TIDMIGAS
RNS Number : 6976U
Igas Energy PLC
30 March 2023
30 March 2023
IGas Energy plc (AIM: IGAS)
("IGas" or "the Company" or "the Group")
Full year results for the year ended 31 December 2022
Commenting today Chris Hopkinson, Interim Executive Chairman,
said:
"The production drive we initiated in October last year proved
that we can overcome technical and operational challenges and I am
delighted that we continue to maintain the momentum into the new
financial year.
The higher oil and gas prices have been a welcome boost to
revenue and cash generation giving us greater financial flexibility
and enabling us to repay debt. However, we believe now is the right
time, given the prevailing price environment, to focus on driving
opportunities for production, that pay back in a short time frame,
and to that end we will seek to finance these near-term
projects.
It is also critical that we maximise the value of our oil and
gas assets to facilitate a "just transition" to a renewable energy
future through the growth of our geothermal heat business .
Momentum is building in the geothermal business and we look forward
to achieving financial close for the Stoke-on-Trent geothermal
project and moving into the execution phase of that project during
the year."
Financial Performance
2022 2021
Revenues GBP59.2m GBP37.9m
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Net debt* GBP6.1m GBP12.2m
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Adjusted EBITDA* GBP21.1m GBP5.9m
----------- ----------
Operating cash flow before working GBP19.4m GBP7.4m
capital movements
----------- ----------
Loss after tax GBP(11.8)m GBP(6.0)m
----------- ----------
Cash and cash equivalents GBP3.1m GBP3.3m
----------- ----------
Underlying operating profit* GBP16.1m GBP2.0m
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* Adjusted EBITDA, Net Debt (borrowings less cash and cash
equivalents excluding capitalised fees) and Underlying Operating
Profit are used by the Group, alongside IFRS measures for both
internal performance analysis and to help shareholders, lenders and
other users of the Annual Report to better understand the Group's
performance in the period in comparison to previous periods and to
industry peers
Corporate and Financial Summary
-- Higher operating cash flow resulted in a significant
reduction in the Group's net debt to GBP6.1 million. Cash balances
as at 31 December 2022 were GBP3.1 million
-- The Group made a loss after tax of GBP11.8 million. This was
after deducting a GBP30.0 million impairment of our shale assets
following the reimposition of the moratorium on hydraulic
fracturing
-- Net cash capex of GBP7.9 million in 2022 primarily on our conventional assets
-- Successful RBL redetermination confirming $17.0 million (GBP14.0 million) of debt capacity
-- We remain focused on maintaining a strong balance sheet and
funding to support our strategy. We will continue to assess funding
opportunities to optimise our capital structure and manage our debt
facilities effectively
-- 60,000 bbls hedged for H1 23 at an average swap price of
$94.9/bbl (we are no longer required to hedge under the terms of
the RBL)
-- Energy Profit Levy charge for 2022 of GBPnil
-- Ring fence tax losses at 31 December 2022 were c.GBP260 million
-- As the Company has been reshaping its strategic direction to
reflect the transition to a lower carbon economy, the Board is
proposing a change in the Company's name to Star Energy Group PLC
(subject to shareholder approval at the AGM in June 2023)
Operational Performance
-- Restructuring and reorganisation of the business to enable
improved strategic planning and more efficient decision making
-- Net production, averaged 1,898 boepd for the year, heavily
impacted in the first half by equipment failure caused by supply
chain issues, which was subsequently resolved
-- A production drive was initiated in October leading to a
strong recovery in H2 resulting in peak production (averaged across
5 days) of 2,432 boepd and December production averaged 2,221 boepd
(net to IGas)
-- Reserves and Resources updated CPR values 1P NPV10 of $144
million (2021: $139 million): 2P NPV10 of $215 million (2021: $190
million)(+)
-- Planning permission submitted and validated for Glentworth
Phase I - potential for additional 200 bbls/d
-- The drilling of a new well in Corringham is planned for H2
2023 with both planning and permitting in place, which, if
successful, is anticipated to add 110 bbls/d peak production
-- Awaiting imminent outcome of the Green Heat Network Fund
grant application for Stoke-on-Trent geothermal project
-- We anticipate notification as to our success in the five NHS
tenders through the Carbon and Energy Fund in Q2 2023
Outlook
-- We anticipate net production of c.2,000 boepd and operating
costs of c.$41/boe (assuming an average exchange rate of
GBP1:$1.23) in 2023
-- 2023 abandonment costs of c.GBP6.5 million as we ramp up the
abandonment and restoration of old and uneconomic fields, in line
with our licence obligations and to focus on profitable fields.
-- In the process of purchasing a rig as part of setting up a dedicated abandonment division
-- We expect cash capex of GBP15.3m in 2023
o This includes GBP5.9 million for near-term incremental
projects to generate c.150-170 boepd and GBP4.0 million to develop
the Bletchingley gas-to-wire project which is expected to generate
circa 47 GWh of power from late 2024/early 2025 , subject to
financing, and GBP1.0 million to progress developments at Singleton
and Bletchingley
o The remaining capex will be spent on the maintenance and
optimisation of our existing conventional sites
(+) Oil price assumption of c.$75/bbl for 5 years, then inflated
at 2% p.a. from 2031 (capped at $118/bbl) see D&M Report
A results presentation will be available at
http://www.igasplc.com/investors/presentations .
Ross Pearson, Technical Director of IGas Energy plc, and a
qualified person as defined in the Guidance Note for Mining, Oil
and Gas Companies, June 2009 and as updated 21 July 2019, of the
London Stock Exchange, has reviewed and approved the technical
information contained in this announcement. Mr Pearson has 22 years
oil and gas exploration and production experience.
For further information please contact:
IGas Energy plc Tel: +44 (0)20 7993 9899
Chris Hopkinson, Interim Executive Chairman
Ann-marie Wilkinson, Chief Communications Officer
Investec Bank plc (NOMAD and Joint Corporate Broker) Tel: +44
(0)20 7597 5970
Virginia Bull/Chris Sim/Charles Craven
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/Finlay Thomson/Kendall Hill
Interim Executive Chairman's Statement
2022 has been a year of change and refocus for the Company
against a mixed set of challenges both domestic and global.
