TIDMIGAS
RNS Number : 5265M
Igas Energy PLC
22 September 2021
THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION
22 September 2021
IGas Energy plc (AIM: IGAS)
("IGas" or "the Company" or "the Group")
Unaudited Interim results for the six months ended 30 June
2021
IGas announces its unaudited interim results for the six months
to 30 June 2021.
Results Summary
Six months Six months
to 30 June to
2021 30 June 2020
GBPm GBPm
---------------------------------------- ----------- -------------
Revenues 16.6 10.5
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Adjusted EBITDA* 2.7 2.2
---------------------------------------- ----------- -------------
Loss after tax - continuing activities (12.2) (30.0)
---------------------------------------- ----------- -------------
Operating cash flow before working
capital movements and realised hedges* 6.4 (1.4)
---------------------------------------- ----------- -------------
Net debt* (excluding capitalised fees) 13.2 11.2
Cash and cash equivalents 2.8 2.6
---------------------------------------- ----------- -------------
*these are alternative performance measures which are further
detailed in the financial review
Corporate & Financial Summary
-- Cash balances as at 30 June 2021 were GBP2.8 million (H1
2020: GBP2.6 million) with net debt of GBP13.2 million (H1 2020:
GBP11.2 million).
-- GBP2.6 million of capex incurred during six months to 30 June
2021. Net cash capex for FY 2021 expected to be GBP5.6 million,
primarily relating to our conventional assets.
-- Operating cash flow before working capital movements and
realised hedges in H1 2021 of GBP6.4 million (H1 2020: cash outflow
GBP1.4 million).
-- Successful Reserve Based Lending facility (RBL)
redetermination in June (a semi-annual recalculation), confirming
US$27 million (GBP19.5 million) of debt capacity and headroom of
US$8.8 million (GBP6.4 million).
-- Hedging in place for H2 2021 of 190,800 bbls using swaps and
collars. Average price including collar upside of c.$49/bbl.
126,000 bbls are currently hedged in 2022 using swaps at an average
price of $63/bbl and 114,000 bbls using puts with an average
guaranteed minimum price, net of premiums, of $44/bbl. The RBL
requires IGas to hedge c.50% of the next twelve months' production
on a rolling basis.
Operational Summary
-- Net production averaged 2,005 boepd in H1 2021 (H1 2020:
1,940 boepd) with operations, maintenance and project activities
all being directly and indirectly impacted by COVID-19. Excluding
the total COVID-19 impact in H1 2021, which averaged c.180 boepd,
production in H1 2021 would have been 2,185 boepd.
-- Full year net production is now forecast to be c.2,000 boepd,
with underlying cash operating costs per boe anticipated to be
c.$38/boe (based on an exchange rate of GBP1:$1.39).
-- Material progress on deep geothermal
o Planning approval received for Stoke-on-Trent and MoU with SSE
to deliver the heat network
o Constructive discussions with Government in respect of
downstream financial support. In addition, there has been a
geothermal Ministerial roundtable and a Westminster Hall Debate -
on 'Opportunities for geothermal energy extraction.'
-- MoU signed with CeraPhi to jointly develop geothermal energy
projects which repurpose and utilise IGas's existing wells and
other infrastructure and use CeraPhi's patented technology,
CeraPhiWell, a closed loop downhole heat exchanger.
-- The planning applications for the Albury and Bletchingley
hydrogen projects have been submitted and validated by Surrey
County Council.
-- Full CPR published in February 2021: 2P reserves replacement 250% (1P 275%)
o 1P NPV10 of $150 million: 2P NPV10 of $204 million*
*based on forward oil curve of: 2021 $53/bbl; 2022 $56/bbl; 2023
$58/bbl; 2024 $59/bbl; 2025 $62/bbl (for full price deck see
CPR).
Commenting today Stephen Bowler, Chief Executive Officer,
said:
"The health, safety, societal and economic impacts of the
COVID-19 pandemic have presented a unique set of challenges for our
production business. Despite these challenges, production remains
robust. We continue to focus our technical and operational
expertise on offsetting the underlying natural decline in our
fields through the execution of incremental production
opportunities that demonstrate commercial benefit via our delivery
assurance processes.
The Group's existing operational expertise as the UK's largest
onshore operator gives us the opportunity to use our existing
business platform to play an important role in the UK's transition
to net zero. Our sub-surface expertise is relevant both to drilling
for geothermal resources, and assessing the potential for carbon
capture and storage. We have extensive experience of dealing with
onshore regulators and planning authorities. We have predictable
operating cash flows to help fund new initiatives and assets to
repurpose in a readily accessible onshore environment.
We have progressed our low-carbon projects during the period. We
have submitted planning applications to produce hydrogen from two
existing sites in Surrey - Albury and Bletchingley. Should we be
successful in developing these blue hydrogen projects, IGas is on
track to produce the UK's first blue hydrogen ahead of other,
refinery scale projects. This demonstrates that small-scale,
distributed hydrogen production will allow blue hydrogen to be
offered to the market rapidly and will build resilience into new
energy networks.
In geothermal, the Stoke-on-Trent project could be the first in
a new generation of British-backed heat plants. It will support the
decarbonisation of heat, move us along the path to net zero and
help tackle climate change. Whilst we await the necessary
Government support for the Stoke-on-Trent project, we are receiving
an increasing number of enquiries from local councils and other
large-scale users of heat.
We believe there is significant commercial potential for
geothermal energy production and the development of localised
hybrid energy systems generating both heat and power."
A results presentation will be available at
http://www.igasplc.com/investors/presentations .
Qualified Person's Statement
Ross Pearson, Technical Director of IGas Energy plc, and a
qualified person as defined in the Guidance Note for Mining, Oil
and Gas Companies, March 2006, of the London Stock Exchange, has
reviewed and approved the technical information contained in this
announcement. Mr Pearson has 20 years oil and gas exploration and
production experience.
For further information please contact:
IGas Energy plc Tel: +44 (0)20 7993 9899
Stephen Bowler, Chief Executive Officer
Ann-marie Wilkinson, Director of Corporate Affairs
Investec Bank plc (NOMAD and Joint Corporate Broker) Tel: +44 (0)20 7597 5970
Sara Hale/Jeremy Ellis/Virginia Bull
Canaccord Genuity (Joint Corporate Broker) Tel: +44 (0)20 7523 8000
Henry Fitzgerald-O'Connor/James Asensio
Vigo Consulting Tel: +44 (0)20 7390 0230
Patrick d'Ancona/Chris McMahon/Kendall Hill
Introduction and Market Backdrop
Whilst the rebound in oil prices since the start of the year
hitting highs of c.$75/bbl has been driven by a mixture of some
early economic recovery and continued production restraint by
OPEC+, the spectre of COVID-19 mutations in many major economies
and pace of vaccine roll-outs could still impact oil demand growth
in the second half of 2021.
Having said that, world demand for crude is stronger than it was
last year and the International Energy Agency anticipates that by
the end of 2022 consumption will rise by about 5% from 2020 levels.
In the longer term, the lack of commitment in investment by the oil
majors will also put upward pressure on prices but ultimately the
balance between these factors will depend on OPEC's future
decisions on output.
Natural gas prices in Europe and the UK have also been very
strong recently. In the UK, prices have risen to over 100p/therm, a
record for summer months as global supplies have tightened as
economies rebound from the COVID-19 pandemic. High prices in Asia
also make it harder for Europe to attract cargoes of liquefied
natural gas, and Europe's stock levels remain low.
Against this backdrop and the ongoing challenges of the COVID-19
pandemic on our business, we have continued to pursue our strategy
of maximising our UK onshore production whilst exposing
shareholders to value creating opportunities in the energy
transition space, principally through geothermal and hydrogen.
The increase in the oil price in recent months has been a
welcome boost to revenue and cash generation and following the cost
reduction exercises implemented last year, we have continued to
tightly manage our finances. We have also successfully completed
the scheduled six-monthly RBL facility redetermination process. The
redetermination exercise confirmed US$27.0 million (GBP19.5
million) of debt capacity and headroom of US$8.8 million (GBP6.4
million) at 30 June 2021.
Throughout the pandemic, the health and safety of all staff and
contractors across our operations has been, and remains, our
priority while ensuring that the business continues to operate
safely and effectively.
As detailed in our 2020 Annual Report, we are now reporting
Scope 1 and 2 emissions under the SECR disclosure and are reviewing
our energy consumption with the aim of delivering ongoing
reductions in emissions and further reducing our emissions
intensity ratio. As part of our efforts to strengthen our ESG
performance, IGas continues its commitment to the UN Sustainable
Development Goals and has recently committed to the UN Global
Compact's 10 Principles on human rights, labour standards, the
environment, and anti-corruption. We continue to support the
communities in which we operate through investment in local
projects.
The Committee on Climate Change (CCC) acknowledges that oil and
gas will be important contributors to the UK's energy needs for
many years to come and that there will be a structural shortage in
supply. In their March 2021 assessment of the compatibility of
onshore oil and gas with the UK's net zero target, the CCC stated
that UK shale gas production could save up to 11.5 million tonnes
of CO(2) equivalent (CO(2) e) in the year 2035 alone. Based on
analysis of the shortfall between supply and demand using the same
method as the CCC, the failure to develop onshore natural gas
resources in the UK will add up to 145 million tonnes CO(2) e to
the UK's fuel supply carbon footprint by 2050.
Production operations
Net production for the period averaged 2,005 boepd. The health,
safety, societal and economic impacts of the COVID-19 pandemic have
presented a unique set of challenges for our production business.
There are both direct and indirect consequences of managing the
effects of the virus, some of which have immediate impact and
others that are extended over longer periods. We have identified
three key drivers to "COVID-19 related" production deferral;
Internal Resourcing, External Resourcing & External Supply
Chain, and our analysis of the production impact during the period
has shown fluctuations on a month-by-month basis. The average
impact for the six month period was c.180 boepd and in light of
this, we have revised our full year forecast to anticipate net
production of c.2,000 boepd. Encouragingly, we have observed an
improving downward trend in disruption as the UK pandemic situation
has improved, though we recognise that there are still inherent
risks ahead and the uncertainty will continue for at least the
remainder of the year.
