliance failure
through the implementation and monitoring of high standards to
minimise the risk of corrupt or anti-competitive behaviour. All
employees and consultants are required to confirm their
understanding of the Group's anti-bribery policy.
Financial risks
Credit risk - All of the Group's revenues arising from the sale
of natural gas is to one customer, the TPDC, which is the gas
aggregator and operator of the National Gas Pipeline in Tanzania.
Sales of natural gas and the credit terms relating to the sales are
governed by a gas sales agreement. The recoverability and timing of
receipts are therefore dependent on one customer.
Mitigation - The credit risk arising from sales to TPDC can be
mitigated by a letter of credit which is required under the gas
sales agreement once a commercial operations date has been
declared. In the absence of regular payments from TPDC, Aminex
could suspend supply until the indebtedness has been reduced.
Currency risk - Although the reporting currency is the US
dollar, which is the currency most commonly used in the pricing of
petroleum commodities and for significant exploration and
production costs, a significant proportion of the Group's other
expenditure (in particular central administrative costs) is made in
local currencies (as are the Company's equity fundings), and
fluctuations in exchange rates may significantly impact the results
of the Group and the results between periods, thus creating
currency exposure.
Mitigation - The Group has a policy of minimising exposure to
foreign currency rates by holding the majority of the Group's funds
in US dollars.
Forward Looking Statements
Certain statements made in this half-yearly financial report are
forward-looking statements. Such statements are based on current
expectations and are subject to a number of risks and uncertainties
that could cause actual events or results to differ materially from
the expected future events or results referred to in these
forward-looking statements.
Statement of the Directors in respect of the Half-Yearly
Financial Report
Each of the directors who held office at the date of this
report, confirm their responsibility for preparing the half-yearly
financial report in accordance with the Transparency (Directive
2004/109/EC) Regulations 2007 (as amended), the Transparency Rules
of the Central Bank of Ireland and the Disclosure and Transparency
Rules of the UK Financial Conduct Authority and with IAS 34 Interim
Financial Reporting, as adopted by the EU and to the best of each
person's knowledge and belief:
-- the condensed consolidated interim financial statements
comprising the condensed consolidated interim income statement, the
condensed consolidated interim statement of comprehensive income,
the condensed consolidated interim balance sheet, the condensed
consolidated interim statement of changes in equity, the condensed
consolidated interim statement of cashflows and the related
explanatory notes have been prepared in accordance with IAS 34
Interim Financial Reporting as adopted by the EU.
-- the interim management report includes a fair review of the information required by:
(a) Regulation 8(2) of the Transparency (Directive 2004/109/EC)
Regulations 2007, being an indication of important events that have
occurred during the first six months of the financial year and
their impact on the condensed set of financial statements; and a
description of the principal risks and uncertainties for the
remaining six months of the year; and
(b) Regulation 8(3) of the Transparency (Directive 2004/109/EC)
Regulations 2007, being related party transactions that have taken
place in the first six months of the current financial year and
that have materially affected the financial position or performance
of the entity during that period; and any changes in the related
party transactions described in the last annual report that could
do so.
On behalf of the Board
J.C. BHATTACHERJEE M.V. WILLIAMS
Chief Executive Officer/Director Chief Financial
Officer/Director/Company Secretary
28 September 2017
Independent Review Report to Aminex PLC
Introduction
We have been engaged by the Company to review the condensed
consolidated financial statements (the "interim financial
statements") in the half-year financial report for the six months
ended 30 June 2017, which comprise the condensed consolidated
income statement, condensed consolidated statement of comprehensive
income, the condensed consolidated balance sheet, the condensed
consolidated statement of changes in equity, the condensed
consolidated cash flow statement, and the related explanatory
notes. Our review was conducted having regard to the Financial
Reporting Council's International Standard on Review Engagements
(UK and Ireland) 2410, 'Review of Interim Financial Information
Performed by the Independent Auditor of the Entity' ("ISRE
2410").
Conclusion
Based on our review, nothing has come to our attention that
causes us to believe that the condensed consolidated interim
financial statements in the half-year report for the six months
ended 30 June 2017 are not prepared, in all material respects, in
accordance with International Accounting Standard 34, 'Interim
Financial Reporting', as adopted by the European Union (the "EU"),
the Transparency (Directive 2004/109/EC) Regulations 2007 as
amended ("the TD Regulations"), the Transparency Rules of the
Central Bank of Ireland and the Disclosure and Transparency Rules
of the UK's Financial Conduct Authority ("FCA").
Basis of our report, responsibilities and restriction on use
The half-year financial report is the responsibility of, and has
been approved by, the Directors. The Directors are responsible for
preparing the half-year report in accordance with the TD
Regulations and the Transparency Rules of the Central Bank of
Ireland.