The weaponisation of energy by Russia driving already high
prices in Europe to an unprecedented level has demonstrated that
traditional energy sources will continue to be a fundamental part
of the overall energy equation for many years to come. Given this
backdrop, the national and local benefits of indigenous oil and gas
supplies remain clear and even more compelling, with a positive
impact on emissions versus imports and Liquified Natural Gas,
energy security, the balance of payments through tax and business
rates and employment.
As a British company operating onshore in the UK, we believe we
have an important role to play in providing the UK's own domestic
resources to give greater security of supply; something the UK
Government in its British Energy Security Strategy has
recognised.
With a cost-of-living and energy crisis unfolding, the UK
Government responded by lifting the moratorium on hydraulic
fracturing in England on 8 September, 2022 and committed to review
energy regulation, paving the way for the timely development of
shale in the UK providing jobs, tax revenue, energy security and
significant community benefits. Disappointingly, just a few weeks
later , this decision was reversed on 27 October 2022.
Having taken advice, and reflected on our strategic goals as a
business, we have decided not to pursue legal recourse further in
respect to the reimposition of the moratorium on hydraulic
fracturing and have fully impaired our remaining shale assets. We
continue to believe and assert that fracking for shale gas can and
will be done safely and in an environmentally responsible manner.
There is a significant recoverable gas resource in the Gainsborough
Trough, the equivalent of up to 19 years of the UK's gas demand,
that could provide this country both energy security for years to
come as well as providing billions of pounds of investment into the
East Midlands and the creation of thousands of skilled jobs. It is
unfortunate that this strategic resource is unlikely to be
realised.
Board Changes
There have been a number of changes to the Board during the
year. Stephen Bowler, Chief Executive Officer, left IGas by mutual
consent in September 2022. Frances Ward, who joined IGas in 2017,
was appointed as Chief Financial Officer and a Board Director in
September 2022.
I was appointed to the Board in January 2022, as a Non-executive
Director and Chairman designate. At the close of the IGas Annual
General Meeting in June, I took over the role of Chairman from Cuth
McDowell who had served as Interim Non-executive Chair since
October 2019 and a member of the Board since December 2012.
Following Stephen's departure in September, I assumed the role of
Interim Executive Chairman.
In February 2022, we welcomed Kate Coppinger to the Board who
then took over the role of Chair of the Audit committee from Cuth
McDowell in June 2022. Tushar Kumar resigned from the Board as a
Non-executive Director in July 2022.
Most recently, in January 2023, we welcomed Doug Fleming as a
Non-executive Director. Doug brings 27 years of senior experience
working in oil and gas exploration and production, corporate
banking and venture capital.
Our Performance in 2022
When I was appointed Interim Executive Chairman in September I
indicated there would be necessary changes in the business to make
it more efficient to ensure operational excellence in our
conventional assets, that we expedite growth in our nascent
geothermal business and we have a structure that correctly reflects
the size and shape of the current business. Furthermore, after a
thorough review of the business, we undertook a restructuring and
rightsizing of the Executive Committee that will enable improved
strategic planning and more efficient decision making, as the
business looks to create a strong and relevant future for its
investor base.
The higher oil and gas prices have been a welcome boost to
revenue and cash generation giving us greater financial flexibility
enabling us to repay debt and invest in our assets.
Our operational performance was a year of two halves. The first
half was beset with equipment failure caused by supply chain issues
and rig downtime due to staffing constraints, that resulted in a
number of wells being offline. In October 2022, we introduced a
series of initiatives to expedite a work programme to get us back
on track and during Q4 the production drive resulted in us bringing
online a significant number of wells and returning production to
the forecast levels. I want to thank everyone involved for all of
the hard work and continued focus in delivering operational
outperformance in Q4 and beyond.
There is no doubt that geothermal technology can provide a
near-term, green solution to the decarbonisation of large scale
heat in Britain bringing with it significant economic benefits. As
we transition from fossil fuels to renewable alternatives, the core
skills deployed in the oil and gas sector, such as sub-surface
geology, well engineering and drilling, are highly transferable to
geothermal.
Outlook
IGas continues to put its efforts into the provision of
responsibly sourced oil and gas to the UK domestic market,
protecting security of supply, and reducing the UK's reliance on
imports whilst positioning itself in the transition to a lower
carbon future through the expansion of its geothermal business.
I am excited to be leading IGas at this important stage in its
development. We are now firmly focussed on maximising the value of
our oil and gas assets to facilitate a "just transition" to a
renewable energy future through the growth of our geothermal heat
business. I look forward to working with the reinvigorated team as
we grow the business, deliver operational excellence and create
value for our investors, staff and communities.
Operating Review
Production
Net production for the period averaged 1,898 boepd (2021: 1,962)
and was heavily i mpacted by equipment failure in the first half of
the year. The equipment failure was primarily caused by
sub-standard material quality, largely as a run-on consequence of
COVID-19 supply chain issues. This resulted in a backlog of well
repair work, which itself was delayed due to COVID-19 outbreaks
amongst rig crews.
In October 2022, a production drive was initiated to ensure
wells, plant and equipment had the maximum uptime, going from one
to five fully operational rigs, returning 18 offline wells to
production, converting two wells from jet pump to beam pumps,
lowering operating costs and significantly increasing water
injection capacity across our asset base. We also i ntroduced a
production dashboard that tracks performance and provides a summary
of our weekly priority work activities. As a result of these
initiatives, Q4 2022 saw some of the highest production levels in
recent times and on 14 December 2022, we produced 2,864 boe,
including returns from hotwashes. At peak production (averaged
across five days) we produced 2,432 boepd and December production
averaged 2,221 boepd (net to IGas).
In 2023, we will move the focus from bringing on any and all
production to putting the business on a resilient and sustainable
footing, able to withstand a wider range of commodity prices. We
will focus on maintaining and increasing production on more
profitable fields, whilst attempting to drive down costs across the
portfolio. Given this focus and the annual average, underlying
production decline of c.7%, we anticipate net production in 2023 of
c.2,000 boepd.