Despite these challenges, we continue to focus our technical and
operational expertise on offsetting the underlying natural decline
in our fields through the execution of incremental production
opportunities that demonstrate commercial benefit via our delivery
assurance processes. Artificial lift optimisation remains a key
continuous improvement objective in terms of cost management and
production enhancement, with routine dynamic optimisation
activities and specific intervention works sanctioned. This has
included the introduction of innovative scale management
technology, artificial lift type conversions, rod string
improvements, rod pump deepening plus the expansion of the beam-gas
compressor systems across more fields. In addition, we have
continued to invest in our facilities to drive operational
improvements such as replacing older power generation systems with
newer, more efficient versions and the continued expansion and
modernisation of our instrumentation systems.
In February 2021, we announced the publication of a CPR by
DeGolyer & MacNaughton (D&M), a leading international
reserves and resources auditor.
The report comprised an independent evaluation of IGas'
conventional oil and gas interests as of 31 December 2020. The full
report can be found on the IGas website
www.igasplc/investors/publications-and-reports
IGas Group Net Reserves & Contingent Resources as at 31
December 2020 (MMboe)
1P 2P 2C
Reserves & Resources as at 31 December 2019 10.55 16.05 19.51
Production during the period (0.68) (0.68) -
Revision of estimates 1.87 1.75 0.84
Reserves & Resources as at 31 December 2020 11.74 17.12 20.35
The report confirms a continuing high reserves replacement of 2P
reserves of approximately 250% reflecting the good performance of
our production assets and progression of projects demonstrating the
significant upside that remains in our conventional portfolio. Some
85% of the 2P is developed meaning it does not require any capital
investment to produce.
IGas has a track record of significant reserves replacement with
a three-year average of over 200%.
This independent report valued our conventional assets at c.$204
million on a 2P NPV10 basis: 1P NPV10 of $150 million (based on
forward oil curve of 2021 $53/bbl; 2022 $56/bbl; 2023 $58/bbl; 2024
$59/bbl; 2025 $62/bbl).
Development assets
Petroleum
The Welton (C-1) waterflood project was brought online in Q2
2021 and completed on budget with good results as anticipated,
injecting an average of c.400 bbls/d of water which is expected to
increase field recovery by approximately 660 Mbbls adding over 100
bopd incremental production which will be realised in 2022.
Scampton North is on the lower end of expectation encountering
higher than anticipated injection pressure, injecting c. 90 bbls/d
of water. Work is ongoing to resolve the lower injection rates and
higher pressure but even at lower than expected results it is still
anticipated to increase ultimate field recovery. These projects not
only add incremental value but also improve environmental impact by
reducing emissions and reducing vehicle movements in water
handling.
A permit application has been submitted to convert an existing,
suspended well in the Stockbridge field to a water disposal well;
this will allow for the resumption of c. 50 bbls/d of suspended
production to be brought back on line. The project will also
provide more operational flexibility in handling produced water in
the Stockbridge area. This work is anticipated to be completed in
early 2022.
Energy Diversification
We continue to evaluate the viability of enhancing our UK sites
to include renewable energy. It is feasible that a number of our UK
sites could become integrated hybrid energy hubs, encompassing
combinations of solar, modular hydrogen, Carbon Capture,
Utilisation and Storage (CCUS) and battery storage.
Geothermal
Good progress is being made in developing our UK geothermal
business. We have now received planning approval for the
Stoke-on-Trent project from both Stoke-on-Trent City Council and
Newcastle-under-Lyme. We have signed a Memorandum of Understanding
(MoU) with SSE Heat Networks Limited (SSE) for roll-out of
geothermal district heating project in Stoke. The MoU grants
exclusivity to each of SSE and GTE with regard to the project for a
period of 12 months with certain milestones including executing a
heat offtake agreement in relation to GTE's future geothermal
plant. . We are in dialogue with the Government regarding grant
funding to support the project - which has public backing from the
council and the Staffordshire Chamber of Commerce - to provide
renewable heat to the Stoke heat network.
We continue to have positive discussions with the Government
regarding future financial support for the UK geothermal industry.
A working group with the Department for Business, Energy and
Industrial Strategy (BEIS) has been established to look at the
policy gap for non-domestic renewable heat and a financial model
for the long-term support of deep geothermal heat. We still await
publication of the delayed BEIS Heat and Building Strategy.
In April 2021, a new industry report on the economic and
environmental importance of UK deep geothermal resources by the
ARUP Group and the Association for Renewable Energy and Clean
Technology (REA) was published. The Report estimates that, with
immediate government support, the UK could deliver 360 geothermal
projects by 2050. This would include an estimated 12 projects being
operational by 2025 with 1,300 jobs created and c.GBP100 million of
investment flowing into the UK economy. The full report can be
found at
https://www.igasplc.com/investors/publications-and-reports
The Committee on Climate Change stated that only decarbonisation
of heat in the UK could deliver the major reduction in emissions
needed to meet the 2050 net zero target. By delivering on average
12 heat projects per year over the next three decades, the UK could
expect to generate up to 15,000 GW hours (GWh) of heat from
geothermal, annually by 2050.
As local authorities and other large-scale users of heat
transition away from fossil fuels we are receiving an increasing
number of enquiries looking to geothermal as a solution and through
this growing pipeline of development opportunities, IGas is well
positioned to deliver a solution to the long-term decarbonisation
for heat in the UK.
Hydrogen
Significant work has been undertaken in order to understand the
potential for low carbon energy production from our existing asset
base. This has resulted in the recent planning applications to
produce hydrogen from two existing sites in Surrey - Albury and
Bletchingley.
At Albury, we have now submitted a planning application that has
been validated by Surrey County Council to install a hydrogen
generation system on the existing site. The steam methane
reformation (SMR) unit will generate 1000kg/day of hydrogen.
A second application at our existing Bletchingley site was
submitted in late August. This is a bigger project involving two
SMR units with initial generation of 2000kg/day and a potential of
up to 6000kg/day depending on reserves.
The projects are being developed in phases, the first phase
being to establish the principle of hydrogen production at the
sites. The second, to produce blue hydrogen, is now being
accelerated following positive feedback from key regulators and
interest from local communities.
Discussions with potential offtakers are taking place for both
projects.
Shale
Discussions are ongoing with partners and regulators in respect
to the effective moratorium on shale albeit impacted by COVID-19
priorities. We believe we can demonstrate that we can operate
safely and environmentally responsibly.
As imports continue to rise and the need for gas and in
particular, methane for hydrogen, has been made clear by the
Committee on Climate Change, the safe development of shale could
play a critical role in the UK's energy transition and in the
creation of jobs and wealth to a number of key areas.
The Springs Road well proved that the Gainsborough Trough has a
world-class resource and therefore could be part of that solution,
producing indigenous gas, providing many skilled jobs and all at
lower emissions than imported gas. We still believe the Springs
Road site is of national importance and we therefore applied to
extend the operational period of the site for a further three years
while discussions continue with the UK Government and regulators.
In July 2021, despite a recommendation by the Planning Officer, the
planning committee at Nottinghamshire County Council voted against
the extension. We are considering our options along with our
partners including our right to bring forward an appeal.
We still await a decision on our appeal at Ellesmere Port now
over two years since the appeal was recovered by the Secretary of
State and 50 months since the initial application.
Financial review
The Group generated revenue of GBP16.6 million in the first six
months of 2021 from sales of 330,984 barrels of oil, including
sales of third party oil, 7,112 Mwh of electricity and 1,247,946
therms of gas (H1 2020: revenue GBP10.5 million, sales of 335,687
barrels of oil, 4,411 Mwh of electricity and 966,445 therms of
gas). The higher revenue was driven by the improvement in Brent
prices, which averaged $64.9/bbl during H1 2021 compared to
$39.1/bbl in H1 2020 as a result of OPEC constraining supply and
increased demand as economies started to recover from the impacts
of the COVID-19 pandemic. This was offset by a strengthening of
sterling versus the US dollar with an average USD/GBP rate of
$1.39/GBP1 in H1 2021 compared to $1.28/GBP1 in H1 2020. The Group
incurred a realised loss on oil price hedges with 208,800 bbls
hedged for H1 2021 at an average price of $44.5/bbl.
Adjusted EBITDA for H1 2021 was GBP2.7 million (H1 2020: GBP2.2
million) and the loss after tax from continuing activities was
GBP12.2 million (H1 2020: loss of GBP30.0 million). The main
factors explaining the movements between H1 2021 and H1 2020 were
as follows:
-- Revenues of GBP16.6 million (H1 2020: GBP10.5 million) were
higher than the first half of 2020 due to higher oil prices as
described above;
-- DD&A decreased to GBP2.4 million (H1 2020: GBP3.5
million) mainly due to the lower carrying value of assets in 2021
following the impairment to oil and gas properties in 2020;
-- Operating costs decreased to GBP8.6 million (H1 2020: GBP9.3
million). The decrease was mainly due to lower transportation
costs, lower rates and licence fee costs and reduced staff costs as
a result of the cost saving measures implemented in 2020. These
savings were partially offset by increased workover activity and an
increase in electricity costs;
-- Administrative expenses decreased to GBP2.3 million (H1 2020:
GBP2.8 million) primarily due to a reduction in staff costs as part
of cost saving measures implemented in 2020 offset by a lower
allocation to capital projects;
-- Exploration and evaluation assets of GBP10.1 million were
written off during the year primarily relating to PEDL 200 which
was relinquished during the year and the impairment of capitalised
decommissioning assets relating to previously written off licences
(H1 2020: nil). An impairment of GBPnil (H1 2020: GBP34.6 million)
was recognised on oil and gas assets during the period;
-- A loss was recognised on oil price derivatives of GBP5.4
million (H1 2020: GBP4.8 million gain) mainly due to lower hedged
prices and an increase in the Brent benchmark;
-- Decreased net finance costs of GBP1.8 million (H1 2020:
GBP3.4 million) due to gains on foreign exchange and a lower
unwinding of discount on provisions; and
-- A tax credit of GBP1.9 million (H1 2020: credit GBP8.1
million) principally due to movement in deferred tax relating to
the value of recognised tax losses available for offset against
future taxable profits and an increase in the tax rate
substantially enacted during the period for non-ring-fenced profits
to 25%.
Income statement
The Group recognised revenues of GBP16.6 million in the period
(H1 2020: GBP10.5 million). Group production in the period averaged
2,005 boepd (H1 2020: 1,940 boepd). Oil sales were 322,199 barrels
(excluding third party sales), with 7,112 Mwh of electricity and
1,247,946 therms of gas sold (H1 2020: 318,751 barrels; 4,411 Mwh
of electricity and 966,445 therms of gas sold). Revenues for the
period also included GBP0.4 million (H1 2020: GBP0.5 million)
relating to the sale of third party oil, the bulk of which is
processed through our gathering centre at Holybourne in the Weald
Basin.