As disclosed in note 1, the interim financial statements of the
Company are prepared in accordance with International Financial
Reporting Standards ("IFRS") as adopted by the EU. The directors
are responsible for ensuring that the condensed interim financial
statements included in this half-year financial report have been
prepared in accordance with IAS 34, Interim Financial Reporting, as
adopted by the EU. Our responsibility is to express to the company
a conclusion on the interim financial statements presented in the
half-year financial report based on our review.
We conducted our review having regard to the Financial Reporting
Council's International Standard on Review Engagements (UK and
Ireland) 2410 Review of Interim Financial Information Performed by
the Independent Auditor of the Entity. A review of interim
financial information consists of making enquiries, primarily of
persons responsible for financial and accounting matters, and
applying analytical and other review procedures. A review is
substantially less in scope than an audit conducted in accordance
with International Standards on Auditing (UK and Ireland) and
consequently does not enable us to obtain assurance that we would
become aware of all significant matters that might be identified in
an audit. Accordingly, we do not express an audit opinion.
We read the other information contained in the half-year
financial report and consider whether it contains any apparent
misstatements or material inconsistencies with the information
contained in the condensed consolidated interim financial
statements. If we become aware of any apparent material
misstatements or inconsistencies we consider the implications for
our report.
This report is made solely to the company in accordance with the
terms of our engagement to assist the company in meeting the
requirements of the Transparency (Directive 2004/109/EC)
Regulations 2007 as amended ("the TD Regulations"), the
Transparency Rules of the Central Bank of Ireland and the
Disclosure and Transparency Rules of the UK's FCA. Our review has
been undertaken so that we might state to the company those matters
we are required to state to it in this report and for no other
purpose. To the fullest extent permitted by law, we do not accept
or assume responsibility to anyone other than the company for our
review work, for this report, or for the conclusions we have
reached.
KPMG
Chartered Accountants
1 Stokes Place
St. Stephen's Green,
Dublin 2
28 September 2017
Aminex PLC
CONDENSED CONSOLIDATED INTERIM INCOME STATEMENT
for the six months ended 30 June 2017
Notes Unaudited Unaudited Audited
6 months 6 months Year ended
ended ended 31 December
30 June 30 June 2016
2017 2016 US$'000
US$'000 US$'000
Continuing operations
Revenue 2 4,592 255 4,934
Cost of sales 2 (1,531) (261) (1,688)
Gross profit/(loss) 3,061 (6) 3,246
Administrative
expenses 3 (1,490) (1,353) (2,840)
Depreciation of
other assets (3) (5) (11)
---------- ---------- -------------
Total administrative
expenses (1,493) (1,358) (2,851)
---------- ---------- -------------
Profit/(loss) from
operating activities
before other items 1,568 (1,364) 395
Gain on part disposal
of development
asset 4 - 344 344
Reduction in fair
value of other
receivables - (556) (1,971)
Impairment loss
on available for
sale assets 11 (4) (14) (18)
Profit/(loss) from
operating activities 1,564 (1,590) (1,250)
Finance income 5 11 - 13
Finance costs 6 (562) (862) (1,297)
---------- ---------- -------------
Profit/(loss) before
income tax 1,013 (2,452) (2,534)
Income tax expense 7 - - -
Profit/(loss) for
the period attributable
to equity holders
of the Company 2 1,013 (2,452) (2,534)
---------- ---------- -------------
Earnings per share
from continuing
activities
Basic (US cents) 8 0.03 (0.12) (0.10)
Diluted (US cents) 0.03 (0.12) (0.10)
---------- ---------- -------------
CONDENSED CONSOLIDATED INTERIM STATEMENT OF COMPREHENSIVE
INCOME
for the six months ended 30 June 2017
Unaudited Unaudited Audited
6 months 6 months Year ended
ended ended 31 December
30 June 30 June 2016
2017 2016 US$'000
US$'000 US$'000
Profit/(loss) for
the period 1,013 (2,452) (2,534)
Other comprehensive
income
Items that are or
maybe reclassified
subsequently to profit
or loss:
Currency translation
differences 719 (148) (1,559)
Total comprehensive
income/(expense) for
the period attributable
to the equity holders
of the Company 1,732 (2,600) (4,093)
---------- ---------- -------------
Aminex PLC
CONDENSED CONSOLIDATED INTERIM BALANCE SHEET
At 30 June 2017
Unaudited Unaudited Audited
30 June 30 June 31 December
2017 2016 2016
Notes US$'000 US$'000 US$'000
ASSETS
Exploration and
evaluation assets 9 93,622 80,508 84,618
Property, plant
and equipment 10 10,039 12,432 11,217
Available for sale
assets 11 - 8 4
Trade and other
receivables - 1,378 -
Total non-current
assets 103,661 94,326 95,839
Current assets
Trade and other
receivables 12 13,493 1,213 9,179
Cash and cash equivalents 13 6,913 1,334 19,567
--------- ------------- ------------
Total current assets 20,406 2,547 28,746
