TIDMBLOE
RNS Number : 9232Q
Block Energy PLC
01 July 2022
Block Energy Plc
("Block" or the "Company")
Audited Results for the Year Ended 31 December 2021
Block Energy plc, the development and production company focused
on Georgia, is pleased to announce its audited results for the year
ended 31 December 2021.
Block's Annual Report is available on the Company's website at
www.blockenergy.co.uk and will be sent to shareholders later
today.
Highlights:
-- Successfully integrated the SRCL assets acquired from
Schlumberger and defined an asset wide field development and
production enhancement plan
-- Commenced gas sales in February 2021, following completion of
the Early Production Facility and associated gas gathering line
-- Delivered on multipleobjectives set for 2021:
o Fully integrated the substantial technical data base,
following completion of the acquisition of SRCL,
o Completed a risking and ranking process, focussed on short
term drilling and production enhancement opportunities across the
enlarged portfolio,
o Defined a two-well drilling programme consisting of a new
horizontal well, designed to appraise areas of low fracture density
in the XIF license and a side track of an existing well, in the
newly acquired XIB license, whilst simultaneously executing a
workover programme structured to reverse the natural decline of our
baseline production
-- Well JKT-01Z drilled and brought into production at 344
boepd, with rapid pay-back of drilling capex
-- Production enhancement programme, continues to deliver
restoring and enhancing baseline production
-- Information gathered via the drilling of well WR-B01a and
well JKT-01Z have directly supported the Project I development plan
of 5 oil wells, due to commence in 2022
-- Asset wide study has defined two further projects:
o Project II - the infill development of the Middle Eocene oil
reservoir in the Patardzeuli oil field in Block XIB, and
o Project III - the appraisal and development of the natural gas
resources in the Lower Eocene throughout the XIF and XIB license
areas.
-- Over 399,000 operational man man-hours worked during the
year, without any lost time incidents
-- Development of a 3 Project strategy, tailored to provide
additional short & medium term cashflows and unlock significant
gas potential.
Block Energy plc's Chief Executive Officer, Paul Haywood,
said:
"The Company swiftly integrated and advanced the appraisal and
development opportunities throughout its enlarged portfolio in
2021. It also delivered on a key milestones, including commencing
gas sales and execution of a multi well drilling campaign."
"This relentless drive to advance the Company and maintain
consistent momentum has placed it in a stronger position to
continue to create value for all shareholders in the current year.
The planned three project strategy is designed to efficiently
deploy existing cash reserves into further development drilling,
throughout the XIF and XIB licenses."
"This, combined with our enhanced understanding of the
subsurface and the Company being profitable, sets the stage for
what we forecast to be a rewarding year and we look forward to
updating shareholders on short and medium term milestones as we
advance".
THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION AS STIPULATED
UNDER THE UK VERSION OF THE MARKET ABUSE REGULATION NO 596/2014
WHICH IS PART OF ENGLISH LAW BY VIRTUE OF THE EUROPEAN (WITHDRAWAL)
ACT 2018, AS AMED. ON PUBLICATION OF THIS ANNOUNCEMENT VIA A
REGULATORY INFORMATION SERVICE, THIS INFORMATION IS CONSIDERED TO
BE IN THE PUBLIC DOMAIN.
For further information please visit
http://www.blockenergy.co.uk/ or contact:
Paul Haywood Block Energy plc Tel: +44 (0)20 3468
(Chief Executive 9891
Officer)
Neil Baldwin Spark Advisory Partners Tel: +44 (0)20 3368
(Nominated Adviser) Limited 3554
Peter Krens Tennyson Securities Tel: +44 (0)20 7186
(Corporate Broker) 9030
Mark Antelme Celicourt Communications Tel: +44 (0)20 8434
Philip Dennis 2643
(Financial PR Adviser)
Chairman's Statement
Despite the challenges posed by the ongoing pandemic, we
delivered on our key milestones during the year 2021, placing us in
a good position to make solid progress this year and beyond.
Our main objectives for 2021 were:
-- to build on our understanding of the subsurface, to support
future drilling and production success; and
-- to deliver a two-well drilling programme and a workover
programme, to augment the existing production from existing
wells.
The first objective was of strategic importance. By using
attribute analysis of the 3D-seismic survey that we acquired on
West Rustavi Block XI(F) and the data acquired by a previous
operator on Block XI(B) , our geoscience team has made a
significant improvement in understanding the nature of our complex
Eocene oil and gas reservoirs.
This understanding has enabled us to make the investment case
for Block Energy in 2022 by defining three appraisal and
development projects:
-- Project I, the development of the Middle Eocene oil reservoir
in the West Rustavi/Krtsanisi field which straddles Blocks XI(F)
and XI(B) ;
-- Project II, the infill development of the Middle Eocene oil
reservoir in the Patardzeuli oil field in Block XI(B) ; and
-- Project III, the appraisal and development of the natural gas
resources throughout the Eocene in Blocks XI(F) and XI(B) .
Projects I and II will provide additional cash flow in the short
to medium term from the sale of crude oil and natural gas while
Project III promises to add significant value by better defining
and ultimately monetising the extensive natural gas resources that
lie under our portfolio of leases. This makes an attractive
investment case, particularly at current oil prices, which should
work well in Georgia, where the complexity of the subsurface
geology is offset by the positive and supportive regulatory
framework. The result, we believe, is an excellent balance of risk
and reward.
We appreciate that the risk relating to individual development
wells is significant when compared to many other regions of the
world where reservoirs are simpler. We think the best way to look
at Block Energy is to consider the totality of the opportunities in
the planned portfolio of wells, rather than on a well-by-well
basis. The nature of the geological risk means that some wells will
always be more successful than others, but our operations team is
driving costs down by a combination of careful planning, hard-nosed
contracting and the introduction of innovative techniques. This
will make payback on the successful wells rapid, particularly at
the current oil price, as well as reducing the cost of any less
successful wells. So, providing each portfolio of new wells is
successful as a whole in adding to production, we, the
shareholders, will see material returns on the investments made and
our strategy going forward is to increase the number and frequency
of wells that we drill.
We plan to commence Project I later this year which entails
drilling five oil wells in the Krtsanisi anticline, newly
recognised in the West Rustavi/Krtsanisi field.
The achievement of the second objective for 2021, reflected in
the success of well JKT-01Z, in terms of cost, placement of the
horizontal and production rate, and, ironically, the disappointing
production rate from WR-B1 also was an important contributor to the
first strategic objective.
None of this, of course, would be possible without the
dedication and commitment shown by our team of 120 people in
Georgia and six in London; a commitment that is reflected in their
readiness to learn and adapt to deliver for us as the shareholders
of our Company. I congratulate our people on quickly coming
together after the acquisition of the Schlumberger subsidiary to
form a unified and effective team. On behalf of the Board and
shareholders, I take the opportunity to thank them for their
dedication and the tremendous effort they make.
Despite the challenges of last year, your Company now has a
stronger platform on which to realise its potential. On behalf of
the Board, I would like to thank you all for your support. We look
forward to engaging with you with further updates as the rest of
the year unfolds.
Philip Dimmock
Non- Executive Chairman
Chief Executive Officer's Statement
In 2021, we saw a material improvement in the global demand for
oil and gas. This really took hold in the latter part of the year
as the world emerged from Covid-19 and economies began to recover.
The Company benefits from much improved oil pricing, which
strengthens our business case and enhances the platform to deliver
Projects .
Despite the challenging environment last year, the Board
considered it vital to continue with prudent investments to
progress the business. Now, a year later, we are seeing the
benefits of those decisions, with the Company's revenue more than
covering cash costs and enabling us to reinvest more revenue in
future development.
Operations
Following the acquisition and integration of Blocks IX and XI(B)
, our Company embarked on two key initiatives during 2021, both
aimed at maximising production from our enlarged portfolio. These
initiatives included a two-well drilling programme to enhance
production levels and a workover programme tailored to maximise
production from our existing well stock.
These two initiatives came on the back of actions put in place
in 2020 to monetise gas production; the success of which was
realised in 2021, with gas sales commencing in February through the
the Early Production Facility ( " EPF " ) and associated gas
gathering line installed in 2020. The Company's investment in these
facilities paid further dividends in 2021 and 2022, with the
immediate tie-in and monetising of oil and gas produced from the
WR-B01a and JKT-01Z wells.
Two Well Programme
Planning for the first of the two wells commenced early in 2021,
with the aim of drilling WR-B01 around mid-year.
The objective of well WR-B01, Georgia's first horizontal well,
was to establish consistent production by targeting an area of the
reservoir that was less prone to fractures, . We learnt that the
limited extent of the fracture networks adversely affected the
overall well productivity.
The information received from drilling the WR-B01a well enabled
the Company to calibrate its subsurface model, ahead of drilling
the second well in the programme, JKT-01Z.
JKT-01Z was spudded in December 2021. The well was delivered
early in 2022, significantly ahead of time and under budget.
The rapid tie-in and monetisation of production from well
JKT-01Z was made possible by the recently installed infrastructure
at an adjacent well, KRT-39, which has been in production for over
20 years. JKT-01Z produced at a rate of 344 boepd, validating the
Company's improved understanding of the reservoir. It remains a
solid contributor to the Company's overall production and cash flow
profile, having already paid back the well-drilling capex in line
with forecast, whilst directly informing the Project I development
plan.
Workover and Other Programmes
Through 2021, the operations team continued to execute well
maintenance and production enhancement intervention . This followed
a well-by-well opportunity review that took place early in the
year.
As part of that programme, well WR-38Z and WR-16aZ were both
brought back into production in Q1, and both wells required further
work during the year to support ongoing production. WR-16aZ
produced intermittently during the first half and was supported by
the installation of artificial lift in Q3. WR-38Z was on production
more consistently, but experienced natural decline, which was more
than offset by the production gains from installing the rod pump on
WR-16aZ.
Later in the year, we undertook a production enhancement
programme, comprising technical well interventions, such as
wellbore cleaning and replacing artificial lift components. This
programme was focussed on supporting near-term production, whilst
informing our technical evaluation of the mature development areas
throughout Block XI(B) , specifically the Patardzeuli field (which
produced 100 MMbbls of oil). The team have since designed a staged
infill development programme, which seeks to recover over 97
million barrels of remaining oil from undrained areas of this
once-prolific field (Project II).
In a separate initiative, upgrading surface facilities at well
KRT-39 in Block XI(B) enabled the monetisation from January 2022 of
the associated gas production from KRT-39 and JKT-01Z, boosting the
Company's revenue whilst supporting strategic plans to advance the
appraisal and development of the significant contingent gas
resources across our portfolio (Project III).
Health & safety and ESG
Over 399,000 operational man man-hours were worked by staff and
contractors over during the year, without any lost time incidents.
This is a significant achievement and reflects the Company's
importance on health and safety. It also demonstrates the quality
and diligence of the management team on-site and their ongoing
dedication to working to the highest standards within the
industry.