The average realised price for the period pre-hedge (excluding
third party sales) was $63.4/bbl (H1 2020: $36.7/bbl) and post
hedge $51.6/bbl (H1 2020: $50.0/bbl). The average exchange rate for
the period was GBP1:$1.39 (H1 2020: GBP1:$1.28) which partially
offset the positive impact on revenues as a result of increased
prices compared to H1 2020.
Cost of sales for the period was GBP11.0 million (H1 2020:
GBP12.9 million) including depreciation, depletion and amortisation
(DD&A) of GBP2.4 million (H1 2020: GBP3.5 million), and
operating costs of GBP8.6 million (H1 2020: GBP9.3 million).
Operating costs include GBP0.4 million (H1 2020: GBP0.5 million) in
relation to processing third party oil. The net contribution
received from processing third party oil was GBPnil (H1 2020:
GBPnil). Operating costs were GBP0.7 million lower than the prior
period, due to lower transportation costs, lower rates and licence
fee costs and reduced staff costs as a result of the cost saving
measures implemented in 2020. These savings were partially offset
by increased workover activity and an increase in electricity
costs. Underlying operating costs per boe were GBP24.8 ($34.4),
excluding the cost of third party sales (H1 2020: GBP27.0
($34.5)).
Adjusted EBITDA in the period was GBP2.7 million (H1 2020:
GBP2.2 million). A gross profit of GBP5.6 million was recognised in
the period (H1 2020: loss of GBP2.4 million).
Administrative costs decreased by GBP0.5 million to GBP2.3
million (H1 2020: GBP2.8 million) principally due to lower staff
and office costs as a result of cost savings measures implemented
in 2020 partially offset by a lower allocation of costs to capital
projects.
Exploration costs written off in H1 2021 were GBP10.1 million
(H1 2020: GBPnil) primarily relating to PEDL 200 which was
relinquished during the year and the impairment of capitalised
decommissioning assets relating to previously written off licences.
As part of our ongoing active portfolio management we continually
review our acreage positions and will relinquish non-core or
uneconomic acreage.
Management has not identified any impairment indicators for oil
and gas assets for the period to 30 June 2021 (H1 2020: impairment
of GBP34.6 million). See note 10 for further details.
Net finance costs were GBP1.8 million in the period (H1 2020:
GBP3.4 million), including interest on borrowings of GBP0.6 million
(H1 2020: GBP0.7 million), unwinding of provisions discount GBP0.9
million (2020: GBP2.0 million) and a net foreign exchange gain of
GBP0.1 million (H1 2020: loss of GBP0.4 million). The net cost also
includes GBP0.3 million (H1 2020: GBP0.3 million) relating to the
finance charge on lease liabilities.
The Group recognised a tax credit of GBP1.9 million (H1 2020:
credit GBP8.1 million) during the period primarily due to movement
in deferred tax relating to the value of recognised tax losses
available for offset against future taxable profits and an increase
in the tax rate substantially enacted during the period for
non-ring fenced profits to 25%.
Cash flow
Net cash generated from operations before working capital
movements in the period amounted to GBP3.7 million (H1 2020: GBP1.9
million). The Group invested GBP2.6 million across its asset base
in the period (H1 2020: GBP4.9 million). GBP1.7 million (H1 2020:
GBP3.5 million) was invested in conventional assets, primarily on
the Scampton North waterflood, Welton water injection and other
projects to optimise existing facilities and systems, including
beam pump installations. GBP0.8 million (H1 2020: GBP1.4 million)
was invested primarily in working up additional exploration
opportunities on conventional assets.
IGas made a net drawdown of GBP1.4 million ($2.0 million) of
principal on borrowings under the RBL facility (H1 2020: net
repayment of GBP1.4 million ($2.0 million)) in accordance with the
terms of the facility.
IGas paid GBP0.5 million ($0.6 million) in interest (H1 2020:
GBP0.5 million ($0.6 million)). Repayment of obligations under
leases was GBP0.8 million (H1 2020: GBP1.6 million).
Cash and cash equivalents were GBP2.8 million at the end of the
period (31 December 2020: GBP2.4 million).
Balance sheet
Net assets were GBP61.9 million at 30 June 2021 (31 December
2020: GBP73.3 million). The decrease related primarily to the
write-off of exploration and evaluation assets.
Shareholder's equity decreased by GBP11.4 million to GBP61.9
million (31 December 2020: GBP73.3 million).
Non-IFRS measures
The Group uses non-IFRS measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. The non-IFRS measures include net debt,
adjusted EBITDA, underlying cash operating costs and operating cash
flow before working capital movements and realised hedges, which
are considered by the Company to be useful additional measures to
help understand underlying performance.
Net Debt
Net debt, being borrowings excluding capitalised fees less cash
and cash equivalents, increased to GBP13.2 million at 30 June 2021
(31 December 2020: GBP12.2 million; 30 June 2020: GBP11.2 million).
The Group's definition of net debt does not include the Group's
lease liabilities.
Six months Six months
ended ended Year ended
30 June 30 June 31 December
2021 2020 2020
GBPm GBPm GBPm
----------- ----------- ------------------
Debt (nominal value
excluding capitalised
expenses) (16.0) (13.8) (14.6)
----------- ----------- ------------------
Cash and cash equivalents 2.8 2.6 2.4
----------- ----------- ------------------
Net Debt (13.2) (11.2) (12.2)
----------- ----------- ------------------
Adjusted EBITDA
Lease costs for the period which have been capitalised under
IFRS 16 have been added to underlying cash operating costs and
deducted in the calculation of adjusted EBITDA to be consistent
with previous periods. Adjusted EBITDA includes adjustments in
relation to non-cash items such as share-based payment charges and
unrealised gain/loss on hedges along with other one-off exceptional
items after deducting lease rentals capitalised under IFRS 16.
Six months Six months Year ended
ended ended 31 December
30 June 30 June 2020
2021 2020
GBPm GBPm GBPm
----------- ----------- -------------
Loss before tax (14.2) (38.1) (44.1)
----------- ----------- -------------
Net finance costs 1.8 3.4 2.2
----------- ----------- -------------
Changes in fair value of
contingent consideration 0.2 - 0.2
----------- ----------- -------------
Depletion, depreciation
& amortisation 2.5 3.7 6.3
----------- ----------- -------------
Impairments/write-offs 10.1 34.6 38.6
----------- ----------- -------------
EBITDA 0.4 3.6 3.2
----------- ----------- -------------
Lease rentals capitalised
under IFRS 16 (0.8) (0.9) (1.8)
----------- ----------- -------------
Share-based payment charges 0.5 1.3 1.0
----------- ----------- -------------
Unrealised loss/(gain) on
hedges 2.6 (1.8) 0.8
----------- ----------- -------------
Redundancy costs - - 0.6
----------- ----------- -------------
Acquisition costs - - 0.2
----------- ----------- -------------
Adjusted EBITDA 2.7 2.2 4.0
----------- ----------- -------------
Underlying cash operating costs
Six months Six months Year ended
ended ended 31 December
30 June 30 June 2020
2021 2020
GBPm GBPm GBPm
----------- ----------- -------------
Other cost of sales 8.6 9.3 17.6
----------- ----------- -------------
Lease rentals capitalised
under IFRS 16 0.8 0.9 1.8
----------- ----------- -------------
Underlying cash operating
costs 9.4 10.2 19.4
----------- ----------- -------------
Operating cash flow before working capital movements and
realised hedges
Six months Six months Year ended
ended ended 31 December
30 June 30 June 2020
2021 2020
GBPm GBPm GBPm
----------- ----------- -------------
Operating cash flow before
working capital movements 3.7 1.9 3.3
----------- ----------- -------------
Realised (gain)/loss on
oil price derivatives 2.7 (3.3) (4.6)
----------- ----------- -------------
Operating cash flow before
working capital movements
and realised hedges 6.4 (1.4) (1.3)
----------- ----------- -------------
Principal risks and uncertainties
The Group constantly monitors the Group's risk exposures and
management reports to the Audit Committee and the Board on a
regular basis. The Audit Committee receives and reviews these
reports and focuses on ensuring that the effective systems of
internal financial and non-financial controls including the
management of risk are maintained. The results of this work are
reported to the Board which in turn performs its own review and
assessment.
The principal risks for the Group remain as previously detailed
on pages 22-23 of the 2020 Annual Report and Accounts and can be
summarised as:
-- Political risk such as change in Government or the effect of local or national referendums;
-- Strategy fails to meet shareholder expectations;
-- Climate change risks that causes changes to laws,
regulations, policies, obligations and social attitudes relating to
the transition to a lower carbon economy which could have a cost
impact or reduced demand for hydrocarbons for the Group and could
impact our Strategy;
-- Cyber security risk that gives exposure to a serious
cyber-attack which could affect the confidentiality of data, the
availability of critical business information and cause disruption
to our operations;
-- Planning, environmental, licensing and other permitting risks
associated with its operations and, in particular, with drilling
and production operations;
-- Oil or gas production, as no guarantee can be given that they
can be produced in the anticipated quantities from any or all of
the Group's assets or that oil or gas can be delivered
economically;
-- Development of shale gas resources not successful;
-- Loss of key staff;
-- Pandemic that impacts the ability to operate the business effectively;
-- Oil market price risk through variations in the wholesale
price in the context of the production from oil fields it owns and
operates;
-- Gas and electricity market price risk through variations in
the wholesale price in the context of its future unconventional
production volumes;
-- Exchange rate risk through both its major source of revenue
and its major borrowings being priced in US$ while most of the
Group's operating and G&A costs are denominated in UK pounds
sterling;
-- Liquidity risk through its operations; and
-- Capital risk resulting from its capital structure, including
operating within the covenants of its RBL facility.
Going concern
The Group continues to closely monitor and manage its liquidity
risks. Cash flow forecasts for the Group are regularly produced
based on, inter alia, the Group's production and expenditure
forecasts, management's best estimate of future oil prices,
management's best estimate of foreign exchange rates and the
Group's available loan facility under the RBL. Sensitivities are
run to reflect different scenarios including, but not limited to,
possible further reductions in commodity prices, strengthening of
sterling and reductions in forecast oil and gas production
rates.