--------- ------------- ------------
Total assets 124,067 96,873 124,585
--------- ------------- ------------
EQUITY
Issued capital 69,062 67,192 68,874
Share premium 122,267 96,036 120,274
Other undenominated
capital 234 234 234
Share option reserve 4,187 3,894 3,894
Share warrant reserve 16 - 3,436 3,436
Foreign currency
translation reserve (2,299) (1,607) (3,018)
Retained earnings (82,907) (85,713) (87,341)
--------- ------------- ------------
TOTAL EQUITY 110,544 83,472 106,353
--------- ------------- ------------
LIABILITIES
Non-current liabilities
Decommissioning
provision 579 455 476
--------- ------------- ------------
Total non-current
liabilities 579 455 476
--------- ------------- ------------
Current liabilities
Loans and borrowings 14 - 9,017 4,931
Trade and other
payables 12,944 3,929 12,825
Total current liabilities 12,944 12,946 17,756
--------- ------------- ------------
Total liabilities 13,523 13,401 18,232
--------- ------------- ------------
TOTAL EQUITY AND
LIABLITIES 124,067 96,873 124,585
--------- ------------- ------------
Aminex PLC
CONDENSED CONSOLIDATED INTERIM STATEMENT OF CHANGES IN
EQUITY
for the six months ended 30 June 2017
Attributable to equity shareholders of the Company
Foreign
currency
Other Share Share translation
Share Share undenominated option warrant reserve Retained Total
capital premium capital reserve reserve fund earnings equity
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
Balance at
1 January
2016 67,192 96,036 234 3,683 3,054 (1,459) (83,864) 84,876
Comprehensive
income
Loss for the
period - - - - - - (2,452) (2,452)
Currency
translation
differences - - - - - (148) - (148)
Transactions
with
shareholders
of the Company
recognised
directly in
equity
Share based
payment
charge - - - 814 - - - 814
Share options
reserve
adjustment - - - (603) - - 603 -
Share warrants
granted - - - - 382 - - 382
Balance at
1 July 2016 67,192 96,036 234 3,894 3,436 (1,607) (85,713) 83,472
Comprehensive
income
Profit for
the period - - - - - - (82) (82)
Currency
translation
differences - - - - - (1,411) - (1,411)
Transactions
with
shareholders
of the Company
recognised
directly in
equity
Shares issued 1,682 24,238 - - - - (1,546) 24,374
Balance at
1 January
2017 68,874 120,274 234 3,894 3,436 (3,018) (87,341) 106,353
Comprehensive
income
Profit for
the period - - - - - - 1,013 1,013
Currency
translation
differences - - - - - 719 - 719
Transactions
with
shareholders
of the Company
recognised
directly in
equity
Shares issued 188 1,993 - - - - (15) 2,166
Share based
payment
charge - - - 293 - - - 293
Share warrants
exercised - - - - (3,436) - 3,436 -
---------- ---------- --------------- --------- --------- ------------- ----------- ----------
Balance at
30 June 2017
(unaudited) 69,062 122,267 234 4,187 - (2,299) (82,907) 110,544
---------- ---------- --------------- --------- --------- ------------- ----------- ----------
Aminex PLC
CONDENSED CONSOLIDATED INTERIM STATEMENT OF CASHFLOWS
for the six months ended 30 June 2017
Unaudited Unaudited Audited
6 months 6 months Year ended
ended ended 31 December
30 June 30 June 2016
2017 2016 US$'000
US$'000 US$'000
Operating activities
Profit/(loss) for the financial
period 1,013 (2,452) (2,534)
Depletion and depreciation 1,182 25 1,248
Share based payment charge 293 814 814
Finance income (11) - (13)
Finance costs 562 862 1,297
Gain on disposal of interest
in jointly controlled operations - (344) (344)
Impairment of other receivables - 556 1,971
Impairment of available
for sale assets 4 14 18
Increase in trade and other
receivables (4,316) (590) (8,595)
(Decrease)/increase in
trade and other payables (591) 337 5,361
--------- --------- ------------
Cash absorbed by operations (1,864) (778) (777)
Interest paid (540) - (2,419)
--------- --------- ------------
Net cash outflows from
operating activities (2,404) (778) (3,196)
--------- --------- ------------
Investing activities
Proceeds from sale of development
asset - 567 567
Acquisition of property,
plant and equipment (4) (69) (128)
Expenditure on exploration
and evaluation assets (7,492) (514) (2,110)
Interest received 11 - 13
--------- --------- ------------
Net cash used in investing
activities (7,485) (16) (1,658)
--------- --------- ------------
Financing activities
Proceeds from the issue
of share capital 2,181 - - 25,920
Payment of transaction
costs on issue of share
capital (15) - (1,546)
Loans repaid (4,931) - (2,081)
Net cash (outflows)/inflows
from financing activities (2,765) - 22,293
--------- --------- ------------
Net (decrease)/increase
in cash and cash equivalents (12,654) (794) 17,439
Cash and cash equivalents
at 1 January 19,567 2,128 2,128
--------- --------- ------------
Cash and cash equivalents
at end of the financial
period 6,913 1,334 19,567
--------- --------- ------------
Aminex PLC
NOTES TO THE CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
(unaudited)
for the six months ended 30 June 2017
1. Basis of preparation
The condensed consolidated interim financial statements for the