Operating costs were $41.5/bbl driven primarily by increased
energy costs and general price increases on equipment, offset by a
more favourable foreign exchange rate. The largest component of
increased energy costs was the price of electricity. However, given
IGas is a net exporter of electricity, there is a net benefit to
IGas of GBP0.5 million, equivalent to $0.93/boe. Increased costs
are being observed with most goods and services alongside extended
delivery times for equipment. To try and mitigate some of these
factors, critical items are being bulk ordered for stock resulting
in higher spend levels.
We continue to focus our technical and operational expertise on
offsetting the underlying natural decline in our fields. This is
achieved through the execution of incremental production
opportunities that demonstrate commercial benefit via our delivery
assurance processes.
During 2022, we completed the abandonment of three wells, two on
the Stockbridge field and one on the Egmanton field.
As we look to the future, part of our transition strategy is the
abandonment and restoration of old and uneconomic fields, in line
with our licence obligations. Our abandonment programme will be
accelerated consistent with this strategy, and to support our focus
on profitable fields. As part of that strategy, we are moving to
campaign style abandonment and to support this, have created a
dedicated abandonment division within the business. We are in the
process of purchasing a rig to service the abandonments, which will
bring the additional benefit of being utilised for workovers that
will ultimately drive down third-party costs.
We continue to work closely with all our regulators to ensure we
at least meet, if not exceed, our responsibilities as a responsible
operator.
Reserves and resources
CPR
In February 2023, IGas announced the publication of the full and
final results of the Competent Persons Report (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 2022. 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 Dec
2022 (MMboe).
1P 2P 2C
Reserves & Resources as at 31 Dec 2021 10.57 15.79 20.34
Production during the period (0.68) (0.68) -
Additions & revisions during the period 1.28 1.93 (1.64)
Reserves & Resources as at 31 Dec 2022 11.17 17.04 18.70
*Oil price assumption of c.$75/bbl for 5 years, then inflated at
2% p.a. from 2031 (capped at $118/bbl)
1P NPV10 of $144 million(2021: $139 million): 2P NPV10 of $215
million (2021: $190 million)*
Development
Conventional oil and gas
In the first quarter of 2022, work was completed to convert an
existing, suspended well in the Stockbridge field to a water
disposal well; this allowed c.200 bbls/d of suspended production to
be brought back online. The project also provides more operational
flexibility in handling produced water in the Stockbridge area.
During the year, we continued to mature our growth opportunities
in the East Midlands at Corringham and Glentworth submitting
applications for planning and permitting and in the Weald,
submitting permit applications for Bletchingley.
On the infill drilling project at Corringham, which has the
potential to add c.110 bbls/d and 0.35 mmstb 2P reserves, we have
now discharged all our planning conditions and we received
environmental permits in March 2023. Execution of this project,
along expected timelines, should add production at the end of
2023.
There is a mature opportunity to install 6MW of electrical
generation capability at the Bletchingley Central site fuelled by
gas from the Bletchingley 2 well, which is currently suspended.
This will generate circa 47GWh of electricity delivered into the
local distribution network. First power export from this project is
expected in late 2024/early 2025.
Glentworth, is a larger appraisal/development project to extend
one of our existing fields. We submitted a planning application to
Lincolnshire County Council for the construction of a new wellsite,
to the west of our existing Glentworth-K oil production site in
December 2022. The application was validated by the Council in
December 2022. It is currently scheduled to be heard at the April
2023 Planning Committee meeting. Phase I has the potential to add
c.200 bbls/d and development of c.1.0 mmstb 2P reserves (currently
2P undeveloped).
If phase I is successful, this will be followed by further
development drilling in subsequent years with the subsequent
development having the potential to add an additional 500bbls/d and
the addition of c.2mmstb 2P reserves from 2C.
As well as executing the Corringham, Bletchingley and Glentworth
projects, we look forward to bringing back production at our
shut-in Avington field and continue to mature our portfolio of
opportunities, particularly around the Singleton and Welton
fields.
Shale
The Group holds a significant portfolio of shale licences,
totalling 292,100 net acres with estimated Mean volumes of
undiscovered GIIP of 93 TCF (net to IGas, independently assessed by
D&M in 2016).
Following a concerted effort from the UK onshore oil and gas
industry, on 5 April 2022 the Government announced that it had
commissioned the British Geological Survey to advise on the latest
scientific evidence around shale gas extraction. This report was
delivered to BEIS on 5 July 2022.
On 8 September 2022, the Government announced a lifting of the
effective moratorium on hydraulic fracturing in England and a
review of energy regulation. On 27 October 2022, the Government,
under the leadership of Rishi Sunak, as Prime Minister,
reintroduced the moratorium on hydraulic fracturing for shale
gas.
We have fully impaired our remaining shale assets and the
Springs Road well will be fully abandoned and restored by Q1
2024.
Geothermal Heat
We have made significant progress during the year in bringing
our vision for decarbonisation of large-scale heat using geothermal
energy, in the UK, closer to fruition. We have been working closely
with the Government, academia and commercial partners to accelerate
support for, and understanding of, this proven technology.
Launched in March 2022 the GHNF opened up for the drilling of
geothermal wells. The GHNF Transition Scheme is a three year,
GBP288 million capital grant fund that will support the
commercialisation and construction of new low and zero carbon heat
networks including deep geothermal wells and associated works. We
submitted an application with SSE for the Stoke-on-Trent district
heat network project and await a decision on the grant award.
In December 2022, we made applications for grant funding from
the Public Sector Decarbonisation Scheme in partnership with the
Carbon Energy Fund (CEF) for the development of five geothermal
schemes, supplying renewable heat to NHS Trusts. We anticipate
notification as to our success in Q2 2023. Subject to our success
in one or more of the schemes, a further five or more NHS sites are
likely to be put forward in H2 2023.
The Public Sector Decarbonisation Scheme, which provides grants
for public sector bodies to fund site decarbonisation, launched its
Phase 3 in September 2022 for low carbon technologies including
deep geothermal. Phase 3 of the Scheme will provide GBP1.425
billion of grant funding over the financial years 2022/2023 to
2024/2025, through multiple application windows. If successful, the
funding will enable us to progress these projects through the
planning and design phase and bring them to shovel ready stage.
As awareness grows of the potential for geothermal we are being
approached by numerous end-users - public sector and commercial -
in search of low carbon solutions to replace higher carbon sources
of heat provision.
Our project pipeline continues to grow and mature and we are in
active discussions with potential customers for 35 projects.