The Group's operating cash flows have improved in 2021 as a
result of improving commodity prices and we have successfully
completed the 2021 half-year redetermination. However, the ability
of the Group to operate as a going concern is dependent upon the
continued availability of future cash flows and the availability of
the monies drawn under its RBL, which is redetermined semi-annually
based on various parameters (including oil price and level of
reserves) and is also dependent on the Group not breaching its RBL
covenants. To mitigate these risks, the Group benefits from its
hedging policy with 190,800 bbls hedged for H2 2021 at an average
price including collar upside of c.$49/bbl, 126,000 bbls are
currently hedged in 2022 using swaps at an average price of $63/bbl
and 114,000 bbls using puts with an average price, net of premiums,
of $44/bbl.
The international efforts to curtail the COVID-19 pandemic,
particularly the increasing vaccination roll-outs has created an
improving macroeconomic outlook. The combination of the recovery in
oil demand and OPEC+ decision on production levels has resulted in
higher oil prices which have increased from c.$54/bbl at the
beginning of the year to above $70/bbl in June 2021. Although the
oil price has recovered sharply, there remains significant
uncertainty as to how COVID-19 and its aftermath will impact
economies, oil demand and therefore oil price over the near and
mid-term.
Management has also considered the impact of the COVID-19 global
crisis on the Group's operations. We have seen some impact on
production during 2021 due to supply chain constraints and the need
for members of our staff to self-isolate. We continue to monitor
the situation closely and act within Government guidelines and have
a number of contingency plans in place should our operations be
significantly affected by the COVID-19 pandemic. Many of our sites
are remotely manned and we are well equipped as a business to
ensure we maintain business continuity recognising that our
production comes from a large number of wells in a variety of
locations and we have flexibility in our off-take arrangements. We
continue to liaise and co-operate with all the relevant regulators
on guidance relating to the pandemic.
The Group's base case cash flow forecast was run with average
oil prices of $68/bbl for Q4 2021 falling to an average of $63/bbl
in 2022 based on the forward curve. A foreign exchange rate of
$1.39/GBP1 for Q4 2021 and $1.38/GBP1 for 2022 was used. Our
forecasts show that the Group will have sufficient financial
headroom to meet its financial covenants based on the existing RBL
facility. However, given the uncertainties described above, the
level of Group revenues and the availability of facilities under
the RBL are inherently uncertain. As such, management has also
prepared a downside case with average oil prices at $58/bbl for Q4
2021 falling to an average of $50/bbl in 2022 and an exchange rate
of $1.40/GBP1.00 for Q4 2021 and $1.42/GBP1.00 for 2022. Our
downside case also included an average reduction in production of
5% over the period. To manage the impact of the downside scenario
modelled, management would take mitigating actions, including
further commodity hedging, delaying capital expenditure and
additional reductions in costs in order to remain within the
Group's debt liquidity covenants. All such mitigating actions are
within management's control. In the downside case, management has
also considered additional cash generating opportunities for the
Group. While management acknowledges that these may not be in our
control, we have assumed that cash flow from some of these
opportunities would be available in 2022. In this downside
scenario, our forecast shows that the Group will have sufficient
financial headroom to meet its financial covenants for the 12
months from the date of approval of the financial statements.
However, should oil price or demand (and therefore revenue) fall
further, the Group may not have sufficient funds available for 12
months from the date of approval of these financial statements.
As a result, at the date of approval of these interim financial
statements, there continues to be material uncertainties, as
described above, arising as a result of the potential impact of
COVID-19 on the Group's operational activities and future commodity
prices. These material uncertainties cast significant doubt upon
the Group's ability to continue as a going concern. Notwithstanding
these material uncertainties, the Directors have a reasonable
expectation that the Group has adequate resources to continue in
existence for the foreseeable future and have concluded it is
appropriate to adopt the going concern basis of accounting in the
preparation of the interim financial statements. The interim
financial statements do not include the adjustments that would
result if the Group was unable to continue as a going concern.
Statement of directors' responsibilities
The Directors confirm that these Condensed Interim Consolidated
Financial Statements have been prepared in accordance with
UK-adopted International Accounting Standard 34, 'Interim Financial
Reporting' ("IAS 34") and the AIM Rules for Companies; and these
Unaudited Interim results include:
a) a fair review of the information required (i.e., an
indication of important events and their impact and a description
of the principal risks and uncertainties for the remaining six
months of the financial year); and
b) a fair review of the information required on related party transactions.
By order of the Board,
Stephen Bowler
Chief Executive Officer
22 September 2021
Independent review report to IGas Energy plc
Report on the condensed interim consolidated financial
statements
Our conclusion
We have reviewed IGas Energy plc's condensed interim
consolidated financial statements (the "interim financial
statements") in the Unaudited Interim results of IGas Energy plc
for the 6-month period ended 30 June 2021 (the "period").
Based on our review, nothing has come to our attention that
causes us to believe that the interim financial statements are not
prepared, in all material respects, in accordance with UK adopted
International Accounting Standard 34, 'Interim Financial Reporting'
and the AIM Rules for Companies.
Emphasis of matter
Without modifying our conclusion on the interim financial
statements, we have considered the adequacy of the disclosure made
in note 2 to the interim financial statements concerning the
Group's ability to continue as a going concern. The ability of the
Group to operate as a going concern is dependent upon the continued
availability of future cash flows, the availability of the monies
drawn under its Reserve Based Lending facility ('RBL'), which is
redetermined semi-annually based on various parameters (including
oil price and level of reserves), and on the Group not breaching
its RBL covenants. The Group's cash flows and the ability to meet
its covenants could be impacted by a return to lower oil prices,
the impact of further COVID-19 restrictions and the ability of
management to implement mitigating actions which are not completely
within their control. These conditions, along with the other
matters explained in note 2 to the interim financial statements,
indicate the existence of material uncertainties which may cast
significant doubt upon the Group's ability to continue as a going
concern. The Group's interim financial statements do not include
the adjustments that would result if the Group was unable to
continue as a going concern.
What we have reviewed
The interim financial statements comprise:
-- the Condensed Interim Consolidated Balance Sheet as at 30 June 2021;
-- the Condensed Interim Consolidated Income Statement for the period then ended;
-- the Condensed Interim Consolidated Statement of Comprehensive
Income for the period then ended;
-- the Condensed Interim Consolidated Cash Flow Statement for the period then ended;
-- the Condensed Interim Consolidated Statement of Changes in
Equity for the period then ended; and
-- the explanatory notes to the interim financial statements.
The interim financial statements included in the Unaudited
Interim results of IGas Energy plc have been prepared in accordance
with UK adopted International Accounting Standard 34, 'Interim
Financial Reporting' and the AIM Rules for Companies.
Responsibilities for the interim financial statements and the
review
Our responsibilities and those of the directors
The Unaudited Interim results, including the interim financial
statements, is the responsibility of, and has been approved by the
directors. The directors are responsible for preparing the
Unaudited Interim results in accordance with the AIM Rules for
Companies which require that the financial information must be
presented and prepared in a form consistent with that which will be
adopted in the company's annual financial statements.
Our responsibility is to express a conclusion on the interim
financial statements in the Unaudited Interim results based on our
review. This report, including the conclusion, has been prepared
for and only for the Company for the purpose of complying with the
AIM Rules for Companies and for no other purpose. We do not, in
giving this conclusion, accept or assume responsibility for any
other purpose or to any other person to whom this report is shown
or into whose hands it may come save where expressly agreed by our
prior consent in writing.
What a review of interim financial statements involves
We conducted our review in accordance with International
Standard on Review Engagements (UK and Ireland) 2410, 'Review of
Interim Financial Information Performed by the Independent Auditor
of the Entity' issued by the Auditing Practices Board for use in
the United Kingdom. A review of interim financial information
consists of making enquiries, primarily of persons responsible for
financial and accounting matters, and applying analytical and other
review procedures.
A review is substantially less in scope than an audit conducted
in accordance with International Standards on Auditing (UK) and,
consequently, does not enable us to obtain assurance that we would
become aware of all significant matters that might be identified in
an audit. Accordingly, we do not express an audit opinion.
We have read the other information contained in the Unaudited
Interim results and considered whether it contains any apparent
misstatements or material inconsistencies with the information in
the interim financial statements.