six months ended 30 June 2017 are unaudited but have been reviewed
by the auditor, having regard to ISRE 2410 (UK & Ireland). The
financial information presented herein does not amount to statutory
financial statements that are required by Part 6 of Chapter 4 of
the Companies Act 2014 to be annexed to the annual return of the
Company. The statutory financial statements for the financial year
ended 31 December 2016 were annexed to the annual return and filed
with the Registrar of Companies. The audit report on those
statutory financial statements was unqualified.
The condensed consolidated interim financial statements have
been prepared in accordance with IAS 34 Interim Financial Reporting
as adopted by the EU.
The financial information contained in the condensed interim
financial statements has been prepared in accordance with the
accounting policies set out in the 2016 Annual Report and
Accounts.
These condensed consolidated interim financial statements were
approved by the Board of Directors on 28 September 2017.
(i) Going concern
The condensed consolidated interim financial statements of the
Company and the Group are prepared on a going concern basis.
The Directors have given careful consideration to the Group's
ability to continue as a going concern. The Group continuously
monitors and manages its cash flow and liquidity risk. Cash
forecasts are regularly updated and sensitivities re run for
different scenarios, including the production flow and timing of
cash flow from the Group's Kiliwani North producing asset, together
with the timing and cost of the Group's drilling and exploration
activities. The Directors have taken into account the capital raise
of $2.18 million before transaction costs following the exercise of
warrants in May 2017, the outstanding decision by partners to
commit to drilling Ntorya-3 well pending the completion of ongoing
technical work and the final settlement of the corporate loan in
June 2017 thereby enabling securities in relation to the corporate
loan to be removed. In addition, the Group's ability to continue to
fulfil capital expenditure commitments, in particular in its main
licence interests, can be assisted if necessary by the successful
sale of assets, discretion over the timing of planned expenditure
or an alternative method of raising capital. The Directors
concluded that the Group has sufficient capital resources from both
ongoing operating cash flows and existing cash resources to
continue as a going concern for the foreseeable future, that is a
period of not less than twelve months from the date of approval of
these condensed consolidated interim financial statements and
accordingly, they are satisfied that it is appropriate to adopt the
going concern
basis of accounting in the preparation of these condensed
consolidated interim financial statements.
(ii) Use of judgments and estimates
The preparation of the condensed consolidated interim financial
statements requires management to make judgments, estimates and
assumptions that affect the application of accounting policies and
the reported amounts of assets, liabilities, income and expenses.
Actual results may differ from these estimates.
Estimates and underlying assumptions are reviewed on an ongoing
basis. Revisions to accounting estimates are recognised in the
period in which the estimates are revised and in any future periods
affected.
The Directors believe that the Group's critical judgments, which
are those that require management's most subjective and complex
judgments, are those described below. These critical accounting
judgments and other uncertainties affecting application of the
Group's accounting policies and the sensitivity of reported results
to changes in conditions and assumptions, are factors to be
considered in reviewing the interim financial statements.
The Directors consider the critical judgments in applying
accounting policies to be related to the ability of the Group to
continue as a going concern, valuation of exploration and
evaluation assets and the depletion and decommissioning costs of
property, plant and equipment and valuation of trade receivables.
The Directors are required to estimate the expected remaining
useful life of the oil and gas producing assets, the future capital
expenditure required to recover oil and gas reserves and the future
prices of oil and gas in assessing these balances. Future revisions
to these estimates and their underlying assumptions could arise
from results of drilling activity, movements in oil and gas prices
and cost inflation in the industry. Further details are set out in
Notes 9 and 10 to these financial statements. The Directors have
also considered whether trade receivables due from the Tanzania
Petroleum Development Corporation are impaired at 30 June 2017 and
that no provision for impairment is required against the balance at
that date. The Directors are required to consider the Group's
ability to continue as a going concern. Further details are set out
in the going concern paragraph above.