As part of the drive to improve the Company's ESG credentials,
we were pleased to be accepted into the UN Global Compact Network (
" UNGCN " ). The UNGCN is a global platform promoting engagement on
human rights, labour, environmental and anti-corruption
standards.
Through its increased focus on gas, the transition fuel, over
the course of 2021, Block also reduced its emissions on a
sales-weighted basis. By selling associated gas produced, Block no
longer has to flare it. Furthermore, by selling gas into the
automobile fuel market, the Company reduces regional transport
emissions by displacing higher carbon and more emissions-intensive
alternative fuels.
Outlook
The Company is now benefitting from the various initiatives
undertaken during 2021 to support production growth and a broader
oil development and gas appraisal programme. The Company has built
an excellent portfolio of assets and the exercise of strict capital
discipline, combined with the benefits from higher oil and gas
prices, places us in a great position to develop them further in
the year ahead. Supported by our cash flow positive business and
non-dilutive development financing options being explored, we plan
to step up the rate of drilling in 2022 and 2023, to increase oil
production and appraise the deeper gas play within our licences,
which we believe contains substantial gas resources. The robust
domestic and regional demand for gas, and the unrestricted direct
access to European markets support the development of as much gas
as possible.
Paul Haywood
Chief Executive Officer
Chief Financial Officer's Statement
Balance sheet - acquisitions, capital expenditure, equity
placing and asset growth
In November 2020, Block Energy Plc acquired 100% of the shares
of Block Rustaveli Limited (formerly Schlumberger Rustaveli Company
Limited), which holds the PSCs to Blocks IX and XI(B) in Georgia,
for $6.8 million consideration, which comprised $7.1 million in
nil-cost options to acquire shares in Block Energy Plc less $0.3
million cash from the seller to adjust the consideration for
liabilities that were for the seller's account. The assets and
liabilities acquired, which are detailed in note 12 to the
consolidated financial statements include the following fair
values: $6.3 million of development and production assets, $1.0
million of crude oil inventory, $1.5 million of materials
inventory, $1.6 million of decommissioning liabilities and $0.9
million of other liabilities.
The Group's net assets have decreased from $29,694,000 as at 31
December 2020 to $27,065,000 as at 31 December 2021. At the end of
the year, the Group's cash balance was $1,244,000 (2020:
$6,331,000).
Income statement
The Group's revenue increased to $6,114,000 (2020: $1,255,000)
and other income included $5,000 (2020: $100,000) for sales of
materials. The current year revenue from sales of crude oil of
$5,518,000 (2020: $1,255,000) comprised the sale of 86,700 barrels
(2020: 34,421barrels) of oil, which equated to average revenue of
$63.65 (2020: $36.45) per barrel.
During the year, the Group produced 108,000 barrels of crude oil
(2020: 25,000 barrels), with the increase in production being due
primarily to oil and gas produced from the wells in Block XIB
(acquired in late 2020) and from new wells/sidetracks. This gross
production includes the state of Georgia's share of production.
In addition, the Group had over 20,000 barrels of crude oil
inventory as at 31 December 2021 (31 December 2020: over 28,000
barrels). Following the year end, during the quarter ended 31 March
2022, the Group sold 24,413 barrels of crude oil inventory for net
revenue of $2.168 million, which equates to average revenue of
$88.80 per barrel (Q1 2021: sold 26,349 barrels for $1.374 million
or $52.18 per barrel).
The Group commenced gas sales on 15 February 2021 and, during
the period from 15 February 2021 to 31 December 2021, it sold 191.5
Mcf of gas for net revenue of $596,000, which equates to an average
gas price of $3.11 per Mcf (2020: sold nil Mcf).
The loss for the year was $4,783,000 as compared with a
$5,512,000 loss in the prior year. During the year, the Group had
not yet achieved sufficient scale for the revenue to cover the
Group's costs.
Future prospects
During Q1 2022, the Company produced 32.1 Mbbls of oil and 14.0
Mboe of gas, resulting in a combined total of 46.1 Mboe of oil and
gas (Q1 2021: produced 29.8 Mbbls of oil and 14.6 Mboe of gas,
resulting in a combined total of 44.4 Mboe of oil and gas). The
average production rate for Q1 2022 was 512 boepd (Q1 2021: 493
boepd).
The Company has always been focused on controlling
administration costs and continues to keep these to a minimum. We
maintain a low-cost operation, and our Georgian portfolio offers a
low-cost short-cycle production base.
Liquidity, counterparty risk and going concern
The Group monitors its cash position, cash forecasts and
liquidity regularly and has a conservative approach to cash
management, with surplus cash held on term deposits with major
financial institutions.
The directors have prepared cash flow forecasts for a period of
18 months from the date of signing these financial statements. The
Group's forecasts are reviewed regularly to assess whether any
actions to curtail expenditure or cut costs are required. The Group
is in the final stages of preparing to drill a horizontal sidetrack
in the WR-B01 well followed by sidetracks of other wells. The
forecasts assume the wells will produce oil and gas, which would be
sold, and indicate the Group has sufficient funds to complete the
drilling of the wells and to meet its liabilities as they fall due
until December 2023. However, if any of the new wells do not
produce commercial quantities of oil or gas, the Group would
immediately revisit its plans to drill subsequent wells. The
financial benefit of any additional capital projects would be
assessed against capital requirements and balanced with ensuring
that the Group and the Company can continue to meet their
liabilities and commitments through to December 2023. The Company's
forecasts are considered together with the Group's forecasts.
The Group's operations presently generate sufficient revenues to
cover operating costs and capital expenditures, supporting the
continued preparation of the Group's accounts on a going concern
basis. The directors are nevertheless conscious that oil prices
have risen rapidly during the past twelve months due in part to
recent global political uncertainty, and could rise further but
could also fall back in the year ahead, and that future production
levels depend in part on the success of future drilling. As part of
their going concern assessment, the directors have performed a
reverse stress test on a low oil price scenario in which future
drilling is inhibited or unsuccessful, and have concluded that it
remains possible that future revenues in such a scenario might not
cover all operating costs and planned capital expenditures,
creating a material uncertainty that may cast doubt over the
Group's ability to continue as a going concern. Whilst
acknowledging this material uncertainty, the directors remain
confident of making further cost savings and/or raising finance
when required, and therefore the directors consider it appropriate
to prepare the financial statements on a going concern basis. The
financial statements do not include the adjustments that would
result if the Group were unable to continue as a going concern.
Results and dividends
The results for the year and the financial position of the Group
are shown in the following financial statements. The Group has
incurred a pre-tax loss of $4,783,000 (2020: loss of
$5,512,000).
The Group has net assets of $27,065,000 (2020: net assets of
$29,694,000).
The directors do not recommend the payment of a dividend (2020:
$nil).
William McAvock
Chief Financial Officer
Consolidated Statement of Comprehensive Income
for the year ended 31 December 2021
Year ended Year ended
31 December 31 December
Note 2021 2020
Continuing operations $'000 $'000
Revenue 4 6,114 1,255
Other cost of sales (2,982) (2,203)
Depreciation and depletion of
oil and gas assets 5 (2,901) (781)
------------------------------------- ------------ ------------- -------------
Total cost of sales (5,883) (2,984)
------------- -------------
Gross profit / (loss) 231 (1,729)
Other administrative costs (3,432) (3,295)
Share based payments charge (1,494) (641)
------------------------------------- ------------ ------------- -------------
Total administrative expenses 6,7 (4,926) (3,936)
Foreign exchange movement (6) 49
Operating loss (4,701) (5,616)
Finance income 8 - 14
Other income 9 5 100
Finance expense (87) (10)
Loss for the year before taxation (4,783) (5,512)
Taxation 10 - -
Loss for the year from continuing
operations (attributable to the
equity holders of the parent) (4,783) (5,512)
------------- -------------
Items that may be reclassified
subsequently to profit and loss:
Exchange differences on translation
of foreign operations 202 (389)
Total comprehensive loss for
the year (attributable to the
equity holders of the parent) (4,581) (5,901)
============= =============
Loss per share basic and diluted 11 (0.76)c (1.31)c
------------- -------------
All activities relate to continuing operations.
The notes on the following pages form part of these consolidated
financial statements.
31 December 2021 31 December 2020
Note $'000 $'000
----------------------------------- ----- ----------------- -----------------
Non-current assets
Property, plant and equipment 13 24,345 21,311
----------------------------------- ----- ----------------- -----------------
Current assets
Inventory 14 4,585 4,114
Trade and other receivables 16 752 2,256
Cash and cash equivalents 17 1,244 6,331
Total current assets 6,581 12,701
----------------------------------- ----- ----------------- -----------------
Total assets 30,926 34,012
----------------------------------- ----- ----------------- -----------------
Equity and liabilities
Capital and reserves attributable
to equity holders of the
Parent Company:
Share capital 19 3,482 3,353
Share premium 20 34,625 34,234
Other reserves 21 10,260 9,120
Foreign exchange reserve 246 44
Accumulated deficit (21,548) (17,057)
Total equity 27,065 29,694
----------------------------------- ----- ----------------- -----------------
Liabilities
Trade and other payables 18 1,556 1,656
Provisions 15 2,305 2,662
Total current liabilities 3,861 4,318
----------------------------------- ----- ----------------- -----------------
Total equity and liabilities 30,926 34,012
----------------------------------- ----- ----------------- -----------------
The financial statements were approved by the Board of Directors
and authorised for issue on 30 June 2022 and were signed on its
behalf by:
William McAvock Paul Haywood
Director Director
The notes on the following pages form part of these consolidated
financial statements.
Consolidated Statement of Changes in Equity
at 31 December 2021
Foreign
Share Share Accumulated Other Exchange Total
Capital Premium deficit Reserves Reserve Equity
$'000 $'000 $'000 $'000 $'000 $'000
Balance at 31
December 2019 2,623 27,985 (11,545) 1,114 433 20,610
------------------------- --------- --------- ----------- ---------- ---------- --------
Loss for the year - - (5,512) - - (5,512)
Exchange differences
on translation
of foreign operations - - - - (389) (389)
------------------------- --------- --------- ----------- ---------- ---------- --------
Total comprehensive
loss for the year - - (5,512) - (389) (5,901)
------------------------- --------- --------- ----------- ---------- ---------- --------
Issue of share
options on acquisition
of BRL - - - 7,304 - 7,304
Issue of shares 730 6,654 - - - 7,384
Cost of issue - (405) - - - (405)
Share based payments - - - 702 - 702
------------------------- --------- --------- ----------- ---------- ---------- --------
Total transactions
with owners 730 6,249 - 8,006 - 14,985
Balance at 31
December 2020 3,353 34,234 (17,057) 9,120 44 29,694
------------------------- --------- --------- ----------- ---------- ---------- --------
Loss for the year - - (4,783) - - (4,783)
Exchange differences
on translation
of foreign operations - - - - 202 202
------------------------- --------- --------- ----------- ---------- ---------- --------
Total comprehensive
loss for the year - - (4,783) - 202 (4,581)
------------------------- --------- --------- ----------- ---------- ---------- --------
Issue of shares 52 255 - - - 307
Share based payments - - - 1,494 - 1,494
Options exercised 77 136 210 (272) - 151
Options expired - - 82 (82) - -
------------------------- --------- --------- ----------- ---------- ---------- --------
Total transactions
with owners 129 391 292 1,140 - 1,952
------------------------- --------- --------- ----------- ---------- ---------- --------
Balance at 31
December 2021 3,482 34,625 (21,548) 10,260 246 27,065
------------------------- --------- --------- ----------- ---------- ---------- --------
The notes on the following pages form part of these consolidated
financial statements.