PricewaterhouseCoopers LLP
Chartered Accountants
London
22 September 2021
Condensed Interim Consolidated Income Statement
Unaudited Unaudited Audited
6 months 6 months year ended
ended ended 31 December
30 June 30 June 2020
2021 2020 GBP000
Notes GBP000 GBP000
-------------------------------------------- ----- --------- --------- -------------
Revenue 4 16,574 10,476 21,578
Cost of sales
Depletion, depreciation and amortisation (2,379) (3,539) (5,974)
Other costs of sales (8,608) (9,340) (17,553)
-------------------------------------------- ----- --------- --------- -------------
Total cost of sales (10,987) (12,879) (23,527)
Gross profit/(loss) 5,587 (2,403) (1,949)
Administrative expenses (2,314) (2,793) (5,331)
Exploration and evaluation assets written
off 9 (10,097) (5) (67)
Oil and gas assets impairment 10 - (34,607) (38,535)
(Loss)/gain on oil price derivatives (5,370) 4,840 3,520
(Loss)/gain on foreign exchange contracts - 310 229
Operating loss (12,194) (34,658) (42,133)
Finance income 5 135 7 1,472
Finance costs 5 (1,893) (3,409) (3,648)
Changes in fair value of contingent
consideration 12 (230) - (180)
Other income - - 415
Loss from continuing activities before
tax (14,182) (38,060) (44,074)
Income tax credit 6 1,942 8,095 1,985
-------------------------------------------- ----- --------- --------- -------------
Loss after tax from continuing operations
attributable to shareholders' equity (12,240) (29,965) (42,089)
Loss after tax from discontinued operations 7 (106) (10,896) (11,060)
-------------------------------------------- ----- --------- --------- -------------
Net loss for the period/year attributable
to shareholders' equity (12,346) (40,861) (53,149)
-------------------------------------------- ----- --------- --------- -------------
Loss attributable to equity shareholders
from continuing operations:
Basic loss per share 8 (9.78p) (24.58p) (34.35p)
Diluted loss per share 8 (9.78p) (24.58p) (34.35p)
-------------------------------------------- ----- --------- --------- -------------
Loss attributable to equity shareholders
including discontinued operations:
Basic loss per share 8 (9.87p) (33.52p) (43.37p)
Diluted loss per share 8 (9.87p) (33.52p) (43.37p)
-------------------------------------------- ----- --------- --------- -------------
Condensed Interim Consolidated Statement of Comprehensive
Income
Unaudited Unaudited Audited
6 months 6 months year ended
ended ended 31 December
30 June 30 June 2020
2021 2020 GBP000
GBP000 GBP000
--------------------------------------------- --------- --------- -------------
Loss for the period/year (12,346) (40,861) (53,149)
Other comprehensive income/(loss) for the
period/year:
Currency translation adjustments recycled
to the income statement (note 7) 326 10,781 10,781
Currency translation adjustments - (67) (19)
--------------------------------------------- --------- --------- -------------
Total comprehensive loss for the period/year (12,020) (30,147) (42,387)
--------------------------------------------- --------- --------- -------------
Condensed Interim Consolidated Balance Sheet
Unaudited Unaudited Audited
at 30 June at 30 June at 31December
2021 2020 2020
Notes GBP000 GBP000 GBP000
------------------------------------- ----- ----------- ------------ --------------
Assets
Non-current assets
Intangible assets 9 37,661 42,399 46,711
Property, plant and equipment 10 73,264 69,348 72,439
Right-of-use assets 7,458 7,694 7,658
Restricted cash 410 410 410
Deferred tax asset 6 33,888 38,056 31,945
152,681 157,907 159,163
------------------------------------- ----- ----------- ------------ --------------
Current assets
Inventories 1,094 1,106 1,023
Trade and other receivables 5,289 3,973 4,095
Cash and cash equivalents 13 2,755 2,592 2,438
Derivative financial instruments - 1,704 314
9,138 9,375 7,870
------------------------------------- ----- ----------- ------------ --------------
Total assets 161,819 167,282 167,033
------------------------------------- ----- ----------- ------------ --------------
Liabilities
Current liabilities
Trade and other payables (4,588) (5,245) (5,247)
Derivative financial instruments (3,897) - (1,271)
Lease liabilities (720) (979) (694)
Provisions 12 (358) - (293)
(9,563) (6,224) (7,505)
------------------------------------- ----- ----------- ------------ --------------
Non-current liabilities
Borrowings 13 (15,123) (12,650) (13,695)
Other creditors (970) (1,358) (1,160)
Lease liabilities (6,667) (6,394) (6,820)
Provisions 12 (67,591) (56,263) (64,550)
(90,351) (76,665) (86,225)
Total liabilities (99,914) (82,889) (93,730)
------------------------------------- ----- ----------- ------------ --------------
Net assets 61,905 84,393 73,303
------------------------------------- ----- ----------- ------------ --------------
Equity
Capital and reserves
Called up share capital 14 30,333 30,333 30,333
Share premium account 14 102,969 102,741 102,906
Foreign currency translation reserve 3,799 3,425 3,473
Other reserves 35,676 34,150 35,117
Accumulated deficit (110,872) (86,256) (98,526)
------------------------------------- ----- ----------- ------------ --------------
Total equity 61,905 84,393 73,303
------------------------------------- ----- ----------- ------------ --------------
Condensed Interim Consolidated Statement of Changes in
Equity
Foreign
currency
Called translation
up Share reserve*
share premium GBP000 Other Accumulated Total
capital account reserves** deficit Equity
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
--------------------------------- -------- -------- ------------- ----------- ----------- --------
At 31 December 2019 (audited) 30,333 102,680 (7,289) 32,781 (45,395) 113,110
Loss for the period - - - - (40,861) (40,861)
Share options issued under the
employee share plan - - - 1,369 - 1,369
Issue of shares (note 14) - 61 - - - 61
Currency translation adjustments - - 10,714 - - 10,714
--------------------------------- -------- -------- ------------- ----------- ----------- --------
At 30 June 2020 (unaudited) 30,333 102,741 3,425 34,150 (86,256) 84,393
Loss for the period - - - - (12,288) (12,288)
--------------------------------- -------- -------- ------------- ----------- ----------- --------
Share options issued under the
employee share plan - - - 997 - 997
Issue of shares (note 14) - 165 - (30) - 135
Disposal of shares held in EBT - - - - 18 18
Currency translation adjustments - - 48 - - 48
--------------------------------- -------- -------- ------------- ----------- ----------- --------
At 31 December 2020 (audited) 30,333 102,906 3,473 35,117 (98,526) 73,303
Loss for the period - - - - (12,346) (12,346)
Share options issued under the
employee share plan - - - 559 - 559
Issue of shares (note 14) - 63 - - - 63
Currency translation adjustments - - 326 - - 326
--------------------------------- -------- -------- ------------- ----------- ----------- --------
At 30 June 2021 (unaudited) 30,333 102,969 3,799 35,676 (110,872) 61,905
--------------------------------- -------- -------- ------------- ----------- ----------- --------
* The foreign currency translation reserve represents exchange
gains and losses arising on translation of foreign currency
subsidiaries net assets and results, and on translation of those
subsidiaries intercompany balances which form part of the net
investment of the Group.
** Other reserves include: 1) EIP/MRP/LTIP/VCP/EDRP reserves
which represent the cost of share options issued under the long
term incentive plans; 2) share investment plan reserve which
represents the cost of the partnership and matching shares; 3)
treasury shares reserve which represents the cost of shares in IGas
Energy plc purchased in the market and held by the IGas Employee
Benefit Trust to satisfy awards held under the Group incentive
plans; and 4) capital contribution reserve which arose following
the acquisition of IGas Exploration UK Limited.
Condensed Interim Consolidated Cash Flow Statement
Notes Unaudited Unaudited Audited
6 Months 6 Months year
ended ended ended
30 June 30 June 31 December
2021 2020 2020
GBP000 GBP000 GBP000
Cash flows from operating activities:
Loss from continuing activities before
tax for the period/year (14,182) (38,060) (44,074)
Depletion, depreciation and amortisation 2,475 3,702 6,303
Abandonment costs/other provisions utilised (122) (863) (1,348)
Share-based payment charge 467 921 1,025
Exploration and evaluation assets written-off 9 10,097 5 67
Oil and gas assets impairment - 34,607 38,535
Change in unrealised loss/(gain) on oil
price derivatives 2,626 (1,533) 1,048
Change in unrealised loss(gain) on foreign
exchange contracts 314 (310) (229)
Changes in fair value of contingent consideration 12 230 - 180
Other income - - (415)
Finance income 5 (135) (7) (1,472)
Finance costs 5 1,893 3,409 3,648
Other non-cash adjustments (1) 3 (10)
Operating cash flow before working capital
movements 3,662 1,874 3,258
(Increase)/decrease in trade and other
receivables and other financial assets (1,103) 2,675 1,514
Decrease/(increase) in trade and other
payables 352 (2,199) (1,187)
(Increase)/decrease in inventories (71) 87 170
Cash from continuing operating activities 2,840 2,437 3,755
--------------------------------------------------- ------ ---------- ---------- -------------
Cash used in discontinued operating activities (124) (168) (156)
--------------------------------------------------- ------ ---------- ---------- -------------
Net cash from operating activities 2,716 2,269 3,599
--------------------------------------------------- ------ ---------- ---------- -------------
Cash flows from investing activities:
Purchase of intangible exploration and
evaluation assets (794) (1,407) (2,314)
Purchase of property, plant and equipment (1,743) (3,500) (6,152)
Purchase of intangible development assets (35) - (67)
Cash acquired on acquisition of subsidiary - - 77
Other income received - - 4
Interest received 5 7 11
--------------------------------------------------- ------ ---------- ---------- -------------
Cash used in continuing investing activities (2,567) (4,900) (8,441)
Net cash used in investing activities (2,567) (4,900) (8,441)
--------------------------------------------------- ------ ---------- ---------- -------------
Cash flows from financing activities:
Cash proceeds from issue of ordinary
share capital 14 21 31 56
Proceeds from disposal of shares held
in EBT net of costs - - 4
Drawdown on Reserves Based Lending facility 13 1,432 3,215 5,544
Repayment on Reserves Based Lending facility 13 - (4,645) (4,645)
Repayment of principal portion of lease
liability (484) (1,265) (973)
Repayment of interest on lease liabilities (340) (320) (795)
Interest paid 13 (454) (477) (940)
Net cash from/(used in) financing activities 175 (3,461) (1,749)
--------------------------------------------------- ------ ---------- ---------- -------------
Net increase/(decrease) in cash and
cash equivalents during the period /year 324 (6,092) (6,591)
Net foreign exchange difference (7) 490 835
Cash and cash equivalents at the beginning
of the period /year 2,438 8,194 8,194
---------------------------------------------------
Cash and cash equivalents at the end
of the period /year 13 2,755 2,592 2,438
--------------------------------------------------- ------ ---------- ---------- -------------
Notes to the Condensed Interim Consolidated Financial
Statements
1 Corporate information
The condensed interim consolidated financial statements of the
Group for the six months ended 30 June 2021, which are unaudited,
were authorised for issue in accordance with a resolution of the
Directors on 22 September 2021.
IGas Energy plc is a public limited company incorporated and
domiciled in England whose shares are publicly traded on the AIM
market. The Group's principal activity is exploring for,
appraising, developing and producing oil and gas resources in Great
Britain. The Group is also diversifying into the wider UK energy
markets and is appraising geothermal and hydrogen projects.
2 Accounting policies
Basis of preparation
These condensed interim consolidated financial statements for
the six months ended 30 June 2021 have been prepared in accordance
with UK-adopted International Accounting Standard 34, 'Interim
Financial Reporting' ("IAS 34") and the AIM Rules for Companies.
The unaudited condensed interim consolidated financial statements
should be read in conjunction with the consolidated financial
statements for the year ended 31 December 2020, which have been
prepared in accordance with international accounting standards in
conformity with the requirements of the Companies Act 2006 and IFRS
adopted pursuant to Regulation (EC) No 1606/2002 as it applies in
the European Union.
The financial information contained in this document does not
constitute statutory accounts as defined by Section 435 of the
Companies Act 2006 (England & Wales). The financial information
as at 31 December 2020 is based on the statutory accounts for the
year ended 31 December 2020. A copy of the statutory accounts for
that year, has been delivered to the Register of Companies and is
available on the Company's website at www.igasplc.com. The
auditors' report in accordance with Chapter 3 Part 16 of the
Companies Act 2006 in relation to those accounts was unqualified
and did not contain any matters on which the auditors are required
to report an exception in accordance with section 498 (2) and (3)
of the Companies Act 2006.
The accounting policies adopted are consistent with those of the
previous financial year and corresponding interim reporting period,
except for the new and amended standards and interpretations
discussed below.