Measurement of fair values
Management use the fair value hierarchy, levels 1, 2 and 3 (as
set out on page 52 of the 2016 Annual Report), for determining and
disclosing the fair values of financial instruments by valuation
technique. The carrying value of the Group's financial instruments
are considered by management to reflect fair value given the short
term nature of these.
(iii) New accounting standards and interpretations adopted
Below is a list of standards and interpretations that were
required to be applied in the period ended 30 June 2017. There was
no material impact to the financial statements in the period from
the application of these.
(a) New standards required to be applied to an entity with
financial reporting period beginning on 1 January 2017
The standards adopted in the 2017 half yearly financial report
are the same as those adopted in the 2016 Annual Report and
Accounts.
(b) New standards endorsed by the EU and available for early
adoption
Description EU effective
date (periods
beginning)
IFRS 15: Revenue from Contracts with 1 January
Customers (May 2014) including amendments 2018
to IFRS 15
IFRS 9: Financial instruments 1 January
2018
The adoption of these standards may result in future changes to
existing accounting policies and disclosures. The Company is
currently evaluating the impact that these standards will have on
results of operations and financial position.
IFRS 15: Revenue from Contracts with Customers. IFRS 15
specifies how and when an IFRS reporter will recognise revenue as
well as requiring such entities to provide users of financial
statements with more informative, relevant disclosures. The
standard provides a single, principles based five-step model to be
applied to all contracts with customers. The core principle of IFRS
15 is that an entity will recognise revenue to depict the transfer
of promised goods or services to customers in an amount that
reflects the consideration to which the entity expects to be
entitled in exchange for those goods or services. With regard to
the gas sales agreement with the Tanzania Petroleum Development
Corporation the Company is still reviewing the impact that this has
on its accounting policies and disclosures but currently believes
there would not be any material impact.
IFRS 9: Financial Instruments. IFRS 9 which includes new
requirements for the classification and measurement of financial
assets. The Company is evaluating the impact of this standard on
the consolidated financial statements.
2. Segmental disclosure - continuing operations
The Group considers that its continuing operating segments
consist of (i) Producing Oil and Gas Assets, (ii) Exploration
Assets and (iii) Oilfield Services and Group Costs. These segments
are those that are reviewed regularly by the Chief Executive
Officer (Chief Operating Decision Maker) to make decisions about
resources to be allocated to the segment and assess its performance
and for which discrete financial information is available. However
it further analyses these by region for information purposes.
Segment results include items directly attributable to the segment
as well as those that can be allocated on a reasonable basis.
Unallocated items comprise mainly of head office expenses, cash
balances and borrowings.
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2017 2016 2016
US$'000 US$'000 US$'000
Segmental revenue
Africa - producing
assets 4,329 76 4,572
Africa - provision
of oilfield services 263 179 362
Total revenue 4,592 255 4,934
---------- ---------- -------------
Revenue from Africa producing assets for the
current period is significantly higher than in
the comparative period due to a full period of
sales from Kiliwani North compared to revenues
generated from April 2016 onwards in the six
months to June 2016.
Cost of sales
Africa - production
costs 89 62 90
Africa - depletion 1,179 20 1,237
Africa - other cost
of sales 263 179 361
Total cost of sales 1,531 261 1,688
---------- ---------- -------------
Segment profit/(loss)
for the financial period
Africa - producing
oil and gas assets 2,966 57 3,134
Africa - exploration
assets (240) 12 (388)
Europe - group costs
(1) (1,713) (2,521) (5,280)
Group profit/(loss)
for the period 1,013 (2,452) (2,534)
---------- ---------- -------------
Segment assets
Africa - producing
oil and gas assets 21,820 12,422 18,114
Africa - exploration
assets 97,139 82,793 91,264
Europe - group assets
(2) 5,108 1,658 15,207
Total assets 124,067 96,873 124,585
---------- ---------- -------------
Segment liabilities
Africa - producing
oil and gas assets 4,260 566 5,694
Africa - exploration
assets 8,710 3,065 7,122
Europe - oilfield services
and group assets (3) 553 9,770 5,416
Total liabilities 13,523 13,401 18,232
---------- ---------- -------------
(1) Group costs primarily comprise impairment
provisions, interest expense on financial liabilities
and salary and related costs.
(2) Group assets primarily comprise
cash and working capital.
(3) Group liabilities primarily comprise
loans and borrowings and trade payables
and related costs.