Consolidated Statement of Cashflows
for the year ended 31 December 2021
Year ended Year ended
31 December 31 December
2021 2020
Note $'000 $'000
Cash flow from operating activities
Loss for the year before tax (4,783) (5,512)
Adjustments for:
Depreciation and depletion 5 2,901 781
Decommissioning finance charge 15 66 -
Impairment of PP&E 2,13 - 172
Disposal of PP&E at nil value 49 -
Other income 8 (5) (15)
Finance expense 3 9
Share based payments expense 7 1,494 641
Foreign exchange movement 6 (49)
Operating cash flows before movements
in working capital (269) (3,973)
Increase in trade and other receivables (4) (513)
Increase in trade and other payables 179 342
(Increase)/ decrease in inventory (471) 955
Net cash used in operating activities (565) (3,189)
Cash flow from investing activities
Cash received from acquisition 278 -
of BRL
Income received 5 15
Expenditure in respect of intangible - -
assets
Expenditure in respect of PP&E (6,407) (2,617)
------------- -------------
Net cash used in investing activities (6,124) (2,602)
Cash flow from financing activities
Proceeds from issue of equity 1,465 5,754
Costs related to issue of equity - (405)
Interest paid (3) (9)
------------- -------------
Net cash inflow from financing
activities 1,462 5,340
Net decrease in cash and cash
equivalents in the year (5,227) (451)
------------- -------------
Cash and cash equivalents at start
of year 6,331 6,494
Effects of foreign exchange rate
changes on cash and cash equivalents 140 288
------------- -------------
Cash and cash equivalents at end
of year 1,244 6,331
------------- -------------
The notes on the following pages form part of these consolidated
financial statements.
Significant non-cash transactions
The only significant non-cash transactions were the issue of
shares and share options detailed in notes 19 and 23.
Notes forming part of the Consolidated Financial Statements
Corporate information
Block Energy Plc ("Block Energy") gained admission to AIM on the
11 June 2018, trading under the symbol of BLOE.
The Consolidated financial statements of the Group, which
comprises Block Energy Plc and its subsidiaries, for the year ended
31 December 2021 were authorised for issue in accordance with a
resolution of the directors on 30 June 2022. Block Energy is a
Company incorporated in the UK whose shares are publicly traded.
The address of the registered office is given in the officers and
advisers section of this report. The Company's administrative
office is in London, UK.
The nature of the Company's operations and its principal
activities are set out in the Strategic Report on pages 3 to 21 and
the Report of the Directors on pages 22 to 24.
1. Significant Accounting policies
IAS 8 requires that management shall use its judgement in
developing and applying accounting policies that result in
information which is relevant to the economic decision-making needs
of users, that are reliable, free from bias, prudent, complete and
represent faithfully the financial position, financial performance
and cash flows of the entity.
Basis of preparation
The principal accounting policies adopted in the preparation of
these consolidated financial statements are set out below. The
policies have been consistently applied to all the years presented,
unless otherwise stated. In the prior year, the Group changed its
presentational currency from the pound sterling to the US dollar,
which represented a change in accounting policy. All amounts
presented are in thousands of US dollars unless otherwise stated.
Foreign operations are included in accordance with the policies set
out below.
The consolidated financial statements have been prepared in
accordance with UK international accounting standards and in
conformity with the requirements of the Companies Act 2006. The
Financial Statements have also been prepared under the historical
cost convention, as modified by the revaluation of financial assets
at fair value through profit or loss.
The preparation of financial statements in conformity with IFRS
requires management to make judgements, estimates and assumptions
that affect the application of policies and reported amounts of
assets and liabilities, income and expenses. The estimates and
associated assumptions are based on historical experience and
factors that are believed to be reasonable under the circumstances,
the results of which form the basis of making judgements about
carrying values of assets and liabilities that are not readily
apparent from other sources. Actual results may differ from these
estimates.
The estimates and underlying assumptions are reviewed on an
ongoing basis. Changes in accounting estimates may be necessary if
there are changes in the circumstances on which the estimate was
based, or as a result of new information or more experience. Such
changes are recognised in the period in which the estimate is
revised.
New and amended standards adopted by the Group
There were no new or amended accounting standards adopted by the
Group for the year ended 31 December 2021.
New accounting standards issued but not yet effective
The standards and interpretations that are relevant to the
Group, issued, but not yet effective, up to the date of the
Financial Statements are listed below. The Group intends to adopt
these standards, if applicable, when they become effective.
Standard Impact on initial application Effective
date
--------------------- ------------------------------------ ----------
IFRS 17 Insurance Contracts 1 January
2023
IFRS 10 and IAS Long term interests in associates Unknown
28 (Amendments) and joint ventures
Amendments to IAS Classification of Liabilities 1 January
1 as current or non-current 2023
Amendments to IAS Disclosure of Accounting Policies 1 January
1 and IFRS Practice 2023
Statement 2
Amendments to IAS Definition of Accounting Estimates 1 January
8 2023
Amendments to IAS Deferred Tax Related to Assets 1 January
12 and Liabilities arising from 2023
a Single Transaction
Amendments to IFRS Reference to the Conceptual 1 January
3 Framework 2022
Amendments to IAS Property, Plant and Equipment 1 January
16 - Proceeds before intended use 2022
Amendments to IAS Onerous contracts - Cost of 1 January
37 fulfilling a contract 2022
Annual Improvements Amendments to IFRS 1 First time 1 January
to IFRS Standard adoption of IFRS, IFRS 9 Financial 2022
2018-2020 Cycle Instruments, IFRS Leases
The Directors have evaluated the impact of transition to the
above standards and do not consider that there will be a material
impact of transition on the financial statements.
Basis of consolidation
Where the Company has control over an investee, it is classified
as a subsidiary. The Company controls an investee if all three of
the following elements are present: power over the investee,
exposure to variable returns from the investee, and the ability of
the investor to use its power to affect those variable returns.
Control is reassessed whenever facts and circumstances indicate
that there may be a change in any of these elements of control.
De-facto control exists in situations where the Company has the
practical ability to direct the relevant activities of the investee
without holding the majority of the voting rights. In determining
whether de-facto control exists the Company considers all relevant
facts and circumstances, including:
-- The size of the Company's voting rights relative to both the
size and dispersion of other parties who hold voting rights;
-- Substantive potential voting rights held by the Company and by other parties;
-- Other contractual arrangements; and
-- Historic patterns in voting attendance.
Business combinations and Goodwill
The consolidated financial statements incorporate the results of
business combinations using the purchase method. In the
consolidated statement of financial position, the acquiree's
identifiable assets, liabilities and contingent liabilities are
initially recognised at their fair values at the acquisition date.
The difference between the consideration paid and the acquired net
assets is recognised as goodwill. The results of acquired
operations are included in the consolidated income statement from
the date on which control is obtained. Any difference arising
between the fair value and the tax base of the acquiree's assets
and liabilities that give rise to a deductible difference results
in recognition of deferred tax liability. No deferred tax liability
is recognised on goodwill. For the purposes of the current period
of reporting the figures related to the transaction accounting are
considered provisional as permitted under the requirements of the
accounting standards. These figures will be finalised within a
period of twelve months from the acquisition date of the
transaction.
Acquisitions
The Group and Company measure goodwill at the acquisition dates
as:
-- The fair value of the consideration transferred; plus
-- The recognised amount of any non-controlling interests in the acquiree
-- Plus, if the business combination is achieved in stages, the
fair value of the existing equity interest in the acquiree; less
the net recognised amount (generally fair value) of the
identifiable assets acquired and liabilities assumed.
When the excess is negative, a bargain purchase gain is
recognised immediately in profit or loss.
Cost related to the acquisition, other than those associated
with the issue of debt or equity securities, that the Group incurs
in connection with a business combination, are expensed as
incurred.
Asset Acquisition
Acquisitions of mineral exploration licences through the
acquisition of non-operational corporate structures that do not
represent a business, and therefore do not meet the definition of a
business combination, are accounted for as the acquisition of an
asset. An example of such would be increases in working interests
in licences.
The consideration for the asset is allocated to the assets based
on their relative fair values at the date of acquisition.
Going concern
The directors have prepared cash flow forecasts for a period of
18 months from the date of signing these financial statements. The
Group's forecasts are reviewed regularly to assess whether any
actions to curtail expenditure or cut costs are required. The Group
is in the final stages of preparing to drill a horizontal sidetrack
in the WR-B1 well followed by sidetracks of other wells. The
forecasts assume the wells will produce oil and gas, which would be
sold, and indicate the Group has sufficient funds to complete the
drilling of the wells and to meet its liabilities as they fall due
until December 2023. However, if any of the new wells do not
produce commercial quantities of oil or gas, the Group would
immediately revisit its plans to drill subsequent wells. The
financial benefit of any additional capital projects would be
assessed against capital requirements and balanced with ensuring
that the Group and the Company can continue to meet their
liabilities and commitments through to December 2023. The Company's
forecasts are considered together with the Group's forecasts.
The Group's operations presently generate sufficient revenues to
cover operating costs and capital expenditures, supporting the
continued preparation of the Group's accounts on a going concern
basis. The directors are nevertheless conscious that oil prices
have risen rapidly during the past twelve months due in part to
recent global political uncertainty, and could rise further but
could also fall back in the year ahead, and that future production
levels depend in part on the success of future drilling. As part of
their going concern assessment, the directors have performed a
reverse stress test on a low oil price scenario in which future
drilling is inhibited or unsuccessful, and have concluded that it
remains possible that future revenues in such a scenario might not
cover all operating costs and planned capital expenditures,
creating a material uncertainty that may cast doubt over the
Group's ability to continue as a going concern. Whilst
acknowledging this material uncertainty, the directors remain
confident of making further cost savings and/or raising finance
when required and, therefore, the directors consider it appropriate
to prepare the financial statements on a going concern basis. The
financial statements do not include the adjustments that would
result if the Group were unable to continue as a going concern.
Intangible Assets
Exploration and evaluation costs
The Group applies the full cost method of accounting for
Exploration and Evaluation (E&E) costs, having regard to the
requirements of IFRS 6 'Exploration for and Evaluation of Mineral
Resources'. Under the full cost method of accounting, costs of
exploring and evaluating properties are accumulated and capitalised
by reference to appropriate cash generating units ("CGUs"). Such
CGU's are based on geographic areas such as a licence area, type or
a basin and are not larger than an operating segment - as defined
by IFRS 8 'Operating segments.