In the year to 31 December 2021 the annual financial statements
will be prepared in accordance with IFRS as adopted by the UK
Endorsement Board and that this change in basis of preparation is
required by UK company law for the purposes of financial reporting
as a result of the UK's exit from the EU on 31 January 2020 and the
cessation of the transition period on 31 December 2020.
This change does not constitute a change in accounting policy
but rather a change in framework which is required to ground the
use of IFRS in company law. There is no impact on recognition,
measurement or disclosure between the two frameworks in the period
reported.
Going concern
The Group continues to closely monitor and manage its liquidity
risks. Cash flow forecasts for the Group are regularly produced
based on, inter alia, the Group's production and expenditure
forecasts, management's best estimate of future oil prices,
management's best estimate of foreign exchange rates and the
Group's available loan facility under the RBL. Sensitivities are
run to reflect different scenarios including, but not limited to,
possible further reductions in commodity prices, strengthening of
sterling and reductions in forecast oil and gas production
rates.
The Group's operating cash flows have improved in 2021 as a
result of improving commodity prices and we have successfully
completed the 2021 half-year redetermination. However, the ability
of the Group to operate as a going concern is dependent upon the
continued availability of future cash flows and the availability of
the monies drawn under its RBL, which is redetermined semi-annually
based on various parameters (including oil price and level of
reserves) and is also dependent on the Group not breaching its RBL
covenants. To mitigate these risks, the Group benefits from its
hedging policy with 190,800 bbls hedged for H2 2021 at an average
price including collar upside of c.$49/bbl, 126,000 bbls are
currently hedged in 2022 using swaps at an average price of $63/bbl
and 114,000 bbls using puts with an average price, net of premiums,
of $44/bbl.
The international efforts to curtail the COVID-19 pandemic,
particularly the increasing vaccination roll-outs has created an
improving macroeconomic outlook. The combination of the recovery in
oil demand and OPEC+ decision on production levels has resulted in
higher oil prices which have increased from c.$54/bbl at the
beginning of the year to above $70/bbl in June 2021. Although the
oil price has recovered sharply, there remains significant
uncertainty as to how COVID-19 and its aftermath will impact
economies, oil demand and therefore oil price over the near and
mid-term.
Management has also considered the impact of the COVID-19 global
crisis on the Group's operations. We have seen some impact on
production during 2021 due to supply chain constraints and the need
for members of our staff to self-isolate. We continue to monitor
the situation closely and act within Government guidelines and have
a number of contingency plans in place should our operations be
significantly affected by the COVID-19 pandemic. Many of our sites
are remotely manned and we are well equipped as a business to
ensure we maintain business continuity recognising that our
production comes from a large number of wells in a variety of
locations and we have flexibility in our off-take arrangements. We
continue to liaise and co-operate with all the relevant regulators
on guidance relating to the pandemic.
The Group's base case cash flow forecast was run with average
oil prices of $68/bbl for Q4 2021 falling to an average of $63/bbl
in 2022 based on the forward curve. A foreign exchange rate of
$1.39/GBP1 for Q4 2021 and $1.38/GBP1 for 2022 was used. Our
forecasts show that the Group will have sufficient financial
headroom to meet its financial covenants based on the existing RBL
facility. However, given the uncertainties described above, the
level of Group revenues and the availability of facilities under
the RBL are inherently uncertain. As such, management has also
prepared a downside case with average oil prices at $58/bbl for Q4
2021 falling to an average of $50/bbl in 2022 and an exchange rate
of $1.40/GBP1.00 for Q4 2021 and $1.42/GBP1.00 for 2022. Our
downside case also included an average reduction in production of
5% over the period. To manage the impact of the downside scenario
modelled, management would take mitigating actions, including
further commodity hedging, delaying capital expenditure and
additional reductions in costs in order to remain within the
Group's debt liquidity covenants. All such mitigating actions are
within management's control. In the downside case, management has
also considered additional cash generating opportunities for the
Group. While management acknowledges that these may not be in our
control, we have assumed that cash flow from some of these
opportunities would be available in 2022. In this downside
scenario, our forecast shows that the Group will have sufficient
financial headroom to meet its financial covenants for the 12
months from the date of approval of the financial statements.
However, should oil price or demand (and therefore revenue) fall
further, the Group may not have sufficient funds available for 12
months from the date of approval of these financial statements.
As a result, at the date of approval of these interim financial
statements, there continues to be material uncertainties, as
described above, arising as a result of the potential impact of
COVID-19 on the Group's operational activities and future commodity
prices. These material uncertainties cast significant doubt upon
the Group's ability to continue as a going concern. Notwithstanding
these material uncertainties, the Directors have a reasonable
expectation that the Group has adequate resources to continue in
existence for the foreseeable future and have concluded it is
appropriate to adopt the going concern basis of accounting in the
preparation of the interim financial statements. The interim
financial statements do not include the adjustments that would
result if the Group was unable to continue as a going concern.
New and amended standards and interpretations
During the period, the Group adopted the following new and
amended IFRSs for the first time for their reporting period
commencing 1 January 2021:
Amendments to IFRS 9, IAS 39, Interest Rate Benchmark Reform - Phase
IFRS 7, IFRS 4 and IFRS 16 2
These standards do not have a material impact on the Group in
the current or future reporting periods. There are no other
standards that are not yet effective and that would be expected to
have a material impact on the entity in the current or future
reporting periods.
Estimates and judgements
The preparation of the condensed interim consolidated financial
statements requires management to make judgements, estimates and
assumptions that affect the application of accounting policies and
the reported amounts of assets and liabilities, income and expense.
Actual results may differ from these estimates.
In preparing these condensed interim consolidated financial
statements, the significant judgements made by management in
applying the Group's accounting policies and the key sources of
estimation uncertainty were the same as those applied to the
consolidated financial statements for the year ended 31 December
2020.
Financial risk management
The Group's activities expose it to a variety of financial
risks; market risk (including interest rate, commodity price and
foreign currency risks), credit risk and liquidity risk.
The condensed interim consolidated financial statements do not
include all financial risk management information and disclosures
required in the annual financial statements; they should be read in
conjunction with the Group's annual financial statements as at 31
December 2020.
3 Basis of consolidation
The condensed interim consolidated financial statements present
the results of IGas Energy plc and its subsidiaries as if they
formed a single entity. The financial information of subsidiaries
used in the preparation of these condensed interim consolidated
financial statements are based on consistent accounting policies to
those of the parent. All intercompany transactions and balances
between Group companies, including unrealised profits/losses
arising from them, are eliminated in full. Where shares are issued
to an Employee Benefit Trust, and the Company is the sponsoring
entity, it is treated as an extension of the entity.
4 Revenue
The Group derives revenue solely within the United Kingdom from
the transfer of goods and services to external customers which is
recognised at a point in time when the performance obligation has
been satisfied by the transfer of goods. The Group's major product
lines are:
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2021 2020 2020
GBP000 GBP000 GBP000
------------------------------ ----------- ---------- -------------
Oil sales 15,284 10,048 20,546
Electricity sales 550 181 438
Gas sales 740 247 594
------------------------------ ----------- ---------- -------------
Revenue for the period /year 16,574 10,476 21,578
------------------------------ ----------- ---------- -------------
5 Finance income and costs
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2021 2020 2020
GBP000 GBP000 GBP000
--------------------------------------------------- ----------- ---------- -------------
Finance income:
Interest on short-term deposits 1 7 11
Foreign exchange gains 134 - 1,461
Finance income for the period /year 135 7 1,472
--------------------------------------------------- ----------- ---------- -------------
Finance expense:
Interest on borrowings (448) (477) (940)
Amortisation of finance fees on borrowings (165) (225) (387)
Foreign exchange loss - (361) -
Unwinding of discount on decommissioning
provisions (note 12) (811) (2,026) (1,466)
Unwinding of discount on contingent consideration
(note 12) (129) - (60)
Finance charge on lease liability for assets
in use (340) (320) (795)
--------------------------------------------------- ----------- ---------- -------------
Finance expense for the period /year (1,893) (3,409) (3,648)
--------------------------------------------------- ----------- ---------- -------------
6 Tax on profit on ordinary activities
The Group calculates the period income tax expense using the UK
corporation tax rate that would be applicable to expected total
annual earnings (40% for UK ring fenced activities and 19% for all
other UK activities). The effective tax rate for the period is 13%
(six months ended 30 June 2020: 21%, year ended 31 December 2020:
5%) and the major components of income tax expense in the condensed
interim consolidated income statement are:
Unaudited Unaudited
6 months 6 months Audited
ended ended year ended
30 June 30 June 31 December
2021 2020 2020
GBP000 GBP000 GBP000
-------------------------------------------- ---------- --------- -------------
UK corporation tax
Charge on loss for the period/year - - -
Total current tax charge - - -
-------------------------------------------- ---------- --------- -------------
Deferred tax
Charge/(credit) relating to the origination
or reversal of temporary differences (1,526) (7,998) 1,409
Credit due to tax rate changes (416) (97) (99)
Credit in relation to prior periods - - (3,295)
Total deferred tax credit (1,942) (8,095) (1,985)
-------------------------------------------- ---------- --------- -------------
Tax credit on loss on ordinary activities
for the period/year (1,942) (8,095) (1,985)
-------------------------------------------- ---------- --------- -------------
Changes to the UK corporation tax rates were substantively
enacted in the current period where the rate of tax will increase
to 25% from 1 April 2023. A deferred tax asset of GBP33.9 million
(30 June 2020: GBP38.1 million, 31 December 2020: GBP31.9 million)
has been recognised in respect of tax losses and other temporary
differences where the Directors believe that it is probable that
these assets will be recovered based on estimated taxable profit
forecast.
7 Loss after tax from discontinued operations
The divestment of assets acquired as part of the Dart
Acquisition, namely the Rest of the World segment, was completed in
2016. The Group still has a presence in a small number of
Australian, Indian and Singaporean registered operations and
continues to progress its plans to exit all legal jurisdictions in
the near future. During the current period, we have commenced the
liquidation process for the remaining of these overseas dormant
subsidiaries and control over these entities has been transferred
to the administrators. The total loss after tax in respect of
discontinued operations was GBP0.1 million primarily due to the
recycling of the currency translation reserve on liquidation/strike
off (six months ended 30 June 2020: loss after tax of GBP10.9
million; year ended 31 December 2020: loss after tax of GBP11.1
million, primarily relating to administration costs).