The Government is also actively working on longer term support
for geothermal with the Department for Energy Security and Net Zero
commissioning ARUP and the British Geological Survey to produce a
Deep Geothermal Energy White Paper, an evidence-based assessment to
help accelerate the development and deployment of deep geothermal
energy projects as an opportunity to significantly contribute to
the UK's net zero goals.
Outlook
During 2023, we expect to start delivering on the organisation's
diversification strategy. We expect to achieve financial close for
the Stoke-on-Trent geothermal project and move into the execution
phase of that project. This will be a fundamental step forward for
the company and for the wider geothermal sector in the UK. We will
continue to grow and mature our pipeline of geothermal
opportunities across the UK.
Financial Review
Commodity prices remained strong during the year, with Brent
averaging c.$108/bbl in the first half of the year before falling
to an average of c.$95/bbl in the second half, resulting in strong
operational cash flow from our conventional oil and gas assets.
Natural gas prices remained volatile, reaching peaks of over
500p/therm and 700p/therm in March and August, respectively, and
averaging 262p/therm for the year. Sterling weakened during the
year, declining to a low of GBP1:$1.07 before recovering to
GBP1:$1.22 towards the end of the year. Average GBP/USD rates were
GBP1:$1.23 in 2022 compared to GBP1:$1.38 in 2021, which also had a
favourable impact on our revenues.
Production for the year averaged 1,898 boepd (2021: 1,962 boepd)
meeting our guidance for the year despite supply chain and staffing
challenges which impacted our ability to perform well interventions
as quickly as planned in the first half of the year. However, good
results from our Stockbridge water injection well, production
enhancement and optimisation expenditure and a production
initiative in the fourth quarter meant we were able to mitigate
these issues and offset the natural declines from our fields.
Whilst volumes declined from last year, the improved pricing and
weakening of sterling resulted in increased revenues of GBP59.2
million for the year (2021: GBP37.9 million) which was partially
offset by a realised loss on hedging of GBP8.0 million (2021:
GBP6.6 million). Operating costs increased to GBP24.0 million
(2021: GBP19.1 million) reflecting inflationary increases in
materials and equipment costs, supply chain disruptions, additional
workover and maintenance activity and an increase in electricity
costs. Operating costs also include an increase of GBP1.5 million
relating to the purchase of third party oil volumes which is offset
by higher revenue from their sale. Depreciation, depletion and
amortisation (DD&A) increased to GBP6.3 million (2021: GBP4.8
million) mainly due to the increase in the carrying value of assets
following the reversal of impairment to oil and gas properties
recorded in June 2022. Underlying operating costs per boe,
excluding third party oil but including costs relating to leases
capitalised under IFRS 16, were GBP33.4 ($41.5) per boe for the
year (2021: GBP27.1 ($37.4) per boe.
Realised Price Per Barrel
2022 2021
----- -----
$ $
----- -----
Realised price per barrel 82.7 54.3
----- -----
G&A per BOE 11.7 11.4
----- -----
Other operating costs (underlying) 30.8 29.0
----- -----
Well services 8.0 5.3
----- -----
Transportation and storage 2.7 3.1
----- -----
A net impairment reversal was recognised on oil and gas assets
in the year of GBP0.03 million (2021: Nil). An impairment reversal
of GBP10.5 million was recorded in the South Cash Generating Unit
(CGU) as a result of higher commodity prices. In the North CGU, an
impairment charge of GBP8.9 million was recognised due to the
increase in discount rates, higher operating costs and the impact
of the Energy Profit Levy. We impaired GBP1.5 million of past costs
on our Lybster licence as these are not expected to be recovered in
any future development of the site. We are currently reviewing
development options for this asset. Exploration and evaluation
assets of GBP30.0 million were also written off during the year
which included GBP6.0 million related to PEDL 184 following the
rejection of planning consent on appeal for a well test of the
Ellesmere Port-1 well and GBP23.8 million related to PEDLs 12, 139,
140, 169 and 210 in our core Gainsborough Trough area, following
the reimposition of the moratorium on hydraulic fracturing for
shale gas by the UK Government in October 2022.
Adjusted EBITDA was GBP21.1 million (2021: GBP5.9 million) and
the underlying operating profit was GBP16.1 million (2021: GBP2.0
million), with the increases resulting primarily from improved
revenues and gross margin.
Adjusted EBITDA
2022 2021
------- -------
GBPm GBPm
------- -------
Loss before tax (18.4) (12.3)
------- -------
Net finance costs 5.1 3.9
------- -------
Changes in fair value of contingent
consideration - (0.6)
------- -------
Depletion, depreciation & amortisation 6.3 4.9
------- -------
Oil and gas assets net impairment - -
(reversal)/charge
------- -------
Exploration and evaluation assets
impairment charge 30.0 10.5
------- -------
EBITDA 23.0 6.4
------- -------
Lease rentals capitalised under
IFRS 16 (1.7) (1.5)
------- -------
Share-based payment charge 1.0 0.9
------- -------
Unrealised (gain)/loss on hedges (1.9) 0.1
------- -------
Redundancy costs (net of capitalisation) 0.7 -
------- -------
Adjusted EBITDA 21.1 5.9
------- -------
Underlying operating profit
2022 2021
------- ------
GBPm GBPm
------- ------
Operating loss (13.3) (9.0)
------- ------
Lease rentals capitalised under
IFRS 16 (1.7) (1.5)
------- ------
Depreciation charge of right-of-use
assets 1.3 1.0
------- ------
Share-based payment charge 1.0 0.9
------- ------
Oil and gas assets net impairment - -
(reversal)/charge
------- ------
Exploration and evaluation assets
impairment charge 30.0 10.5
------- ------
Unrealised (gain)/loss on hedges (1.9) 0.1
------- ------
Redundancy costs (net of capitalisation) 0.7 -
------- ------
Underlying operating profit 16.1 2.0
------- ------
Higher operating cash flows resulted in a significant reduction
in the Group's net debt to GBP6.1 million as at 31 December 2022
(31 December 2021: GBP12.2 million). The Group's RBL is subject to
a semi-annual redetermination which confirmed an available facility
limit of GBP14.0 million ($17.0 million) as at 1 January 2023.