E&E costs are initially capitalised within 'Intangible
assets'. Such E&E costs may include costs of licence
acquisition, technical services and studies, seismic acquisition,
exploration drilling and testing, but do not include costs incurred
prior to having obtained the legal rights to explore an area, which
are expensed directly to the statement of comprehensive income as
they are incurred. Plant and equipment assets acquired for use in
exploration and evaluation activities are classified as property,
plant and equipment.
However, to the extent that such an asset is consumed in
developing an unproven oil and gas asset, the amount reflecting
that consumption is recorded as part of the cost of the unproven
oil and gas asset.
Exploration and unproven oil and gas assets related to each
exploration license/prospect are not amortised but are carried
forward until the technical feasibility and commercial feasibility
of extracting a mineral resource are demonstrated.
Impairment of Exploration and Evaluation assets
All capitalised exploration and evaluation assets and property,
plant and equipment are monitored for indications of impairment.
Where a potential impairment is indicated, assessment is made for
the Group of assets representing a cash generating unit.
In accordance with IFRS 6 the Group firstly considers the
following facts and circumstances in their assessment of whether
the Group's exploration and evaluation assets may be impaired,
whether:
-- the period for which the Group has the right to explore in a
specific area has expired during the period or will expire in the
near future, and is not expected to be renewed;
-- unexpected geological occurrences render the resource uneconomic;
-- a significant fall in realised prices or oil and gas price
benchmarks render the project uneconomic; or
-- an increase in operating costs occurs.
If any such facts or circumstances are noted, the Group perform
an impairment test in accordance with the provisions of IAS 36.
The aggregate carrying value is compared against the expected
recoverable amount of the cash generating unit. The recoverable
amount is the higher of value in use and the fair value less costs
to sell. An impairment loss is reversed if the asset's or
cash-generating unit's recoverable amount exceeds its carrying
amount. A reversal of impairment loss is recognised in the profit
or loss immediately.
Property, plant and equipment - development and production
(D&P) assets
Capitalisation
The costs associated with determining the existence of
commercial reserves are capitalised in accordance with the
preceding policy and transferred to property, plant and equipment
as development assets following impairment testing. All costs
incurred after the technical feasibility and commercial viability
of producing hydrocarbons have been demonstrated are capitalised
within development assets on a field-by-field basis. Subsequent
expenditure is only capitalised where it either enhances the
economic benefits of the development asset or replaces part of the
existing development asset (where the remaining cost of the
original part is expensed through the income statement). Costs of
borrowing related to the ongoing construction of development and
production assets and facilities are capitalised during the
construction phase. Capitalisation of interest ceases once an asset
is ready for production.
Depreciation
Capitalised oil assets are not subject to depreciation until
commercial production starts. Depreciation is calculated on a
unit-of-production basis in order to write off the cost of an asset
as the reserves that it represents are produced and sold. Any
periodic reassessment of reserves will affect the depreciation rate
on a prospective basis. The unit-of-production depreciation rate is
calculated on a field-by-field basis using proved, developed
reserves as the denominator and capitalised costs as the numerator.
The numerator includes an estimate of the costs expected to be
incurred to bring proved, developed, not-producing reserves into
production. Infrastructure that is common to a number of fields,
such as gathering systems, treatment plants and pipelines are
depreciated on a unit-of-production basis using an aggregate
measure of reserves or on a straight line basis depending on the
expected pattern of use of the underlying asset.
Proven oil and gas properties
Oil and gas properties are stated at cost less accumulated
depreciation and impairment losses. The initial cost comprises the
purchase price or construction cost including any directly
attributable cost of bringing the asset into operation and any
estimated decommissioning provision.
Once a project reaches the stage of commercial production and
production permits are received, the carrying values of the
relevant exploration and evaluation asset are assessed for
impairment and transferred to proven oil and gas properties and
included within property plant and equipment.
Proven oil and gas properties are accounted for in accordance
with provisions of the cost model under IAS 16 "Property Plant and
Equipment" and are depleted on unit of production basis based on
the estimated proven and probable reserves of the pool to which
they relate.
Impairment of development and production assets
A review is performed for any indication that the value of the
Group's D&P assets may be impaired such as:
-- significant changes with an adverse effect in the market or
economic conditions which will impact the assets; or
-- obsolescence or physical damage of an asset; or
-- an asset becoming idle or plans to dispose of the asset
before the previously expected date; or
-- evidence is available from internal reporting that indicates
that the economic performance of an asset is or will be worse than
expected.
For D&P assets when there are such indications, an
impairment test is carried out on the CGU. CGUs are identified in
accordance with IAS 36 'Impairment of Assets', where cash flows are
largely independent of other significant asset Groups and are
normally, but not always, single development or production areas.
When an impairment is identified, the depletion is charged through
the Consolidated Statement of Comprehensive Income if the net book
value of capitalised costs relating to the CGU exceeds the
associated estimated future discounted cash flows of the related
commercial oil reserves.
The CGU's identified by the company are Corporate along with
West Rustavi, Rustaveli, Satskhenisi and Norio given they are
independent projects under individual Production Sharing Contracts
("PSCs"). An assessment is made at each reporting as to whether
there is any indication that previously recognised impairment
charges may no longer exist or may have decreased. If such an
indication exists, the Group estimates the recoverable amount. A
previously recognised impairment charge is reversed only if there
has been a change in the estimates used to determine the assets
recoverable amount since the last impairment charge was recognised.
If this is the case the carrying amount of the asset is increased
to its recoverable amount, not to exceed the carrying amount that
would have been determined, net of depreciation , had no impairment
charges been recognised for the asset in prior years.
Property, plant and equipment and depreciation
Property, plant and equipment which are awaiting use in the
drilling campaigns, and storage, are recorded at historical cost
less accumulated depreciation. Property, plant and equipment are
depreciated using the straight line method over their estimated
useful lives, as follows:
-- PP&E - 6 years
The carrying value of Property, plant and equipment is assessed
annually and any impairment charge is charged to the Consolidated
Statement of Comprehensive income.
Leases
In the current year, the Group adopted 'IFRS 16: Leases', which
requires operating and finance leases to be accounted for in a
consistent manner. There was no material impact on the Group from
the adoption of this standard year-on-year.
The Group assesses whether a contract is or contains a lease, at
inception of the contract. The Group recognises a right-of-use
asset and a corresponding lease liability with respect to all lease
arrangements in which it is the lessee, except for short-term
leases (defined as leases with a lease term of 12 months or less)
and leases of low value assets (such as tablets and personal
computers, small items of office furniture and telephones). For
these leases, the Group recognises the lease payments as an
operating expense on a straight-line basis over the term of the
lease unless another systematic basis is more representative of the
time pattern in which economic benefits from the leased assets are
consumed.
Inventories
Crude oil inventories are stated at the lower of cost and net
realisable value. The cost of crude oil is the cost of production,
including direct labour and materials, depreciation and an
appropriate portion of fixed overheads allocated based on normal
operating capacity of the production facilities, determined on a
weighted average cost basis. Net realisable value of crude oil is
based on the market price of similar crude oil at the balance sheet
date and costs to sell, adjusted if the sale of inventories after
that date gives additional evidence about its net realisable value
at the balance sheet date.
The cost of crude oil is expensed in the period in which the
related revenue is recognised.
Inventories of drilling tubulars and drilling chemicals are
valued at the lower of cost or net realisable value, where cost
represents the weighted average unit cost for inventory lines on a
line by line basis. Cost comprises all costs of purchase, costs of
conversion and other costs incurred in bringing the inventories to
their present location and condition.
Decommissioning provision
Provisions for decommissioning are recognised in full when wells
have been suspended or facilities have been installed.
A corresponding amount equivalent to the provision is also
recognised as part of the cost of either the related oil and gas
exploration and evaluation asset or property, plant and equipment
as appropriate. The amount recognised is the estimated cost of
decommissioning, discounted to its net present value, and is
reassessed each year in accordance with local conditions and
requirements.
Changes in the estimated timing of decommissioning or
decommissioning cost estimates are dealt with prospectively by
recording an adjustment to the provision, and a corresponding
adjustment to the related asset.
The unwinding of the discount on the decommissioning provision
is included as a finance cost.
Taxation and deferred tax
Income tax expense represents the sum of the current tax and
deferred tax charge for the period.
The Group's liability for current tax is calculated using tax
rates that have been enacted or substantively enacted by the
reporting date.
Deferred tax is recognised on differences between the carrying
amounts of assets and liabilities in the financial information and
the corresponding tax bases and is accounted for using the balance
sheet liability method .
Deferred tax assets are recognised to the extent that it is
probable that taxable profits will be available against which
deductible temporary differences can be utilised.
Judgement is applied in making assumptions about future taxable
income, including oil and gas prices, production, rehabilitation
costs and expenditure to determine the extent to which the Group
recognises deferred tax assets, as well as the anticipated timing
of the utilisation of the losses.
Deferred tax is calculated at the tax rates that have been
enacted or substantively enacted and are expected to apply in the
period when the liability is settled, or the asset realised.
Deferred tax is charged or credited to the statement of
comprehensive income, except when it relates to items charged or
credited directly to equity, in which case the deferred tax is also
dealt with in equity.
Foreign currencies
Monetary assets and liabilities denominated in foreign
currencies are translated into US dollars at the rates of exchange
prevailing at the reporting date: $1.3523/GBP1 (2020:
$1.3678/GBP1). Transactions in foreign currencies are translated at
the exchange rate ruling at the date of the transaction. Exchange
differences are taken to the Statement of Comprehensive Income.
The Company's functional currency is the pound sterling and its
presentational currency is the US dollar and accordingly the
financial statements have also been prepared in US dollars. The
functional currencies of Block Norioskhevi Ltd, Satskhenisi
Limited, Georgia New Ventures Inc and Block Rustaveli Limited are
the US dollar and the functional currencies of their branches in
Georgia are the Georgian Lari.
Foreign operations
The assets are translated into US dollars at the exchange rate
at the reporting date and income and expenses of the foreign
operations are translated at the average exchange rates. Exchange
differences arising on translation are recognised in other
comprehensive income and presented in the other reserves category
in equity.
Determination of functional currency and presentational
currency
The determination of an entity's functional currency is assessed
on an entity by entity basis. A company's functional currency is
defined as the currency of the primary economic environment in
which the entity operates. The functional currency of the Parent
Company is the pound sterling, because it operates in the UK, where
the majority of its transactions are in pounds sterling. The
functional currencies of Block Norioskhevi Ltd, Satskhenisi
Limited, Georgia New Ventures Inc and Block Rustaveli Limited are
the US dollar, because the majority of their transactions by value
is in US dollars, and the functional currencies of their branches
in Georgia are the Georgian Lari, because the majority of their
transactions by value is in Georgian Lari.