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2017 2016 2016
US$'000 US$'000 US$'000
Capital expenditure
Africa - exploration
assets 13,677 644 4,754
Africa - producing assets - 163 161
Europe - oilfield services/Group
costs 4 5 15
Total capital expenditure 13,681 812 4,930
---------- ---------- -------------
Non-cash items
Europe: depreciation
- Group assets 3 5 11
Africa: depletion - Producing
assets 1,179 20 1,237
Impairment of other receivables - 556 1,971
Impairment provision
against available for
sale assets 4 14 18
Interest expense on financial
liabilities measured
at amortised cost 540 841 1,255
Other finance costs -
decommissioning provision
interest charge 22 21 42
Equity-settled share-based-payment
expenses 293 814 814
3. Share based payments
The following expenses have been recognised in the income
statement arising on share based payments and included within
administrative expenses:
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2017 2016 2016
US$'000 US$'000 US$'000
Share based payment charge
on vesting of options 293 814 814
The fair values of options granted in the period in accordance
with the terms of the Aminex PLC Executive Share Option Scheme were
calculated using the following inputs into the binomial
option-pricing model:
Date of grant 3 May 2017
Contractual life 3 years
Exercise price Stg 4.99
pence
Market price Stg 4.99
pence
Number of options granted (immediate vesting) 15,000,000
Expected volatility 45%
Vesting conditions Immediate
Fair value per option Stg 1.51
pence
Expected dividend yield -
Risk-free rate 0.001%
-----------
The binomial option-pricing model is used to estimate the fair
value of the Company's share options because it better reflects the
possibility of exercise before the end of the options' life. The
binomial option-pricing model also integrates possible variations
in model inputs such as risk-free interest rates and other inputs,
which may change over the life of the options.
4. Part disposal of property, plant and equipment
In the prior period, the Company completed the disposal of
1.0526% of its interest in the Kiliwani North Development Licence
to Solo Oil plc for a consideration of US$0.57 million giving rise
to a profit on disposal of US$0.34 million. There have been no
further disposals of interest in the Kiliwani North Development
Licence in the current period.
5. Finance income
Audited
Unaudited Unaudited year ended
6 months 6 months 31 December
ended ended 2016
30 June 30 June US$'000
2017 2016
US$'000 US$'000
Deposit interest income 11 - 13
------------ ------------ -------------
6. Finance costs
Unaudited Unaudited Audited
6 months 6 months year ended
ended ended 31 December
30 June 30 June 2016
2017 2016 US$'000
US$'000 US$'000
Interest expense on
financial liabilities
measured at amortised
cost 540 841 1,255
Other finance costs
- decommissioning provision
interest charge 22 21 42
562 862 1,297
---------- ---------- -------------
Included in finance costs for the period is an interest charge
of US$540,000 in respect of the US$8 million corporate loan
facility, which has been calculated using the effective interest
rate method. The outstanding loan balance was fully repaid in the
period.
7. Tax
The Group has not provided any tax charge for the six month
periods ended 30 June 2017 and 30 June 2016 or for the year ended
31 December 2016. The Group's operating divisions have accumulated
losses which are expected to exceed profits earned by operating
entities for the foreseeable future.
8. Earnings per share from continuing activities
The basic profit per Ordinary Share is calculated using a
numerator of the profit for the financial period and a denominator
of the weighted average number of Ordinary Shares in issue for the
financial period. The diluted profit per Ordinary Share is
calculated using a numerator of the profit for the financial period
and a denominator of the weighted average number of Ordinary Shares
outstanding and adjusted for the effect of all potentially dilutive
shares, including the share options and share warrants, assuming
that they have been converted.
The calculations for the basic and diluted earnings per share of
the financial periods ended 30 June 2017, 30 June 2016 and the year
ended 31 December 2016 are as follows:
Unaudited Unaudited Audited
6 months 6 months Year ended
ended ended 31 December
30 June 30 June 2016
2017 2016
Numerator for basic
and diluted earnings
per share:
Profit/(loss) for the
financial period (US$'000) 1,013 (2,452) (2,534)
------------ ------------ -------------
Weighted average number
of shares:
Weighted average number
of ordinary shares ('000) 3,513,133 1,976,205 2,600,190
------------ ------------ -------------
Basic earnings per share
(US cents) 0.03 (0.12) (0.10)
Diluted earnings per
share (US cents) 0.03 (0.12) (0.10)
------------ ------------ -------------
The diluted earnings per share for the current period is
adjusted to show the potential dilution if employee share options
are converted into shares. The weighted average number of diluted
shares is increased by 241.6 million compared to the weighted
average number of basic shares, after adding back employee share
options and share warrants that are deemed to be in issue for the
whole of the period under review. This results in a diluted
weighted average number of shares of 3,754.5 million. There were
143.5 million share options outstanding at 30 June 2017 with no
share warrants in issue at the end of the period.