31 December 31 December
2022 2021
GBPm GBPm
------------ ------------
Debt (nominal value excluding
capitalised expenses) (9.2) (15.5)
------------ ------------
Cash and cash equivalents 3.1 3.3
------------ ------------
Net Debt (6.1) (12.2)
------------ ------------
Income Statement
The Group recognised revenues of GBP59.2 million for the year
(2021: GBP37.9 million). Group production for the year averaged
1,898 boepd (2021: 1,962 boepd). Revenues included GBP2.7 million
(2021: GBP1.1 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 pre-hedge realised price for the year was $98.6/bbl
(2021: $68.5/bbl) and post-hedge $82.7/bbl (2021: $54.3/bbl). A
loss of GBP8.0 million was realised on hedges due to an increase in
oil prices during the year (2021: GBP6.6 million). The average
GBP/USD exchange rate for the year was GBP1: $1.23 (2021: GBP1:
$1.38).
Cost of sales for the year were GBP30.3 million (2021: GBP23.9
million) including DD&A of GBP6.3 million (2021: GBP4.8
million), and other costs of sales of GBP24.0 million (2021:
GBP19.1 million). The DD&A charge has increased by GBP1.5
million in the year due to the increase in the carrying amount of
the underlying oil and gas assets as a result of the reversal of
impairment on the South CGU in June 2022. Other costs of sales were
GBP4.9 million higher than the prior year. GBP1.5 million of the
increase related to the purchase of third party oil which was
offset by higher revenue from related sales. The remaining increase
was due to inflationary increases in materials and equipment costs,
supply chain disruptions, additional workover and maintenance
activity and an increase in electricity costs .
Underlying operating costs per barrel of oil equivalent (boe),
excluding third party oil but including costs relating to leases
capitalised under IFRS 16, increased to GBP33.4 ($41.5), (2021:
GBP27.1 ($37.4) per boe), as a result of the higher operating costs
in the year.
Adjusted EBITDA in the year was GBP21.1 million (2021: GBP5.9
million). The gross profit for the year was GBP28.8 million (2021:
GBP14.0 million).
Administrative costs increased by GBP0.5 million to GBP6.3
million (2021: GBP5.8 million). The increase was due to higher
staff costs arising as a result of inflation increases and
redundancy costs incurred during the year. This was partially
offset by lower legal and professional costs and a higher
allocation to capital projects.
A net impairment reversal of GBP0.03 million was recorded on oil
and gas assets during the year (2021: GBPnil). The impairment
assessment at year end was based on a discounted cash flow model
prepared using price assumptions for Brent of $70-80/bbl for the
years 2023-2027 and $65/bbl thereafter. Management also performed
sensitivity analysis on the key assumptions. Whilst the impairment
assessment supported a reversal of the previously recorded
impairment of GBP10.5 million for the South CGU, an impairment
charge of GBP8.9 million was recognised in the North CGU as a
result of the impact of an increase in the discount rate, higher
operating costs and the expansion of the Energy Profits Levy
scheme, which more than offset the benefits from higher oil price
forecasts for that CGU. In addition, an impairment charge of GBP1.5
million was recorded against the Scotland CGU in respect of past
costs as these are not expected to be recovered in any future
development of the site.
Exploration and evaluation assets impairments during the year
were GBP30.0 million. This included GBP6.0 million relating to PEDL
184 following the rejection of planning consent on appeal for a
well test of the Ellesmere Port-1 well and, as the Group have no
plans for further activity on the licence, the full capitalised
amount has been written off (2021: GBP10.5 million). In addition,
GBP23.8 million was written off primarily related to PEDLs 12, 139,
140, 169 and 210 in the Gainsborough Trough area following the
reimposition of the moratorium on hydraulic fracturing for shale
gas by the UK Government in October 2022, a month after it was
temporarily lifted. The Board assessed that, given the broad
political consensus in the UK on this issue, the moratorium is
unlikely to be lifted in the near to medium-term and therefore that
the Group is unlikely to be able to proceed with the commercial
development of this asset, hence the full capitalised value was
written off.
Net finance costs were GBP5.1 million (2021: GBP3.9 million).
Interest and amortisation of finance fees on borrowings were GBP1.2
million (2021: GBP1.1 million) with the impact of a reduction in
the amount drawn being offset by higher interest rates. Finance
costs also included the unwinding of discount on provisions of
GBP1.7 million (2021: GBP1.9 million) and a foreign exchange loss
of GBP1.4 million (2021: GBP0.2 million) due to the revaluation of
our USD denominated loan at a stronger USD/GBP rate. Interest on
leases was GBP0.7 million (2021: GBP0.7 million).
The increase in oil prices during the year generated a net loss
on oil price derivatives of GBP6.0 million (2021: GBP6.7
million).
A net tax credit of GBP6.6 million (2021: GBP6.2 million) was
recognised during the year, mainly due to the increase in a
deferred tax asset relating to tax losses following an improved
short term oil price and foreign exchange environment (GBP14.1
million), partially offset by a deferred tax charge arising as a
result of the Energy Profits Levy (GBP4.6 million) and accelerated
capital allowances of (GBP3.0 million).
Cash Flow
Net cash generated from operating activities for the year was
GBP18.1 million (2021: GBP7.1 million). The increase was primarily
due to higher revenue partially offset by a realised hedge loss,
higher operating costs and working capital movements. We also spent
GBP2.2 million on our abandonment programme during the year related
to wells in the Stockbridge and Egmanton fields (2021: GBP0.4
million).
The Group invested GBP7.9 million across its asset base during
the year (2021: GBP4.8 million). GBP7.2 million was invested in our
conventional assets primarily to convert an existing, suspended
well in the Stockbridge field to a water disposal well allowing
c.200 bbls/d of suspended production to be brought back on line and
in smaller projects to generate near-term production and offset
field declines by upgrading existing facilities and systems and
optimising production at a number of sites. GBP0.5 million was
spent on working up additional exploration opportunities on
conventional assets as well as maintenance costs relating to shale
licences.
The Group made a repayment of GBP8.0 million ($10 million)
(2021: GBP0.7 million ($1.0 million)) under the RBL and paid GBP1.0
million ($1.2 million) in loan interest (2021: GBP0.8 million ($1.0
million)).