The presentational currency of the Group for year ended 31
December 2021 is US dollars. The presentational currency is an
accounting policy choice.
Revenue
Revenue from contracts with customers is recognised when the
Group satisfies its performance obligation of transferring control
of oil or gas to a customer. Transfer of control is usually
concurrent with both transfer of title and the customer taking
physical possession of the oil or gas, which is determined by
reference to the oil or gas sales agreement. This performance
obligation is satisfied at that point in time.
The transaction price is agreed between the Group and the
customer, with the amount of revenue recognised being determined by
considering the terms of the Production Sharing Contract ("PSC")
and the oil sales agreement for each oil sale or the gas sales
agreement for each gas sale.
Finance income and expenses
Finance costs are accrued on a time basis, by reference to the
principal outstanding and at the effective interest rate
applicable. Finance expenses comprise interest or finance costs on
borrowings.
Financial instruments
The amendments to IFRS 9 clarify that for the purpose of
assessing whether a prepayment feature meets the 'solely payments
of principal and interest' (SPPI) condition, the party exercising
the option may pay or receive reasonable compensation for the
prepayment irrespective of the reason for prepayment. In other
words, financial assets with prepayment features with negative
compensation do not automatically fail SPPI.
Financial assets and financial liabilities are recognised on the
Group's balance sheet when the Group becomes party to the
contractual provisions of the instrument.
Fair value
Fair value is the price that would be received to sell an asset
or paid to transfer a liability in an orderly transaction between
market participants at the measurement date. All assets and
liabilities, for which fair value is measured or disclosed in the
Financial Statements, are categorised within the fair value
hierarchy, described as follows, based on the lowest-level input
that is significant to the fair value measurement as a whole:
Level 1 - quoted (unadjusted) market prices in active markets
for identical assets or liabilities;
Level 2 - valuation techniques for which the lowest-level input
that is significant to the fair value measurement is directly or
indirectly observable; and
Level 3 - valuation techniques for which the lowest-level input
that is significant to the fair value measurement is
unobservable.
Financial assets
Financial assets are initially recognised at fair value, and
subsequently measured at amortised cost, less any allowances for
losses using the expected credit loss model, being the difference
between all contractual cash flows that are due to the Group in
accordance with the contract and all the cash flows that the Group
expects to receive.
Impairment provisions for receivables from related parties and
loans to related parties are recognised based on a forward looking
expected credit loss model. The methodology used to determine the
amount of the provision is based on whether there has been a
significant increase in credit risk since initial recognition of
the financial asset.
For those where the credit risk has not increased significantly
since initial recognition of the financial asset, twelve month
expected credit losses along with gross interest income are
recognised. For those for which credit risk has increased
significantly, lifetime expected credit losses along with the gross
interest income are recognised. For those that are determined to be
credit impaired, lifetime expected credit losses along with
interest income on a net basis are recognised.
Financial liabilities
Financial liabilities are classified as either financial
liabilities at fair value through profit and loss (FVTPL) or as
other financial liabilities. The Group derecognises financial
liabilities when, and only when, the Group's obligations are
discharged or cancelled, or they expire.
Financial liabilities are classified at FVTPL when the financial
liability is either held for trading or it is designated at FVTPL.
A financial liability is classified as held for trading if it has
been incurred principally for the purpose of repurchasing it in the
near term or is a derivative that is not a designated or effective
hedging instrument.
Financial liabilities at FVTPL are measured at fair value, with
any gains or losses arising on changes in fair value recognised in
profit or loss. The net gain or loss recognised in profit or loss
incorporates any interest paid on the financial liability.
Other financial liabilities, including borrowings, are initially
measured at fair value, net of transaction costs and are
subsequently measured at amortised cost using the effective
interest method, with interest expense recognised on an effective
yield basis.
The effective interest method is a method of calculating the
amortised cost of a financial liability and of allocating interest
expense over the relevant period. The effective interest rate is
the rate that exactly discounts estimated future cash payments
through the expected life of the financial liability, or, where
appropriate, a shorter period, to the net carrying amount on
initial recognition.
Share based payments
The fair value of options granted to directors and others in
respect of services provided is recognised as an expense in the
Statement of Comprehensive Income with a corresponding increase in
equity reserves - 'other reserves'.
On exercise or cancellation of share options, the proportion of
the share based payment reserve relevant to those options is
transferred from other reserves to the accumulated deficit. On
exercise, equity is also increased by the amount of the proceeds
received.
The fair value is measured at grant date and charged over the
accounting periods which the option becomes unconditional.
The fair value of options are calculated using the Black-Scholes
model, taking into account the terms and conditions upon which the
options were granted. Vesting conditions are non-market and there
are no market vesting conditions. These vesting conditions are
included in the assumptions about the number of options that are
expected to vest. At the end of each reporting period, the Company
revises its estimate of the number of options that are expected to
vest. The exercise price is fixed at the date of grant and no
compensation is due at the date of grant. Where equity instruments
are granted to persons other than employees, the statement of
comprehensive income is charged with the fair value of the goods
and services received.
Warrants issued for services rendered are accounted for in
accordance with IFRS 2 recognising either the costs of the service
if it can be reliably measured or the fair value of the warrant
(using the Black-Scholes model). The fair value is recognised as an
expense in the accounting period that the warrant is granted and
there is no revision to this estimate in future accounting
periods.
Warrants issued as part of share issues have been determined as
equity instruments under IAS 32. Since the fair value of the shares
issued at the same time is equal to the price paid, these warrants,
by deduction, are considered to have been issued at nil value.
2. Critical accounting judgments, estimates and assumptions
The Group makes estimates and assumptions regarding the future.
Estimates and judgements are continuously evaluated based on
historical experiences and other factors, including expectations of
future events that are believed to be reasonable under the
circumstances. In the future, actual experience may deviate from
these estimates and assumptions. The key assumptions concerning the
future and other key sources of estimation uncertainty at the
reporting date that have a significant risk of causing a material
adjustment to the carrying amounts of assets and liabilities within
the next financial year, are described below.
Recoverable value of Development & Production assets
-judgement, estimates and assumptions
Costs capitalised in respect of the Group's development and
production assets are required to be assessed for impairment under
the provisions of IAS 36. Such an estimate requires the Group to
exercise judgement in respect of the indicators of impairment and
also in respect of inputs used in the models which are used to
support the carrying value of the assets. Such inputs include
estimates of oil and gas reserves, production profiles, oil price,
oil quality discount, capital expenditure (including an allocation
of salary costs), inflation rates, and pre-tax discount rates that
reflect current market assessments of (a) the time value of money;
and (b) the risks specific to the asset for which the future cash
flow estimates have not been adjusted. The directors concluded that
there was no indication of impairment in the current year (an
impairment of $172,000 on the carrying value of the development and
production assets at Satskhenisi oilfield was recognised in the
prior year).
Asset Decommissioning Provisions -estimates and assumptions
The Group's activities are subject to various laws and
regulations governing the protection of the environment. The Group
recognises management's best estimate of the asset decommissioning
costs in the period in which they are incurred. Such estimates of
costs include pre-tax discount rates that reflect current market
assessments of (a) the time value of money; and (b) the risks
specific to the asset for which the future cash flow estimates have
not been adjusted. Actual costs incurred in future periods could
differ materially from the estimates.
Additionally, future changes to environmental laws and
regulations, life of development and production assets, estimates
and discount rates could affect the carrying amount of this
provision. The Board assessed the extent of decommissioning
required as at 31 December 2021 and concluded that a provision of
$2,040,000 (2020: $1,917,000) should be recognised in respect of
future decommissioning obligations at Rustaveli, West Rustavi,
Satskhenisi and Norio (refer note 15).
Share Options - estimates and assumptions
Share options issued by the Group relates to the Block Energy
Plc Share Option Plan. The grant date fair value of such options is
calculated using a Black-Scholes model whose input assumptions are
derived from market and other internal estimates.
The key estimates include volatility rates and the expected life
of the options, together with the likelihood of non-market
performance conditions being achieved. Refer note 23.
Accounting for business combinations and fair value - estimates
and assumptions
Business combinations are accounted for at fair value. The
assessment of fair value is subjective and depends on a number of
assumptions. These assumptions include assessment of discount
rates, and the amount and timing of expected future cash flows from
assets and liabilities. In addition, the selection of specific
valuation methods for individual assets and liabilities requires
judgment. The specific valuation methods applied will be driven by
the nature of the asset or liability being assessed. The
consideration given to a seller for the purchase of a business or a
company is accounted for at its fair value. When the consideration
given includes elements that are not cash, such as shares or
options to acquire shares, the fair value of the consideration
given is calculated by reference to the specific nature of the
consideration given to the seller. See note 12.
3. Segmental disclosures
IFRS 8 requires segmental information for the Group on the basis
of information reported to the chief operating decision maker for
decision making purposes. The Company considers this role as being
performed by the Board of Directors. The Group's operations are
focused on oil and gas development and production activities (Oil
Extraction segment) in Georgia and has a corporate head office in
the UK (Corporate segment). Based on risks and returns the
directors consider that there are two operating segments that they
use to assess the Group's performance and allocate resources being
the Oil Extraction in Georgia, and the Corporate segment including
unallocated costs.
The segmental results are as follows:
Oil Corporate Group Total
Extraction and other
Year ended 31 December 2021 $'000 $'000 $'000
Revenue 6,114 - 6,114
Cost of sales (2,982) - (2,982)
Depreciation and depletion (2,896) (5) (2,901)
Administrative costs (1,201) (3,725) (4,926)
Other income 5 - 5
Net Finance costs and Forex (90) (3) (93)
------------ ----------- ------------
Loss from operating activities (1,050) (3,733) (4,783)
------------ ----------- ------------
Total non-current assets 24,341 4 24,345
Oil Corporate
Extraction and other Group Total
Year ended 31 December 2020 $'000 $'000 $'000
Revenue 1,255 - 1,255
Cost of sales (2,203) - (2,203)
Depreciation and depletion (768) (13) (781)
Administrative costs (807) (3,129) (3,936)
Other income 100 - 100
Net Finance costs and income 29 24 53
------------ ----------- ------------
Loss from operating activities (2,394) (3,118) (5,512)
------------ ----------- ------------
Total non-current assets 21,304 7 21,311
31 December 2021 31 December 2020
Segmental Assets $'000 $'000
Oil exploration - Georgia 23,745 26,483
Corporate and other 7,181 7,529
------------------ -----------------
30,926 34,012
------------------ -----------------
Segmental Liabilities 31 December 2021 31 December 2020
$'000 $'000
Oil exploration - Georgia 3,087 3,239
Corporate and other 774 1,079
----------------- -----------------
3,861 4,318
----------------- -----------------
4. Revenue
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
Crude oil revenue 5,519 1,255
Gas revenue 595 -
------------- -------------
6,114 1,255
------------- -------------
5. Depreciation and Depletion on Oil and Gas assets
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
Depreciation of PP&E 238 109
Depletion of oil and gas assets 2,663 672
------------- -------------
2,901 781
------------- -------------
6. Expenses by nature
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
Employee benefit expense 1,720 1,559
Share option charge 1,224 460
Warrants charge 270 181
Security expense 162 -
Fees to Auditor in respect of the Group audit 93 94
Fees to Auditor in respect of the Company audit 93 94
Fees to Auditor for other non-audit services 7 39
Regulatory fees 51 38
Operating lease expense 49 57
7. Directors and employees
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
Employment costs (inc. directors' remuneration):
Wages and salaries 1,453 2,149
Pensions 55 147
Share based payments 1,449 641
Social security costs 212 48
3,169 2,985
------------- -------------
The share based payments comprised the fair value of options
granted to directors and employees in respect of services
provided.