There is no difference between the basic loss per Ordinary Share
and the diluted loss per Ordinary Share for the financial period
ended 30 June 2016 and the year ended 31 December 2016 as all
potentially dilutive Ordinary Shares outstanding were
anti-dilutive. There were 156.7 million anti-dilutive share options
at 30 June 2016 and 128.5 million at 31 December 2016. In addition
to this there were 167.6 million share warrants in issue at both 30
June 2016 and 31 December 2016.
9. Exploration and evaluation assets
Cost US$'000
At 1 January 2017 89,699
Additions 9,004
---------
At 30 June 2017 98,703
---------
Provisions for impairment
At 31 December 2016 and 30
June 2017 5,081
Net book value
At 30 June 2017 93,622
---------
At 31 December 2016 84,618
---------
The Group does not hold any property, plant and equipment within
exploration and evaluation assets.
The additions to exploration and evaluation assets during the
period relate mainly to the completion of drilling operations for
the Ntorya-2 appraisal well and the subsequent successful testing
of the well. Other additions include geophysical and geological
work, administrative and licence costs associated with the Ruvuma
and Nyuni Area PSAs.
The Directors have considered the licence, exploration and
appraisal costs incurred in respect of its exploration and
evaluation assets. These assets are carried at historical cost
except for provisions against the Nyuni-1 well, the cost of seismic
acquired over relinquished blocks and obsolete stock. These assets
have been assessed for impairment and in particular with regard to
the remaining licence terms, likelihood of renewal, likelihood of
further expenditures and ongoing acquired data for each area, as
more fully described in the Operations Report. In December 2016,
the Tanzanian authorities granted an extension to the Nyuni Area
licence which, pending confirmation from the TPDC, has a licence
period ending in October 2019 and which crystallised previous
arrangements for the deferral of licences commitments from the
initial Work Period and proposed relinquishment blocks against
which provision was made in the year ended 31 December 2015. The
Tanzanian authorities also granted a one-year extension to the
Mtwara Licence, which together with the Lindi Licence, comprises
the Ruvuma Production Sharing Agreement. The Mtwara Licence, which
includes the Ntorya appraisal area, has a scheduled expiry date in
December 2017. Application has been made for extensions to both the
Mtwara and Lindi Licences. The Directors have also taken into
account ongoing negotiations with the Tanzanian authorities over
the extension to the Lindi Licence. The Lindi Licence was scheduled
to expire in January 2017 but the Directors have a reasonable
expectation of obtaining an extension to the Lindi Licence. If the
Lindi Licence is not extended, an impairment against the carrying
value of the Lindi Licence, which includes the Likonde-1 well, may
be necessary. The Directors are satisfied that there are no further
indicators of impairment but recognise that future realisation of
these oil and gas assets is dependent on further successful
exploration, appraisal and development activities and the
subsequent economic production of hydrocarbon reserves.
10. Property, plant and equipment
Development
property Other
- Tanzania assets Total
US$'000 US$'000 US$'000
Cost
At 1 January 2017 12,440 127 12,567
Additions in the period - 4 4
Disposals in the period - (74) (74)
Exchange rate adjustment - 3 3
At 30 June 2017 12,440 60 12,500
------------ --------- --------
Depreciation and depletion
At 1 January 2017 1,237 113 1,350
Charge for the period 1,179 3 1,182
Disposals in the period (74) (74)
Exchange rate adjustment - 3 3
At 30 June 2017 2,416 45 2,461
------------ --------- --------
Net book value
At 30 June 2017 10,024 15 10,039
------------ --------- --------
At 31 December 2016 11,203 14 11,217
------------ --------- --------
Following the award of the Kiliwani North Development Licence by
the Tanzanian Government in April 2011, the carrying cost relating
to the development licence was reclassified as a development asset
under property, plant and equipment, in line with accounting
standards and the Group's accounting policies. Production from the
Kiliwani North-1 well commenced on 4 April 2016 and the depletion
charge for the year has been calculated with reference to the
contingent resources ascribed to the field in 2015. The resources
remain contingent on the notification of a commercial operations
date by the TPDC in accordance with the Gas Sales Agreement with
the TPDC. The Directors have reviewed the carrying value of the
asset at 30 June 2017 based on estimated discounted future
cashflows and are satisfied that no impairment has occurred.
11. Available for sale assets
An impairment against the carrying value of a listed investment
has been expensed in the income statement.