Effect of liquidation/strike off on the financial
statements:
Unaudited Unaudited
6 months 6 months Audited
ended ended year ended
30 June 30 June 31 December
2021 2020 2020
GBP000 GBP000 GBP000
-------------------------------------------- -------------- -------------- -------------
Other receivables (10) (1) 2
Cash and cash equivalents (20) (9) (9)
Other payables 15 56 56
Net assets and liabilities disposed (15) 46 49
-------------------------------------------- -------------- -------------- -------------
Disposal consideration - - -
-------------------------------------------- -------------- -------------- -------------
Translation reserve re-classification to
income statement on liquidation/strike off (326) (10,781) (10,781)
Loss on liquidation/strike off charged to
the income statement (341) (10,735) (10,732)
-------------------------------------------- -------------- -------------- -------------
8 Earnings per share (EPS)
Basic EPS amounts are based on the loss for the period after
taxation attributable to ordinary equity holders of the parent of
GBP12.2 million (six months ended 30 June 2020: a loss after tax of
GBP30.0 million; year ended 31 December 2020: a loss after tax of
GBP42.1 million) and the weighted average number of ordinary shares
outstanding during the period of 125.1 million (six months ended 30
June 2020: 121.9 million; year ended 31 December 2020: 122.5
million).
Diluted EPS amounts are based on the loss for the period after
taxation attributable to the ordinary equity holders of the parent
and the weighted average number of shares outstanding during the
period plus the weighted average number of ordinary shares that
would be issued on the conversion of all the potentially dilutive
ordinary shares into ordinary shares, except where these are
anti-dilutive.
There are 11.7 million potentially dilutive employee share
options (six months ended 30 June 2020: 12.0 million, year ended 31
December 2020: 10.9 million) which are not included in the
calculation of diluted earnings per share in the current period as
their conversion to ordinary shares would have decreased the loss
per share.
9 Intangible assets
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2021 30 June 2020 31 December 2020
GBP'000 GBP'000 GBP'000
------------------------------------- ----------------------------------- -------------------------------------
Exploration Exploration Exploration
and and and
evaluation Development evaluation Development evaluation Development
assets costs Total assets costs Total assets costs Total
----------------- ------------ ------------ --------- ------------ ------------ ------- ------------ ------------ -------
Cost
At 1 January 43,421 3,290 46,711 41,455 - 41,455 41,455 - 41,455
Acquisitions - - - - - - - 3,223 3,223
Additions 621 38 659 949 - 949 2,090 67 2,157
Changes in
decommissioning
(note 12) 388 - 388 - - - (57) - (57)
Amounts written
off (10,097) - (10,097) (5) - (5) (67) - (67)
At 30 June/
31 December 34,333 3,328 37,661 42,399 - 42,399 43,421 3,290 46,711
----------------- ------------ ------------ --------- ------------ ------------ ------- ------------ ------------ -------
Exploration and evaluation assets
Exploration costs written off in the period to 30 June 2021 were
GBP10.1 million (6 months to 30 June 2020: GBPnil, year ended 31
December 2020: GBP0.1 million) of which GBP10.0 million related to
the PEDL 200 (Tinker Lane) licence and GBP0.1 million impairment of
capitalised decommissioning assets relating to previously written
off licences. PEDL 200, the licence in which the basin edge
defining well Tinker Lane was drilled, and EXL 288 have been
relinquished during the period. This allows the group to focus on
its core Gainsborough Trough shale acreage, defined as those
licences in which a significant thickness of the Gainsborough shale
is, or is predicted, to be present.
Further analysis by location of asset is as follows:
North West: The group has GBP6.3 million (H1 2020: GBP6.1
million, year ended 31 December 2020: GBP6.1 million) of
capitalised exploration expenditure relating to Ellesmere Port
where IGas has lodged an appeal against the decision made by
Cheshire West and Chester Council's Planning and Licensing
Committee to refuse planning consent for routine tests on a rock
formation encountered in the Ellesmere Port-1 well. The appeal has
been recovered by the Secretary of State and we are awaiting the
outcome. As the outcome is still undetermined, it is appropriate to
keep the carrying value of the asset capitalised.
East Midlands: The group has GBP23.1 million (H1 2020: GBP32.3
million, year ended 31 December 2020: GBP32.8 million) of
capitalised exploration expenditure relating to our core area in
the Gainsborough Trough which includes PEDLs 12, 139, 140, 169 and
210. The Gainsborough Trough is an area with significant shale
potential. Following the moratorium on fracking, we continue to
work with the OGA, BEIS and No 10 Policy Unit to demonstrate that
we can develop shale in this area in a safe manner. Our discussions
have focused on the new science that would be brought forward on a
sector wide and site specific basis that would allow the moratorium
to be lifted. We are doing this in conjunction with our joint
venture partners and the work is ongoing at present. As the work is
still ongoing, it is appropriate to keep the carrying value of the
asset capitalised.
Conventional assets: The Group has GBP4.9 million (six months
ended 30 June 2020: GBP4.0 million, year ended 31 December 2020:
GBP4.5 million) of capitalised exploration expenditure which
relates to our conventional assets including PEDL 235 and PL
240.
Development costs
The development costs relate to assets acquired as part of the
GT Energy acquisition in 2020. The costs relate to the design and
development of deep geothermal heat projects in the United Kingdom,
with the principal project being at Etruria Valley,
Stoke-on-Trent.
The Group reviewed the carrying value of development costs as at
30 June 2021 and assessed it for impairment indicators. Principally
due to COVID-19, the development of the Stoke-on-Trent project has
taken longer than anticipated. This, however, does not impact the
overall economics of the project materially. On this basis, the
group has concluded that there are no impairment indicators as at
30 June 2021. No impairment was required for the period ( year
ended 31 December 2020 : GBPnil).
10 Property, plant and equipment
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2021 30 June 2020 31 December 2020
GBP'000 GBP'000 GBP'000
---------------------------- ---------------------------- ----------------------------
Oil Oil Oil
and Other and Other and Other
gas fixed gas fixed gas fixed
assets assets Total assets assets Total assets assets Total
---------------------- -------- -------- -------- -------- -------- -------- ------------ -------- --------
Cost
At 1 January 209,225 2,951 212,176 197,875 3,660 201,535 197,875 3,660 201,535
Additions 1,152 - 1,152 2,465 3 2,468 5,212 1 5,213
Disposals - (518) (518) (21) - (21) (117) (710) (827)
Changes in
decommissioning
(note 12) 1,591 - 1,591 - - - 6,255 - 6,255
At 30 June/ 31
December 211,968 2,433 214,401 200,319 3,663 203,982 209,225 2,951 212,176
---------------------- -------- -------- -------- -------- -------- -------- ------------ -------- --------
Depreciation and
Impairment
At 1 January 138,233 1,504 139,737 94,940 2,063 97,003 94,940 2,063 97,003
Charge for the
period/year 1,879 39 1,918 2,955 90 3,045 4,875 151 5,026
Disposals - (518) (518) (21) - (21) (117) (710) (827)
Impairment - - - 34,607 - 34,607 38,535 - 38,535
At 30 June/ 31
December 140,112 1,025 141,137 132,481 2,153 134,634 138,233 1,504 139,737
---------------------- -------- -------- -------- -------- -------- -------- ------------ -------- --------
Net book value at
30 June/ 31 December 71,856 1,408 73,264 67,838 1,510 69,348 70,992 1,447 72,439
---------------------- -------- -------- -------- -------- -------- -------- ------------ -------- --------
The Group reviewed the carrying value of oil and gas assets as
at 30 June 2021 and assessed it for impairment and impairment
reversal indicators. The strong pricing along the forward curve and
an improving economic outlook has improved the oil price
environment and other key assumptions underpinning the recoverable
value of oil and gas assets have not moved materially since 31
December 2020. On this basis, the group has concluded that there
are no impairment indicators as at 30 June 2021 (six months ended
30 June 2020: GBP34.6 million impairment; year ended 31 December
2020: GBP38.5 million impairment). However, continued uncertainty
exists as a result of the COVID-19 pandemic and its related impact
on the demand for oil, as a result, the group has concluded that
there are no impairment reversal indicators as at 30 June 2021.
11 Financial Instruments - fair value disclosure
The Group uses the following hierarchy for determining and
disclosing the fair value of the financial instruments by valuation
technique:
-- Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities;
-- Level 2: other valuation techniques for which all inputs
which have a significant effect on the recorded fair value are
observable, either directly or indirectly; and
-- Level 3: valuation techniques which use inputs which have a
significant effect on the recorded fair value that are not based on
observable market data.
There are no non-recurring fair value measurements nor have
there been any transfers between levels of the fair value
hierarchy.
The financial assets and liabilities measured at fair value are
categorised into the fair value hierarchy as at the reporting dates
as follows:
Level Unaudited Unaudited
6 months 6 months Audited
ended ended year ended
30 June 30 June 31 December
2021 2020 2020
GBP'000 GBP'000 GBP'000
----------------------------------- ------ ---------- ---------- ------------
Financial assets:
Derivative financial instruments -
oil hedges 2 - 1,309 -
Derivative financial instruments -
foreign exchange contracts 2 - 395 314
----------------------------------- ------ ---------- ---------- ------------
At 30 June /31 December - 1,704 314
----------------------------------- ------ ---------- ---------- ------------
Financial liabilities:
Derivative financial instruments -
oil hedges 2 (3,897) - (1,271)
Contingent consideration (note 12) 3 (3,383) - (3,024)
At 30 June /31 December (7,280) - (4,295)
----------------------------------- ------ ---------- ---------- ------------
Fair value of derivative financial instruments
Commodity price hedges
The fair values of the commodity price options were provided by
counterparties with whom the trades have been entered into. These
consist of Asian style put and call options and swaps to sell/buy
oil. The options are valued using a Black-Scholes methodology;
however, certain adjustments are made to the spot-price volatility
of oil prices due to the nature of the options. These adjustments
are made either through Monte Carlo simulations or through
statistical formulae. The inputs to these valuations include the
price of oil, its volatility, and risk free interest rates.
Foreign exchange contracts
The fair values of foreign exchange contracts were provided by
counterparties with whom the trades have been entered into.
Fair value of financial assets and financial liabilities
The carrying values of the financial assets and financial
liabilities are considered to be materially equivalent to their
fair values.