Wages and salaries include amounts that are recharged between
subsidiaries. Some of these costs are then capitalised as
development and production assets and others are administration
expenses.
The average monthly number of employees during 2021 was 176
(2020:102) split as follows:
Year ended Year ended
31 December 31 December
2021 2020
Management 18 5
Technical 135 77
Administration 23 20
176 102
------------- -------------
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
Amounts attributable to the highest paid director:
Director's salary and bonus 358 350
Pension 27 25
Share based payments 183 67
568 442
------------- -------------
Key management and personnel are considered to be the
directors.
8. Finance Income
Year ended Year ended
31 December 2021 31 December
2020
$'000
$'000
Other finance income - 14
------------------- -------------
- 14
------------------------------------------------ -------------
9. Other income
Year ended Year ended
31 December 31 December
2021 2020
$'000 $'000
Sale of materials 5 100
------------- -------------
5 100
------------- -------------
During the year, materials to be used in the construction of the
gas pipeline from the Early Production Facility at West Rustavi
were sold for $5,000 (2020: $100,000).
10. Taxation
Based on the results for the year, there is no charge to UK or
foreign tax. This is reconciled to the accounting loss as
follows:
Year ended Year ended
31 December 31 December
2021 2020
UK taxation $'000 $'000
UK Loss on ordinary activities (4,783) (5,512)
------------- -------------
Loss before taxation at the average UK standard rate of 19% (2020:19%) (909) (1,047)
Effect of:
Zero tax rate income (1,162) (257)
Tax losses for which no deferred income tax asset was recognised 2,071 1,304
Current tax - -
------------- -------------
The Group offsets deferred tax assets and liabilities if, and
only if, it has a legally enforceable right to offset current tax
assets and current tax liabilities and the deferred tax assets and
deferred tax liabilities related to corporation taxes levied by the
same tax authority. Due to the tax rates applicable in the
jurisdictions of the Group's subsidiary entities (being 0%) no
deferred tax liabilities or assets are considered to arise.
Year ended Year ended
31 December 31 December
2021 2020
Unrecognised gross deferred tax position $'000 $'000
Tax losses bought forward 13,808 8,296
Total unrecognised gross deferred tax position at start of year 13,808 8,296
Tax losses not recognised in the year 4,783 5,512
Tax losses carried forward 18,591 13,808
Total unrecognised gross deferred tax position at end of year 18,591 13,808
------------- -------------
Year ended Year ended
31 December 31 December
2021 2020
Unrecognised deferred tax asset $'000 $'000
Total unrecognised deferred asset brought forward 1,304 1,206
Increase in asset 767 98
------------- -------------
Total unrecognised deferred asset carried forward 2,071 1,304
------------- -------------
For any other jurisdictions which the Group has not recognised
deferred income tax assets for tax losses carried forward for
entities in which it is not considered probable that there will be
sufficient future taxable profits available for offset.
Unrecognised deferred income tax assets related to unused tax
losses. The Company has UK corporation tax losses available to
carry forward against future profits of approximately
$18,591,000 (2020: $13,808,000).
11. Loss per share
The calculation for loss per Ordinary Share (basic and diluted)
is based on the consolidated loss attributable to the equity
shareholders of the Company is as follows:
Year ended Year ended
31 December 2021 31 December 2020
Loss attributable to equity Shareholders ($'000) (4,783) (5,512)
Weighted average number of Ordinary Shares 630,629,894 419,300,390
Loss per Ordinary share ($/cents) (0.76)c (1.31)c
Loss and diluted loss per Ordinary Share are calculated using
the weighted average number of Ordinary Shares in issue during the
year. Diluted share loss per share has not been calculated as the
options and warrants have no dilutive effect given the loss arising
in the year.
12. Acquisition of Subsidiaries and associated PSC interests
Acquisition of Block Rustaveli Limited ("BRL") in prior year
On 23 November 2020, the Company acquired 100% of the share
capital of Schlumberger Rustaveli Company Limited ("SRCL"). The
completion of the acquisition means the Company now holds licences
for Georgian onshore blocks IX and XI(B) . The Company changed the
name of the acquired company to Block Rustaveli Limited on 9
December 2020. The principal activity is oil and gas extraction and
it was acquired for the purposes of expanding the Company's
production and development business in Georgia.
On acquisition, the Company issued Schlumberger one US dollar
and an option to acquire 120 million 0.25p Ordinary Shares in Block
Energy Plc, at a nil exercise price, representing 16% of Block's
enlarged ordinary share capital (at 31 December 2020). The Options
are exercisable between 12 and 24 months from 23 November 2020.
The fair value of the 120 million share options issued was based
on the published closing price of the Ordinary Shares in Block
Energy Plc on 23 November 2020 of 4.45p per share. Following the
acquisition, the finalisation of the completion statement led to a
payment by Schlumberger of $278,190 to Block Energy Plc, which has
been recognised as a reduction in the fair value of the
consideration paid by Block Energy Plc for this acquisition,
because the payment was a contractual working capital adjustment to
compensate Block Energy Plc for liabilities that were deemed to be
for the seller's account.
Under IFRS 3, a business must have three elements: inputs,
processes and outputs. BRL has these three elements and, therefore,
this transaction has been accounted for as a business
combination.
The amounts recognised in respect of the identifiable assets
acquired and liabilities assumed of the business combination are as
set out in the table below:
Net book Fair value Fair value
value of adjustments of assets
assets acquired acquired
$'000 $'000 $'000
Development and production
assets - 6,258 6,258
Exploration and evaluation
assets 6,593 (6,593) -
PP&E 506 506
Oil inventory 867 147 1,014
Inventory and spare parts 1,535 - 1,535
Financial liabilities (275) - (275)
Provision for baseline oil
liability - (655) (655)
Provision for decommissioning
costs (1,562) - (1,562)
Total identifiable assets
acquired and liabilities
assumed 7,664 (843) 6,821
----------------- ------------- -----------
Provisional Fair Value of $'000
Consideration Paid:
Share options issued at nil
cost 7,099
Less cash received from seller
to adjust consideration (278)
Total consideration 6,821
-----------
Provisional goodwill on -
acquisition
-----------
Analysis of cash flows on $'000
acquisition
Payment on acquisition of -
subsidiary
Net cash acquired on acquisition -
-----------
Net cash inflow of acquisition -
-----------
Since the acquisition of BRL on 23 November 2020, BRL
contributed $308,000 and $183,000 in the year ended 31 December
2020 to the Group revenue and loss respectively. If the acquisition
had occurred on 1 January 2020, consolidated pro-forma revenue and
loss for the year ended 31 December 2020 would have been $483,000
and $7,534,000 respectively.
All of the identifiable assets acquired and liabilities assumed
were fair valued. PP&E and spare parts inventory were fair
valued based on the items' condition and application of an industry
accepted discount to the original cost. The oil inventory was fair
valued by management based on the net realisable value at the
acquisition date . Given the subjectivity in valuing undeveloped
reserves and unevaluated acreage, a market approach was used to
fair value the development and production assets, whereby the
seller marketed the business for sale and the acquisition price
paid was deemed to be the fair value of the sum of the identifiable
assets acquired and liabilities assumed. Therefore, the fair value
of the development and production assets was calculated as the
difference between the acquisition price paid and the fair value of
the other identifiable assets acquired and liabilities assumed.
13. Property, Plant and Equipment
PPE/Computer / Office Equipment /
Development & Production Assets Motor Vehicles Total
$'000 $'000 $'000
Cost
At 1 January 2020 13,204 129 13,333
Additions 2,772 210 2,982
Additions through acquisition 6,258 506 6,764
Disposals (138) (54) (192)
Foreign exchange movements - (14) (14)
---------------------------------- ----------------------------------- -------
At 31 December 2020 22,096 777 22,873
---------------------------------- ----------------------------------- -------
Reallocation of assets (780) 780 -
Additions 6,182 290 6,472
Disposals (38) (12) (50)
Reduction in BLO (see note
15) (498) - (498)
Foreign exchange movements - (33) (33)
---------------------------------- ----------------------------------- -------
At 31 December 2021 26,962 1,802 28,764
---------------------------------- ----------------------------------- -------
Accumulated Depreciation
At 1 January 2020 613 7 620
Disposals - (11) (11)
Charge for the year 672 109 781
Impairment charge 172 - 172
---------------------------------- ----------------------------------- -------
At 31 December 2020 1,457 105 1,562
---------------------------------- ----------------------------------- -------
Reallocation of assets (91) 91 -
Disposals - (1) (1)
Charge for the year 2,663 238 2,901
Foreign exchange movements - (43) (43)
At 31 December 2021 4,029 390 4,419
---------------------------------- ----------------------------------- -------
Carrying Amount
---------------------------------- ----------------------------------- -------
At 1 January 2020 12,591 122 12,713
---------------------------------- ----------------------------------- -------
At 31 December 2020 20,639 672 21,311
---------------------------------- ----------------------------------- -------
At 31 December 2021 22,933 1,412 24,345
---------------------------------- ----------------------------------- -------
Carrying amount of property plant and equipment by cash
generative unit:
Satsk
Norio henisi West Rustavi Rustaveli Corporate Total
$'000 $'000 $'000 $'000 $'000 $'000
Carrying amount
At 31 December 2021 2,222 176 14,045 7,721 181 24,345
------ -------- ------------- ------------ ---------- ---------
At 31 December 2020 2,298 230 11,767 6,866 150 21,311
------ -------- ------------- ------------ ---------- ---------
At the end of the current year, the directors concluded there
were no impairment indicators in the current year that warranted
impairment testing to be prepared with respect to the carrying
value of the assets of the Group.
14. Inventory
31 December 2021 31 December 2020
$'000 $'000
Spare parts and consumables 3,174 2,918
Crude oil 1,411 1,196
4,585 4,114
------------------ -----------------
Inventories recognised in cost of sales during the year amounted
to $(279,000), (2020: $886,000).