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2017 2016 2016
At beginning of
period 4 22 22
Impairment loss
charged to income
statement (4) (14) (18)
At end of period - 8 4
---------- ---------- -------------
12. Trade and other receivables
Trade and other receivables amounted to US$13.49 million at the
period end (30 June 2016: US$1.21 million). The increase is largely
due to debtors relating to gas sales from Kiliwani North. Included
in trade and other receivables is an amount of US$9.20 million due
from the TPDC for the gross receivables due to the joint venture
parties for gas sales from Kiliwani North. Since the period end,
the Group has received monthly payments from the TPDC to reduce the
period end trade receivable. The receivable includes amounts
received on behalf of joint venture parties and taxes which are
included in payables and primarily only payable once funds have
been received.
13. Cash and cash equivalents
Included in cash and cash equivalents is an amount of US$0.73
million (30 June 2016: US$0.18 million) held on behalf of partners
in joint operations.
14. Loans and borrowings
During the period, the Company paid US$5.5 million comprising
capital interest and redemption premium and thereby settled its
corporate loan facility in full. Documentation for the release of
related securities is being finalised.
An amount of US$0.54 million (30 June 2016: US$0.84 million) has
been charged to the Group Income Statement in respect of the
finance cost of the facility (see Note 6).
15. Financial instruments
(a) Carrying amounts and fair values
The following table shows the carrying amounts and fair values
of financial assets and financial liabilities, including their
levels in the fair value hierarchy for financial instruments
measured at fair value for the prior year. It does not include fair
value information for financial assets and liabilities not measured
at fair value if the carrying amount is a reasonable approximation
of fair value.
Carrying amount Fair value
Non-current Current
trade trade
and other and other Level Level
receivables receivables Total 1 3 Total
US$'000 US$'000 US$'000 US$'000 US$'000 US$'000
30 June 2017
Available for - - - - - -
sale assets
------------- ------------- -------- -------- -------- --------
- - - - - -
------------- ------------- -------- -------- -------- --------
31 December
2016
Available for
sale assets 4 - 4 4 - 4
4 - 4 4 - 4
------------- ------------- -------- -------- -------- --------
(b) Measurement of fair values
Where the market value of other investments is available, the
fair values are determined using the bid market price without
deduction of any transaction costs.
16. Share warrant reserve
On 22 May 2017, the sole warrant holder exercised 167,561,032
warrants over ordinary shares with a nominal value of EUR0.001 each
("Ordinary Shares"). All the warrants exercised had an exercise
price of Stg 1 pence per warrant. Accordingly, 167,561,032 new
Ordinary Shares were issued for which the Company received gross
proceeds of US$2.18 million. The balance of US3.44 million relating
to the warrants included in the share warrant reserve was therefore
transferred to retained earnings. The warrants were exercisable by
30 June 2017. No warrants remain outstanding.
17. Commitments - exploration activity
In accordance with the relevant PSA, Aminex has a commitment to
contribute its share of the following outstanding work
programmes:
(a) Following the grant of the extension to the Nyuni Area PSA,
Tanzania, the terms of the licence require the acquisition of 600
square kilometres of 3D seismic over the deep-water sector of the
licence, and drilling of four wells, on the continental shelf or in
the deep-water, by October 2019 (or December 2020 pending advice
from the Tanzanian authorities as the First Extension Period was
granted in December 2016).
(b) The Ruvuma PSA, Tanzania, comprises two licences. The Mtwara
Licence has been extended to December 2017 and two wells are
required to be drilled, one of which is expected to be the Ntorya-3
location. The Company is seeking extensions to both the Mtwara
Licence and the Lindi Licence, which also requires two wells to be
drilled.
18. Related party transactions
There were no related party transactions during the six-month
period to 30 June 2017 that have materially affected the financial
position or performance of the Group.
19. Post balance sheet events
In early September 2017, Aminex reported an upgrade to its
unrisked resource estimates from 466 BCF Pmean GIIP to
approximately 1.3 TCF Pmean GIIP for the Ntorya appraisal area. The
Company also submitted a development plan for the Ntorya appraisal
area together with a request for the grant of a 25-year development
licence.
20. Statutory information
The interim financial information to 30 June 2017 and 30 June
2016 is unaudited and does not constitute statutory financial
information. The information given for the year ended 31 December
2016 does not constitute the statutory accounts within the meaning
of Part 6 of Chapter 4 of the Companies Act 2014. The statutory
accounts for the year ended 31 December 2016 has been filed with
the Registrar of Companies in Ireland. This announcement is being
sent to shareholders and will be made available at the Company's
registered office at 6 Northbrook Road, Dublin 6 and at the
Company's UK representative office at 60 Sloane Avenue, London SW3
3DD.
This information is provided by RNS
The company news service from the London Stock Exchange
END
IR SESFMWFWSEFU
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