To protect against the volatile oil price and in accordance with
the requirements of our RBL facility, the Group placed commodity
hedges for a period of up to 12 months. As at 31 December 2022, the
Group had hedged a total of 60,000 bbls for 2023, using fixed price
swaps at an average fixed price of $94.93/bbl.
Cash and cash equivalents were GBP3.1 million at the end of the
year (2021: GBP3.3 million).
Balance Sheet
Net assets reduced by GBP10.3 million to GBP58.3 million at 31
December 2022 (2021: GBP68.6 million), primarily due to the
impairment of capitalised exploration costs related to our shale
assets, offset by a reduction in borrowings and in our
decommissioning provision.
Property, plant and equipment increased by GBP0.1 million during
the year as a result of capital expenditure of GBP7.8 million,
offset by a DD&A charge of GBP5.0 million and a reduction in
the value of decommissioning assets of GBP2.7 million.
Intangible assets reduced by GBP29.1 million following an
impairment of shale assets of GBP30.0 million. Additions to oil and
gas exploration and evaluation assets and geothermal development
assets were GBP0.7 million and GBP0.2 million, respectively.
The provision for decommissioning costs decreased by GBP3.2
million (2021: increase of GBP3.3 million) as a result of
abandonment activity during the year (GBP2.3 million), an increase
in discount rates and a change in inflation assumptions and the
expected timing of abandonments (GBP2.7 million), offset by the
unwinding of the discount on the provision of GBP1.7 million.
At 31 December 2022, right-of-use assets were GBP7.4 million
(2021: GBP7.0 million) and related lease liabilities were GBP7.8
million (2021: GBP7.2 million).
We repaid $10.0 million (GBP8.0 million) on our RBL loan
facility during the year reducing net debt to GBP6.1 million by
year end (2021: GBP12.2 million).
2023 Capital Expenditure
We are forecasting cash capex of GBP15.3 million in 2023,
subject to financing. This includes GBP5.7 million for near-term
incremental projects to generate c.150-170 boepd, including 110
bbls/d from our Corringham project which is expected to be online
at the end of 2023. The remaining expenditure includes GBP4.0
million to develop the Bletchingley gas-to-wire project which is
expected to generate circa 47 GWh of power from late 2024/early
2025, GBP1.0 million to progress development projects at Singleton
and Glentworth, and expenditure on the maintenance and optimisation
of our existing conventional sites .
We expect a cash outflow of c.GBP6.5 million for our abandonment
programme in 2023 to be spent primarily in carrying out abandonment
works in the Egmanton field and abandoning two shale wells. We are
also in the process of purchasing a rig as part of setting up a
dedicated abandonment division.
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 and
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.
Crude oil prices rose during 2022 as loosening pandemic-related
restrictions and growing economies resulted in global petroleum
demand rising faster than supply. The war in Ukraine and sanctions
imposed on Russia have led to concerns about oil and gas supply
disruption while also adding support to prices. Going forward,
prices remain volatile with cost of living and recession concerns
in many economies increasing risks on the demand side whereas
China's relaxing of COVID-19 restrictions and resumption of normal
economic activity will support prices.
The Group's operating cash flows have improved in 2022 as a
result of improving commodity prices and we have successfully
completed the November 2022 redetermination. A successful
production drive and reorganisation was undertaken in the last
quarter of 2022, which resulted in a significant increase in
production and we have seen the benefit of this extending into
2023, putting the business on a resilient and sustainable footing,
able to withstand a wider range of commodity prices. 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.
The Group's base case cash flow forecast was run with average
oil prices of $84/bbl for H1 2023 and $83/bbl for H2 2023, falling
to $80/bbl for H1 2024 and $77/bbl for Q3 2024, and a foreign
exchange rate of an average $1.23/GBP1 for 2023 and $1.25/GBP1 for
2024. We also assumed that our existing RBL facility is amortised
in line with its terms, but is not refinanced or extended,
resulting in a reduction in the facility to $nil million from 30
June 2024. Our forecasts show that the Group will have sufficient
financial headroom to meet its financial covenants based on the
existing RBL facility for a period of at least 12 months from the
date of approval of the financial statements.
Management has also prepared a downside case with average oil
prices at $80/bbl for H1 2023, $72/bbl for Q3 2023 and $68/bbl for
Q4 2023, falling further to $65/bbl for H1 2024 and $62/bbl for Q3
2024. We used an average exchange rate of $1.25/GBP1 for the
remainder of H1 2023, $1.27/GBP1 for H2 2023 and H1 2024 and
$1.30/GBP1 for Q3 2024. Our downside case also included an average
reduction in production of 5% over the period. In the event of the
downside scenario, management would take mitigating actions
including delaying capital expenditure and reducing costs, in order
to remain within the Group's debt liquidity covenants over the
remaining facility period, should such actions be necessary. All
such mitigating actions are within management's control. We have
not assumed any extensions or refinancing to the RBL. 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. Management remain focused on maintaining a strong
balance sheet and funding to support our strategy. As part of this
financial policy, management continue to assess funding
opportunities and plan to refinance the existing RBL before its
expiry date.
Based on the analysis above, the Directors have a reasonable
expectation that the Group has adequate resources to continue as a
going concern for at least the next twelve months from the date of
the approval of the Group financial statements and have concluded
it is appropriate to adopt the going concern basis of accounting in
the preparation of the financial statements.
Frances Ward
Chief Financial Officer
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 and underlying operating profit.
These non-IFRS measures are used by the Group, alongside IFRS
measures, for both internal performance analysis and to help
shareholders, lenders and other users of the Annual Report to
better understand the Group's performance in the period in
comparison to previous periods and to industry peers.
Net debt is defined as borrowings excluding capitalised fees
less cash and cash equivalents and does not include the Group's
lease liabilities.
Adjusted EBITDA and underlying operating profit includes
adjustments in relation to non-cash items such as share-based
payment charges and unrealised gain/ loss on hedges.
Lease costs for the period which have been capitalised under
IFRS 16 have been added to underlying operating costs and deducted
in the calculation of adjusted EBITDA to be consistent with
previous periods.