15. Provisions
31 December 2021 31 December 2020
$'000 $'000
Decommissioning provision 2,040 1,917
Baseline oil liability 265 745
------------------ -----------------
2,305 2,662
------------------ -----------------
31 December 31 December
2021 2020
Decommissioning provision $'000 $'000
Brought forward 1,917 276
Decommissioning provision arising from the
acquisition - 1,562
Additional decommissioning provision in the
year 123 79
Carried forward 2,040 1,917
------------- ------------
31 December 31 December
2021 2020
Baseline oil liability $'000 $'000
Brought forward 745 -
Baseline oil liability (reducing)/arising
from the acquisition (498) 654
Additional baseline oil liability provided
in the year 18 91
------------- ------------
Carried forward 265 745
------------- ------------
Decommissioning provisions are based on management estimates of
work and the judgement of the directors. By its nature, the
detailed scope of work required, and timing of such work is
uncertain.
The baseline oil liability arose from the acquisition of BRL
during the prior year. Under the production sharing contract for
Block XI(B) , BRL is obliged to deliver a certain quantity of oil
to the State of Georgia in quarterly instalments by May 2022. As at
31 December 2021, BRL owed 586 tonnes of baseline oil with a
present value of $262,000 to the State of Georgia.
16. Trade and other receivables
31 December 2021 31 December 2020
$'000 $'000
Other receivables 657 2,196
Prepayments 95 60
752 2,256
------------------ -----------------
In prior year, other receivables included proceeds receivable
from the share issue on 30 December 2020 amounting to $1,314,000
and $278,000 receivable from Schlumberger following the Completion
Statement and acquisition of BRL.
17. Cash and cash equivalents
31 December
2021 31 December 2020
$'000 $'000
Cash and cash equivalents 1,244 6,331
------------- -----------------
Cash and cash equivalents consist of balances in bank accounts
used for normal operational activities. The vast majority of the
cash was held at year end in an institution with a Fitch's credit
rating of BB-.
18. Trade and Other Payables
31 December 31 December
2021 2020
$'000 $'000
Trade and other payables 845 989
Accruals 711 667
1,556 1,656
------------- ------------
Trade and other payables principally comprise amounts
outstanding for corporate services and operational expenditure.
19. Share capital
Called up, allotted, issued Nominal
and fully paid No. Ordinary No. Deferred Value
Shares Shares $
As at 1 January 2020 394,438,662 2,095,165,355 2,622,866
------------- -------------- ----------
Issue of equity on 1 June 2020 1,654,824 - 5,204
Issue of equity on 10 June 2020 39,609,348 - 126,134
Issue of equity on 1 July 2020 188,435 - 588
Issue of equity on 1 August
2020 407,374 - 1,333
Issue of equity on 1 September
2020 544,400 - 1,814
Issue of equity on 1 October
2020 724,433 - 2,343
Issue of equity on 2 November
2020 450,541 - 1,456
Issue of equity on 1 December
2020 524,076 - 1,754
Issue of equity on 31 December
2020 176,000,000 - 589,017
As at 31 December 2020 614,542,093 2,095,165,355 3,352,509
------------- -------------- ----------
Issue of equity on 4 January
2021 617,571 - 2,098
Issue of equity on 12 January
2021 397,904 - 1,362
Issue of equity on 1 February
2021 839,996 - 2,937
Issue of equity on 15 February
2021 180,715 - 632
Issue of equity on 1 March 2021 232,248 - 800
Issue of equity on 12 March
2021 865,896 - 2,983
Issue of equity on 16 March
2021 6,590,707 - 22,752
Issue of equity on 7 April 2021 58,972 - 204
Issue of equity on 5 May 2021 171,715 - 611
Issue of equity on 7 June 2021 125,696 - 434
Issue of equity on 2 July 2021 1,355,805 - 4,713
Issue of equity on 2 September
2021 62,005 - 209
Issue of equity on 15 September
2021 24,877,230 - 83,684
Issue of equity on 4 October
2021 746,668 - 2,556
Issue of equity on 8 October
2021 299,412 - 1,025
Issue of equity on 2 November
2021 262,403 - 873
Issue of equity on 5 December
2021 522,489 - 1,766
As at 31 December 2021 652,749,525 2,095,165,355 3,482,148
------------- -------------- ----------
On 4 January 2021, the Company issued 617,571 Ordinary Shares to
a service provider in lieu of cash settlement for services provided
to the Company with a total value of GBP20,984 ($28,509).
On 12 January 2021, the Company issued 397,904 Ordinary Shares
to a Chris Brown, Non-executive Director, on exercise of his nil
cost options.
On 1 February 2021, the Company issued 839,996 Ordinary Shares
to six service providers in lieu of cash settlement for services
provided to the Company with a total value of GBP29,251
($40,914).
On 15 February 2021, the Company issued 180,715 Ordinary Shares
to a former employee/director on exercise of their nil cost
options.
On 1 March 2021, the Company issued 232,248 Ordinary Shares to
four service providers in lieu of cash settlement for services
provided to the Company with a total value of GBP7,542
($10,395).
On 12 March 2021, the Company issued 865,896 Ordinary Shares to
Philip Dimmock, Chairman and a Contractor, on exercise of their nil
cost options.
On 16 March 2021, the Company issued 4,400,000 Ordinary Shares
to Paul Haywood, Executive Director, on exercise of his options, at
an exercise price of 2.5 pence per share. Additionally on this
date, the Company issued 2,190,707 Ordinary Shares to a service
provider in lieu of cash settlement for services provided to the
Company with a total value of GBP72,134 ($100,000).
On 7 April 2021, the Company issued 58,972 Ordinary Shares to
one service provider in lieu of cash settlement for services
provided to the Company with a total value of GBP1,717
($2,372).
On 5 May 2021, the Company issued 171,715 Ordinary Shares to two
service providers in lieu of cash settlement for services provided
to the Company with a total value of GBP4,751 ($6,765).
On 7 June 2021, the Company issued 125,696 Ordinary Shares to
two service providers in lieu of cash settlement for services
provided to the Company with a total value of GBP3,234
($4,468).
On 2 July 2021, the Company issued 1,355,805 Ordinary Shares to
a former employee on exercise of their nil cost options at a value
of $44,269 to the Company as it met the income tax cost of this
issue.
On 2 September 2021, the Company issued 62,005 Ordinary Shares
to a service provider in lieu of cash settlement for services
provided to the Company with a total value of GBP155 ($209).
On 15 September 2021, the Company issued 24,877,230 Ordinary
Shares at their nominal value to the Employee Benefit Trust.
On 4 October 2021, the Company issued 746,668 Ordinary Shares to
four service providers in lieu of cash settlement for services
provided to the Company with a total value of GBP20,148
($27,589).
On 8 October 2021, the Company issued 299,412 Ordinary Shares to
a former Director, on exercise of their nil cost options.
On 2 November 2021, the Company issued 262,403 Ordinary Shares
to two service providers in lieu of cash settlement for services
provided to the Company with a total value of GBP5,533
($7,367).
On 5 December 2021, the Company issued 522,489 Ordinary Shares
to two service providers in lieu of cash settlement for services
provided to the Company with a total value of GBP8,033
($10,863).
On 2 June 2020, the Company issued 1,654,824 Ordinary Shares,
details of which are set out below:
150,731 Ordinary Shares have been allotted to Philip Dimmock,
Chairman, at an average price of 3.98p in settlement of fees
amounting to GBP6,000 due to him and 100,486 Ordinary Shares have
been allotted to Chris Brown, Non-Executive Director, at an average
price of 3.98p in settlement of fees of GBP4,000 due to him.
1,124,058 Ordinary Shares have been allotted to two consultants
to the Company as settlement for services provided on the Georgian
operations during the period from February 2019 to March 2020 with
a total value of GBP57,229.
75,000 Ordinary Shares have been allotted to Timothy Parson,
former Non-Executive Director of the Company, as settlement for
services provided on the Georgian operations during 2017 with a
total value of GBP3,000.
204,549 Ordinary Shares have been allotted to an adviser to the
Company in lieu of cash settlement for services provided to the
Company during the two months period from 1 April 2020 to 31 May
2020 with a total value of GBP3,433.
On 10 June 2020, the Company issued 39,609,348 new Ordinary
Shares at their nominal value to the EBT.
On 1 July 2020, the Company issued 188,435 Ordinary Shares to
two service providers in lieu of cash settlement for series
provided to the Company with a total value GBP4,417 ($5,513).
On 3 August 2020, the Company issued 407,374 Ordinary Shares of
0.25p each to three service providers in lieu of cash settlement
for services provided to the Company with a total value of
GBP10,000 ($13,088).
On 2 September 2020, the Company issued 544,400 Ordinary Shares
0.25p each to three service providers in lieu of cash settlement
for services provided to the Company with a total value of
GBP13,184 ($17,574).
On 2 October 2020, the Company issued 724,433 Ordinary Shares
0.25p each to four service providers in lieu of cash settlement for
services provided to the Company with a total value of GBP19,212
($24,853).
On 2 November 2020, the Company issued 450,451 Ordinary Shares
0.25p each to four service providers in lieu of cash settlement for
services provided to the Company with a total value of GBP11,268
($14,565).
On 2 December 2020, the Company issued 524,076 Ordinary Shares
0.25p each to seven service providers in lieu of cash settlement
for services provided to the Company with a total value of
GBP15,819 ($21,177).
On 30 December 2020, the Company raised gross proceeds of
GBP5,280,000 ($7,068,287) through the placing of 176,000,000
Ordinary Shares at 3p per share.
The Ordinary Shares consist of full voting, dividend and capital
distribution rights and they do not confer any rights for
redemption. The Deferred Shares have no entitlement to receive
dividends or to participate in any way in the income or profits of
the Company, nor is there entitlement to receive notice of, speak
at, or vote at any general meeting or annual general meeting.
20. Share premium account
$'000
Balance at 1 January 2021 34,234
Premium arising on issue of equity shares 391
Share issue costs -
-------
Balance at 31 December
2021 34,625
-------
$'000
Balance at 1 January 2020 27,985
Premium arising on issue of equity shares 6,654
Share issue costs (405)
-------
Balance at 31 December 2020 34,234
-------
21. Reserves
The following describes the nature and purpose of each reserve
within owners' equity.
Reserves Description and purpose
Share Capital Amount subscribed for share capital at nominal value.
Share premium account Amount subscribed for share capital in excess of nominal value, less attributable
costs.
Other reserves The other reserves comprises the fair value of all share options and warrants which
have been
charged over the vesting period, net of the amount relating to share options which
have expired,
been cancelled and have vested. It also comprises of the fair value of the share
options issued
as part of the consideration paid for the acquisition of the subsidiary BRL and the
movement
has been shown in the Consolidated Statement of the Changes in Equity.
Foreign exchange reserve Exchange differences on translating the net assets of foreign operations
Accumulated deficit Cumulative net gains and losses recognised in the income statement and in respect of
foreign
exchange.