12 Provisions
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2021 30 June 2020 31 December 2020
GBP'000 GBP'000 GBP'000
----------------------------------------- ----------------------------------- -----------------------------------
Decommis- Decommis-
Decommissioning Contingent sioning Contingent sioning Contingent
provisions consideration Total provision consideration Total provision consideration Total
----------------- ---------------- -------------- ------- ---------- -------------- ------- ---------- -------------- -------
At 1 January 61,819 3,024 64,843 55,101 - 55,101 55,101 - 55,101
Acquisitions - 2,784 2,784
Utilisation of
provision (43) - (43) (864) - (864) (946) - (946)
Unwinding of
discount (note
5) 811 129 940 2,026 - 2,026 1,466 60 1,526
Reassessment
of
decommissioning
provision (note
9 and 10) 1,979 - 1,979 - - - 6,198 - 6,198
Changes in fair
value of
contingent
consideration - 230 230 - - - - 180 180
At 30 June/
31 December 64,566 3,383 67,949 56,263 - 56,263 61,819 3,024 64,843
----------------- ---------------- -------------- ------- ---------- -------------- ------- ---------- -------------- -------
Decommissioning provision
Provision has been made for the discounted future cost of
abandoning wells and restoring sites to a condition acceptable to
the relevant authorities. The provisions are based on the Group's
internal estimate as at 30 June 2021. Assumptions are based on the
current experience from decommissioning wells which management
believes is a reasonable basis upon which to estimate the future
liability. The estimates are reviewed regularly to take account of
any material changes to the assumptions. Actual decommissioning
costs will ultimately depend upon future costs for decommissioning
which will reflect market conditions and regulations at that time.
Furthermore, the timing of decommissioning is uncertain and is
likely to depend on when the fields cease to produce at
economically viable rates. This, in turn, will depend on factors
such as future oil and gas prices, which are inherently
uncertain.
A risk free rate range of 1.20% to 3.00% is used in the
calculation of the provision as at 30 June 2021 (30 June 2020: Risk
free rate range of 1.2% to 3.03%, 31 December 2020: Risk free rate
range of 1.20% to 3.00%).
Contingent consideration
The carrying value of contingent consideration relates to the
acquisition of GT Energy. The change in fair value is primarily
related to the increase in fair value of IGas Energy plc shares
between 31 December 2020 and 30 June 2021, as the consideration is
payable in shares offset by changes to the anticipated timing of
the various milestones being achieved.
13 Cash and cash equivalents and other financial assets
Unaudited Unaudited Audited
As at As at As at
30 June 30 June 31 December
2021 2020 2020
GBP000 GBP000 GBP000
----------------------------------------- ---------- ---------- -------------
Cash and cash equivalents 2,755 2,592 2,438
Borrowings - including capitalised fees (15,123) (12,650) (13,695)
----------------------------------------- ---------- ---------- -------------
Net debt (12,368) (10,058) (11,257)
Capitalised fees (803) (1,108) (937)
----------------------------------------- ---------- ---------- -------------
Net debt excluding capitalised fees at
30 June /31 December (13,171) (11,166) (12,194)
----------------------------------------- ---------- ---------- -------------
Net debt reconciliation
Cash and cash Borrowings Total
equivalents
GBP000 GBP000 GBP000
------------------------------ ------------------------ ----------- ---------
At 1 January 2020 8,194 (13,071) (4,877)
------------------------------ ------------------------ ----------- ---------
Interest paid on borrowings (477) - (477)
Drawdown of RBL 3,215 (3,215) -
Repayment of RBL (4,645) 4,645 -
Foreign exchange adjustments 491 (846) (355)
Other cash flows (4,186) - (4,186)
Other non-cash movements - (163) (163)
------------------------------ ------------------------ ----------- ---------
At 30 June 2020 2,592 (12,650) (10,058)
------------------------------ ------------------------ ----------- ---------
Interest paid on borrowings (463) - (463)
Drawdown of RBL 2,329 (2,329) -
Foreign exchange adjustments (1,327) 1,456 129
Other cash flows (693) - (693)
Other non-cash movements - (172) (172)
------------------------------ -------- -------------- -----------
At 31 December 2020 2,438 (13,695) (11,257)
------------------------------ -------- -------------- -----------
Interest paid on borrowings (454) - (454)
Drawdown of RBL 1,432 (1,432) -
Foreign exchange adjustments (7) 137 130
Other cash flows (654) - (654)
Other non-cash movements - (133) (133)
At 30 June 2021 2,755 (15,123) (12,368)
------------------------ ----------- -----------
Reserve Based Lending facility
On 3 October 2019, the Company announced that it had signed a
$40.0 million RBL facility with BMO Capital Markets (BMO). In
addition to the committed $40.0 million RBL, a further $20.0
million is available on an uncommitted basis, and can be used for
any future acquisitions or new conventional developments. The RBL
has a five-year term, an interest rate of LIBOR plus 4.0%, matures
in September 2024 and is secured on the Company's assets. The RBL
is subject to a semi-annual redetermination in May and November
when the loan availability will be recalculated taking into account
forecast commodity prices, remaining field reserves (assessed by an
independent reserves auditor annually) and the latest forecast of
operating and capital costs. As at 30 June 2021, the Group had
successfully completed the May 2021 redetermination which confirmed
an available facility limit of $27.0 million. Under the terms of
the RBL, the Group is subject to a financial covenant whereby, as
at 30 June and 31 December each year, the ratio of Net Debt at the
period end to Earnings before Interest, Tax, Depreciation,
Amortisation and Exceptional items (EBITDAX as defined in the RBL
agreement) for the previous 12 months shall be less than or equal
to 3.5:1.
Collateral against borrowing
A Security Agreement was executed between BMO and IGas Energy
plc and some of its subsidiaries, namely; Island Gas Limited,
Island Gas Operations Limited, Star Energy Weald Basin Limited,
Star Energy Group Limited, Star Energy Limited, Island Gas
(Singleton) Limited, Dart Energy (East England) Limited, Dart
Energy (West England) Limited, IGas Energy Development Limited,
IGas Energy Enterprise Limited, Dart Energy (Europe) Limited and
IGas Energy Production Limited. Under the terms of this Agreement,
BMO have a floating charge over all of the assets of these legal
entities, other than property, assets, rights and revenue detailed
in a fixed charge. The fixed charge encompasses the Real Property
(freehold and/or leasehold property), the specific petroleum
licences, all pipelines, plant, machinery, vehicles, fixtures,
fittings, computers, office and other equipment, all related
property rights, all bank accounts, shares and assigned agreements
and rights including related property rights (hedging agreements,
all assigned intergroup receivables and each required insurance and
the insurance proceeds).
14 Share capital
Share Share
Ordinary shares Deferred shares capital premium
-------------------------- ------------------------- --------- ---------
Nominal Nominal Nominal
value value value Value
No. GBP000 No. GBP000 GBP000 GBP000
------------------------------------ -------------- ---------- -------------- --------- --------- ---------
Issued and fully paid
At 1 January 2020 122,360,175 2 303,305,534 30,331 30,333 102,680
SIP issue partnership 85,036 - - - - 30
SIP issue matching 85,036 - - - - 31
------------------------------------ -------------- ---------- -------------- --------- --------- ---------
At 30 June 2020 122,530,247 2 303,305,534 30,331 30,333 102,741
SIP issue partnership 203,327 - - - - 26
SIP issue matching 200,326 - - - - 25
Shares issued in respect of
salary sacrifice scheme 1,235,168 - - - - -
Shares issued for acquisitions 377,586 - - - - 84
Shares issued in lieu of Directors'
fees 250,515 - - - - 30
At 31 December 2020 124,797,169 2 303,305,534 30,331 30,333 102,906
SIP issue partnership 185,212 - - - - 21
SIP issue matching 271,971 - - - - 42
------------------------------------ -------------- ---------- -------------- --------- --------- ---------
At 30 June 2021 125,254,352 2 303,305,534 30,331 30,333 102,969
------------------------------------ -------------- ---------- -------------- --------- --------- ---------
15 Subsequent events
On 17 September 2021, the Group signed a Memorandum of
Understanding (MoU) with SSE Heat Networks Limited (SSE) for the
development of a geothermal district heating project in
Stoke-on-Trent (the Project). The MoU grants exclusivity to each of
SSE and GT Energy UK Limited (GTE), a wholly subsidiary of the
Group, with regard to the Project for a period of 12 months with
certain milestones including executing a heat offtake agreement in
relation to GTE's future geothermal plant. This is a non-adjusting
subsequent event.
Glossary
GBP The lawful currency of the United Kingdom
$ The lawful currency of the United States of America
1P Low estimate of commercially recoverable reserves
2P Best estimate of commercially recoverable reserves
3P High estimate of commercially recoverable reserves
1C Low estimate or low case of Contingent Recoverable Resource
quantity
2C Best estimate or mid case of Contingent Recoverable Resource
quantity
3C High estimate or high case of Contingent Recoverable Resource
quantity
AIM AIM market of the London Stock Exchange
Bbl(s)/d Barrel(s) of oil per day
boepd Barrels of oil equivalent per day
bopd Barrels of oil per day
CCUS Carbon capture usage and storage
Contingent Recoverable Resource - Contingent Recoverable
Resource estimates are prepared in accordance with the Petroleum
Resources Management System (PRMS), an industry recognised
standard. A Contingent Recoverable Resource is defined as
discovered potentially recoverable quantities of hydrocarbons where
there is no current certainty that it will be commercially viable
to produce any portion of the contingent resources evaluated.
Contingent Recoverable Resources are further divided into three
status groups: marginal, sub -- marginal, and undetermined. IGas'
Contingent Recoverable Resources all fall into the undetermined
group. Undetermined is the status group where it is considered
premature to clearly define the ultimate chance of
commerciality.
Drill or drop - A drill or drop well carries no commitment to
drill. The decision whether or not to drill the well rests entirely
with the Licensee being driven by the results of geotechnical
analysis. The Licence will, however, still expire at the end of the
Initial Term if the well has not been drilled.
Firm well - A firm well is classified as a firm commitment to
drill a well. It is not contingent on any further geotechnical
evaluation (i.e. it is a fully evaluated Prospect).
GIIP Gas initially in place
m Million
Mbbl Thousands of barrels
MMboe Millions of barrels of oil equivalent
MMscfd Millions of standard cubic feet per day
PEDL United Kingdom petroleum exploration and development
licence
PL Production licence
Tcf Trillions of standard cubic feet of gas
UK United Kingdom
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END
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September 22, 2021 02:00 ET (06:00 GMT)
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