CONSOLIDATED INCOME STATEMENT
FOR THE YEARED 31 DECEMBER 2022
Year ended Year ended
31 December 31 December 2021
2022 GBP000
Note GBP000
-------------------------------------------------------------------- ---- ------------ ----------------------------
Revenue 2 59,171 37,916
Cost of sales:
Depletion, depreciation and amortisation (6,302) (4,794)
Other costs of sales (24,019) (19,105)
-------------------------------------------------------------------- ---- ------------ ----------------------------
(30,321) (23,899)
Gross profit 28,850 14,017
Administrative expenses (6,329) (5,827)
Exploration and evaluation assets written-off 6 (30,018) (10,463)
Oil and gas assets impairment 7 (10,457) -
Reversal of oil and gas assets impairment 7 10,489 -
Loss on derivative financial instruments (6,027) (6,715)
Other income 159 -
Operating loss (13,333) (8,988)
Finance income 3 8 2
Finance costs 3 (5,091) (3,850)
Changes in fair value of contingent consideration 10 - 570
Loss from continuing activities before tax (18,416) (12,266)
Income tax credit 4 6,638 6,230
-------------------------------------------------------------------- ---- ------------ ----------------------------
Loss after tax from continuing operations attributable to
shareholders' equity (11,778) (6,036)
Loss after taxation from discontinued operations
after tax from discontinued operations - (203)
-------------------------------------------------------------------- ---- ------------ ----------------------------
Net loss for the year attributable to shareholders' equity (11,778) (6,239)
-------------------------------------------------------------------- ---- ------------ ----------------------------
Loss attributable to equity shareholders from continuing operations:
Basic loss per share 5 (9.35p) (4.82p)
Diluted loss per share 5 (9.35p) (4.82p)
Loss attributable to equity shareholders including discontinued
operations:
Basic loss per share 5 (9.35p) (4.98p)
Diluted loss per share 5 (9.35p) (4.98p)
-------------------------------------------------------------------- ---- ------------ ----------------------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE YEARED 31 DECEMBER 2022
Year ended Year ended
31 December 31 December
2022 2021
Note GBP000 GBP000
--------------------------------------------------------------------- ----- ------------ ------------
Loss for the year (11,778) (6,239)
Other comprehensive income for the year:
Items that are or may be reclassified subsequently to profit or loss
Currency translation adjustments recycled to the income statement - 326
Total comprehensive loss for the year (11,778) (5,913)
---------------------------------------------------------------------------- ------------ ------------
CONSOLIDATED BALANCE SHEET
AS AT 31 DECEMBER 2022
31 December 31 December
2022 2021
Note GBP000 GBP000
------------------------------------- ---- ----------- -----------
ASSETS
Non - current assets
Intangible assets 6 9,268 38,322
Property, plant and equipment 7 74,731 74,583
Right-of-use assets 7,383 7,017
Restricted cash 8 410 410
Deferred tax asset 4 44,813 38,176
136,605 158,508
------------------------------------- ---- ----------- -----------
Current assets
Inventories 1,667 1,092
Trade and other receivables 7,098 5,509
Cash and cash equivalents 8 3,092 3,289
Derivative financial instruments 525 -
12,382 9,890
------------------------------------- ---- ----------- -----------
Total assets 148,987 168,398
------------------------------------- ---- ----------- -----------
LIABILITIES
Current liabilities
Trade and other payables (8,264) (6,863)
Borrowings 9 (3,325) -
Derivative financial instruments - (1,410)
Lease liabilities (738) (815)
Provisions 10 (6,840) (2,419)
(19,167) (11,507)
------------------------------------- ---- ----------- -----------
Non - current liabilities
Borrowings 9 (5,418) (14,836)
Other payables (369) (770)
Lease liabilities (7,042) (6,362)
Provisions 10 (58,716) (66,307)
(71,545) (88,275)
Total liabilities (90,712) (99,782)
------------------------------------- ---- ----------- -----------
Net assets 58,275 68,616
------------------------------------- ---- ----------- -----------
EQUITY
Capital and reserves
Called up share capital 30,334 30,333
Share premium account 103,068 102,992
Foreign currency translation reserve 3,799 3,799
Other reserves 37,617 36,257
Accumulated deficit (116,543) (104,765)
Total equity 58,275 68,616
------------------------------------- ---- ----------- -----------
These financial statements were approved and authorised for
issue by the Board on 30 March 2023 and are signed on its behalf
by:
Chris Hopkinson Frances Ward
Interim Executive Chairman Chief Financial Officer
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEARED 31 DECEMBER 2022
Called Share Foreign
up premium currency Other
share account translation reserves Accumulated Total
capital GBP000 reserve* ** deficit equity
GBP000 GBP000 GBP000 GBP000 GBP000
At 1 January 2021 30,333 102,906 3,473 35,117 (98,526) 73,303
Loss for the year - - - - (6,239) (6,239)
Share options issued under
the employee share plan - - - 1,140 - 1,140
Issue of shares - 86 - - - 86
Currency translation adjustments - - 326 - - 326
---------------------------------- --------- --------- ------------- ----------- ------------ ---------
At 31 December 2021 30,333 102,992 3,799 36,257 (104,765) 68,616
Loss for the year - - - - (11,778) (11,778)
================================== ========= ========= ============= =========== ============ =========
Share options issued under
the employee share plan - - - 1,360 - 1,360
================================== ========= ========= ============= =========== ============ =========
Issue of shares 1 76 - - - 77
At 31 December 2022 30,334 103,068 3,799 37,617 (116,543) 58,275
---------------------------------- --------- --------- ------------- ----------- ------------ ---------
* The foreign currency translation reserve represents exchange
gains and losses on translation of net assets and results, and
intercompany balances, which formed part of the net investment of
the Group, in respect of subsidiaries which previously operated
with a functional currency other than UK pound sterling.
During the year ended 31 December 2022, we also continued the
liquidation process for certain subsidiaries registered in foreign
jurisdictions and control over these entities remains with the
administrators.
** Other reserves include: 1) Share plan reserves comprising
EIP/MRP/LTIP/VCP/EDRP reserve representing the cost of share
options issued under the long term incentive plans and share
incentive plan reserve representing the cost of the partnership and
matching shares; 2) treasury shares reserve which represents the
cost of shares in IGas Energy plc purchased in the market to
satisfy awards held under the Group incentive plans; 3) capital
contribution reserve which arose following the acquisition of IGas
Exploration UK Limited; and 4) merger reserve which arose on the
reverse acquisition of Island Gas Limited.