22. Warrants
31 December 2021 31 December 2020
weighted average weighted average
Number of Warrants exercise price Number of Warrants exercise price
Outstanding at the
beginning of the
year 16,820,502 6p 8,070,335 10p
Additions - - 8,750,167 3p
Outstanding at the
end of the year 16,820,502 6p 16,820,502 6p
------------------- ----------------------- ------------------- ------------------------
As at 31 December 2021, all warrants were available to exercise
and were exercisable at prices between 3p and 12.5p (31 December
2020: 3p and 12.5p). The weighted average life of the warrants is
2.65 years (31 December 2020: 3.6 years). No new warrants were
issued and no existing warrants were exercised or lapsed during the
year. The additions during the prior year represent warrants issued
with 5 year terms. The fair value of additions during the year was
$nil (2020: $376,000).
23. Share based payments
During the year, the Group operated a Block Energy Plc Share
Option Plan (Share Option Scheme).
Under IFRS 2, an expense is recognised in the statement of
comprehensive income for share based payments, to recognise their
fair value at the date of grant. The application of IFRS 2 gave
rise to a charge of $1,494,000 for the year ended 31 December 2021.
The equivalent charge for the year ended 31 December 2020 was
$641,000. The Group recognised total expenses (all of which related
to equity settled share-based payment transactions) under the
current plans of:
2021 2020
$'000 $'000
Share option scheme 1,224 460
Warrants charge 270 181
1,494 641
-------- -------
Share Option Scheme
The vesting period varies between 0 days to 3 years. The options
expire if they remain unexercised after the exercise period has
lapsed and have been valued using the Black Scholes model.
The following table sets out details of all outstanding options
granted under the Share Option Scheme.
2021 2021 2020 2020
Weighted Weighted
average exercise average exercise
Options price Options price
Outstanding at beginning
of year 31,338,713 $0.05 27,437,856 $0.07
Granted during the
year 44,136,726 $0.02 9,230,112 $0.00
Exercised during
the year (25,211,024) $0.01 (1,997,622) $0.03
Expired during the
year (3,198,464) $0.04 (3,331,633) $0.06
-------------------------- ------------- ------------------ ------------ ------------------
Outstanding at the
end of the year 47,065,951 $0.05 31,338,713 $0.05
-------------------------- ------------- ------------------ ------------ ------------------
Exercisable at the
end of the year 29,161,323 $0.03 30,040,857 $0.01
-------------------------- ------------- ------------------ ------------ ------------------
The weighted average exercise price of the share options
exercisable at 31 December 2021 is $0.03 (31 December 2020: $0.01).
The weighted average contractual life of the share based payments
outstanding at 31 December 2021 is 9.8 years (31 December 2020: 3.6
years).
The estimated fair values of options which fall under IFRS 2,
and the inputs used in the Black-Scholes model to calculate those
fair values are as follows:
Date of Number Estimated Share Exercise Expected Expected Risk Expected
grant of options fair price price volatility life free dividends
value rate
5.5
30 June 2017 1,200,000 $0.04 $0.01 $0.03 84% years 1.16% 0%
6 April 2018 4,400,000 $0.05 $0.04 $0.03 84% 10 years 1.34% 0%
11 June 2018 18,098,332 $0.04 $0.05 $0.05 84% 10 years 1.23% 0%
21 October 9.0
2019 6,325,000 $0.05 $0.06 $0.15 109% years 0.63% 0%
9.5
1 March 2021 10,800,00 $0.04 $0.04 $0.06 192% years 0% 0%
Warrants
31 December
2020 8,750,167 $0.04 $0.04 $0.04 190% 5 years 0% 0%
All share based payment charges are calculated using the fair
value of options.
For the options granted prior to 30 June 2018, expected
volatility was determined by reviewing benchmark values from
comparator companies. For the options granted after 30 June 2018,
expected volatility was determined by reference to the volatility
of historic trading prices of the Company's shares.
24. Financial instruments
Capital Risk Management
The Company manages its capital to ensure that entities in the
Group will be able to continue as a going concern while maximising
the return to stakeholders. The overall strategy of the Company and
the Group is to minimise costs and liquidity risk.
The capital structure of the Group consists of equity
attributable to equity holders of the parent, comprising issued
share capital, foreign exchange and other reserves and retained
earnings as disclosed in the Consolidated Statement of Changes of
Equity.
The Group is exposed to a number of risks through its normal
operations, the most significant of which are interest, credit,
foreign exchange and liquidity risks. The management of these risks
is vested to the Board of Directors.
The sensitivity has been prepared assuming the liability
outstanding was outstanding for the whole period. In all cases
presented, a negative number in profit and loss represents an
increase in finance expense / decrease in interest income.
Fair Value Measurements Recognised in the Statement of Financial
Position
The following provides an analysis of the Group's financial
instruments that are measured subsequent to initial recognition at
fair value, grouped into Levels 1 & 2 based on the degree to
which the fair value is observable.
- Level 1 fair value measurements are those derived from inputs
other than quoted prices that are observable for the asset or
liability, either directly (i.e. as prices) or indirectly (i.e.
derived from prices).
- Level 2 fair value measurements are those derived from
valuation techniques that include inputs for the asset or liability
that are not based on observable market data (unobservable
inputs).
- Level 3 assets are assets whose fair value cannot be
determined by using observable inputs or measures, such as market
prices or models. Level 3 assets are typically very illiquid, and
fair values can only be calculated using estimates or risk-adjusted
value ranges.
Credit risk
Credit risk is the risk that the Group will suffer a financial
loss as a result of another party failing to discharge an
obligation and arises from cash and other liquid investments
deposited with banks and financial institutions and receivables
from the sale of crude oil.
For deposits lodged at banks and financial institutions these
are all held through a recognised financial institution. The
maximum exposure to credit risk is $1,244,000 (2020: $6,331,000).
The Group does not hold any collateral as security.
The carrying value of cash and cash equivalents and financial
assets represents the Group's maximum exposure to credit risk at
year end. The Group has no material financial assets that are past
due.
The Company has made unsecured interest-free loans to its
subsidiary companies. Although the loans are repayable on demand,
they are unlikely to be repaid until the projects become successful
and the subsidiaries start to generate revenues. An assessment of
the expected credit loss arising on intercompany loans is detailed
in note 6 to the parent Company financial statements.
Market risk
Market risk arises from the Group's use of interest bearing and
foreign currency financial instruments. It is the risk that future
cash flows of a financial instrument will fluctuate because of
changes in interest rates (interest rate risk), and foreign
exchange rates (currency risk).
There are no variable interest bearing loans in the Group. No
risk therefore identified.
Currency risk
Foreign currency risk can only arise on financial instruments
that are denominated in a currency other than the functional
currency in which they are measured. Translation-related risks are
therefore not included in the assessment of the entity's exposure
to currency risks. Translation exposures arise from financial and
non-financial items held by an entity (for example, a subsidiary)
with a functional currency different from the group's presentation
currency. However, foreign currency-denominated inter-company
receivables and payables which do not form part of a net investment
in a foreign operation would be included in the sensitivity
analysis for foreign currency risks; this is because, even though
the balances eliminate in the consolidated balance sheet, the
effect on profit or loss of their revaluation under IAS 21 is not
fully eliminated.
A 10% increase in the strength of the pound sterling against the
US dollar would cause an estimated increase of $480,000 (2020:
$629,000 increase) in the loss after tax of the Group for the year
ended 31 December 2021, with a 10% weakening causing an equal and
opposite decrease. The impact on equity is the same as the impact
on loss after tax.
The Group's cash and cash equivalents and liquid investments are
mainly held in US dollars, pounds sterling and Georgian Lari. At 31
December 2021, 3% of the Group's cash and cash equivalents and
liquid investments were held in pounds sterling, 88% in Georgian
Lari and the remainder in US dollars, Euros and Canadian dollars
(31 December 2020: 90% in pounds sterling).
Liquidity risk
Liquidity risk arises from the possibility that the Group and
its subsidiaries might encounter difficulty in settling its debts
or otherwise meeting its obligations related to financial
liabilities. In addition to equity funding, additional borrowings
have been secured in the past to finance operations. The Company
manages this risk by monitoring its financial resources and
carefully plans its expenditure programmes. Financial liabilities
of the Group comprise trade payables which mature in less than
twelve months.
25. Categories of financial instruments
In terms of financial instruments, these solely comprise of
those measured at amortised cost and are as follows:
31 December 2021 31 December 2020
$'000 $'000
Liabilities at amortised cost 1,556 1,656
1,556 1,656
------------------ -----------------
Cash and cash equivalents at amortised cost 1,244 6,331
Financial assets at amortised cost 657 2,196
------------------ -----------------
1,901 8,527
------------------ -----------------
No collateral has been pledged in relation thereto.
26. Subsidiaries
At 31 December 2021, the Group consists of the following
subsidiaries, which are wholly owned by the Company.
Proportion of voting Proportion of voting
Country of rights and equity rights and equity
Company Incorporation interest interest
2021 2020
Block Norioskhevi Ltd British Virgin Islands 100% 100%
Satskhenisi Ltd Marshall Islands 100% 100%
Georgia New Ventures
Inc. Bahamas 100% 100%
Block Operating
Company LLC Georgia 100% 100%
Block Rustaveli
Limited British Virgin Islands 100% 100%
Subsidiaries - Nature of business
The principal activity of Georgia New Ventures Inc, Satskhenisi
Ltd, Block Norioskhevi Ltd and Block Rustaveli Limited is oil and
gas development and production.
The principal activity of Block Operating Company LLC is to be
the operator of the oil and gas licenses held in Georgia.
Registered Office
The registered office of Georgia New Ventures Inc. is Bolam
House, King and George Streets, P.O. Box CB 11.343, Nassau,
Bahamas.
The registered office of Satskhenisi Ltd is Trust Company
Complex, Ajeltake road, Ajeltake Island, Majuro, Marshall Islands
MH96960.
The registered office of Block Norioskhevi Ltd is Trident
Chambers, P.O.Box 146, Road Town, Tortola, British Virgin
Islands.
The registered office of Block Operating Company LLC is 13A
Tamarashvili Street, Tbilisi 0162, Georgia.
The registered office of Block Rustaveli Limited is Craigmuir
Chambers, Road Town, Tortola, VG1110, British Virgin Islands.
27. Commitments
Commitments at the reporting date that have not been provided
for were as follows:
Operating lease commitment
UK operating lease commitment
At 31 December 2021 and 31 December 2020, the total of future
minimum lease payments under non-cancellable operating leases for
each of the following periods was:
31 December 31 December 2020
2021 $'000
$'000
Within 1 year - -
Between 1 and 5 years - -
Total - -
------------- -----------------
28. Related party transactions
Key management personnel comprises of the directors and details
of their remuneration are set out in Note 7 and the Remuneration
Report.
In the prior year, on 1 June 2020, 75,000 Ordinary Shares were
issued to Timothy Parson, former Non-Executive Director of the
Company, as settlement for services provided on the Georgian
operations during 2017 with a total value of GBP3,000 ($4,000).
29. Events occurring after year end
There were no material events occurring after the year end.
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END
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