CONSOLIDATED CASH FLOW STATEMENT
FOR THE YEARED 31 DECEMBER 2022
Year
ended Year ended
31 December 31 December
2022 2021
Note GBP000 GBP000
Cash flows from operating activities:
Loss from continuing activities before tax for
the year (18,416) (12,266)
Depletion, depreciation and amortisation* 6,338 4,903
Abandonment costs/other provisions utilised (2,579) (356)
Share-based payment charge 934 878
Exploration and evaluation assets written-off 6 30,018 10,463
Reversal of Oil and gas assets impairment 7 (10,489) -
Oil and gas assets impairment 7 10,457 -
Unrealised (gain)/loss on oil price derivatives (1,934) 138
Unrealised loss on foreign exchange contracts - 315
Changes in fair value of contingent consideration 10 - (570)
Finance income 3 (8) (2)
Finance costs 3 5,091 3,850
Other non-cash adjustments - 9
------------------------------------------------------ ----- ------------- -------------
Operating cash flow before working capital movements 19,412 7,362
Increase in trade and other receivables and other
financial assets (1,607) (1,637)
Increase in trade and other payables 919 1,699
Increase in inventories (575) (69)
Cash from continuing operating activities 18,149 7,355
------------------------------------------------------ ----- ------------- -------------
Cash used in discontinued operating activities - (221)
------------------------------------------------------ ----- ------------- -------------
Taxation paid - continuing operating activities - -
Net cash from operating activities 18,149 7,134
------------------------------------------------------ ----- ------------- -------------
Cash flows from investing activities:
Purchase of intangible exploration and evaluation
assets (516) (734)
Purchase of property, plant and equipment (7,196) (3,905)
Purchase of intangible development assets (202) (167)
Interest received 3 8 2
------------------------------------------------------ ----- ------------- -------------
Net cash used in investing activities (7,906) (4,804)
------------------------------------------------------ ----- ------------- -------------
Cash flows from financing activities:
Cash proceeds from issue of ordinary share capital 44 40
Drawdown on Reserves Based Lending facility 8 - 1,432
Repayment of Reserves Based Lending facility 8 (7,985) (756)
Repayment of principal portion of lease liability (1,059) (747)
Repayment of interest on lease liabilities (707) (684)
Interest paid 8 (950) (812)
Net cash used in financing activities (10,657) (1,527)
------------------------------------------------------ ----- ------------- -------------
(414)
Net (decrease)/increase in cash and cash equivalents
in the year ) 803
Net foreign exchange difference 217 48
Cash and cash equivalents at the beginning of
the year 3,289 2,438
------------------------------------------------------
Cash and cash equivalents at the end of the year 8 3,092 3,289
------------------------------------------------------ ----- ------------- -------------
* Depletion, depreciation and amortisation includes GBP1.3
million (2021: GBP1.0 million) relating to right-of-use assets
CONSOLIDATED FINANCIAL STATEMENTS - NOTES
FOR THE YEARED 31 DECEMBER 2022
1 Accounting policies
(a) Basis of preparation of financial statements
Whilst the financial information in this preliminary
announcement has been prepared in accordance with international
accounting standards in conformity with the requirements of the
Companies Act 2006 ("the "Standards"), this announcement does not
contain sufficient information to comply with the Standards. The
Group will publish full financial statements that comply with the
Standards in May 2023.
The financial information for the year ended 31 December 2022
does not constitute statutory financial statements as defined in
sections 435 (1) and (2) of the Companies Act 2006. Statutory
financial statements for the year ended 31 December 2021 have been
delivered to the Registrar of Companies and those for 2022 will be
delivered following the Company's annual general meeting. The
auditor has reported on the 2022 financial statements and their
report was unqualified. The report did not contain a statement
under section 498 (2) or (3) of the Companies Act 2006.
The accounting policies applied are consistent with those
adopted and disclosed in the Group's financial statements for the
year ended 31 December 2021. There have been a number of amendments
to accounting standards and new interpretations issued by the
International Accounting Standards Board which were applicable from
1 January 2022. These did not have a material impact on the
accounting policies, methods of computation or presentation applied
by the Group.
There are also a number of amendments to accounting standards
and new interpretations issued by the International Accounting
Standards Board which will be applicable from 1 January 2023
onwards. These are not expected to have a material impact on the
accounting policies, methods of computation or presentation applied
by the Group and have not been adopted early.
Further details on new International Financial Reporting
Standards adopted and yet to be adopted will be disclosed in the
2022 Annual Report and Financial Statements.
IGas Energy plc is a public limited company incorporated and
registered in England and Wales and is listed on the Alternative
Investment Market ("AIM"). The Group's principal activities are
exploring for, appraising, developing and producing oil and gas and
developing geothermal projects.
The financial information is presented in UK pounds sterling and
all values are rounded to the nearest thousand (GBP000) except when
otherwise indicated. Certain prior year numbers have been
reclassified to conform to the current year presentation.
(b) 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 and
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.
Crude oil prices rose during 2022 as loosening pandemic-related
restrictions and growing economies resulted in global petroleum
demand rising faster than supply. The war in Ukraine and sanctions
imposed on Russia have led to concerns about oil and gas supply
disruption while also adding support to prices. Going forward,
prices remain volatile with cost of living and recession concerns
in many economies increasing risks on the demand side whereas
China's relaxing of covid-19 restrictions and resumption of normal
economic activity will support prices.
The Group's operating cash flows have improved in 2022 as a
result of improving commodity prices and we have successfully
completed the November 2022 redetermination. A successful
production drive and reorganisation was undertaken in the last
quarter of 2022, which resulted in a significant increase in
production and we have seen the benefit of this extending into
2023, putting the business on a resilient and sustainable footing,
able to withstand a wider range of commodity prices. 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.
The Group's base case cash flow forecast was run with average
oil prices of $84/bbl for H1 2023 and $83/bbl for H2 2023, falling
to $80/bbl for H1 2024 and $77/bbl for Q3 2024, and a foreign
exchange rate of an average $1.23/GBP1 for 2023 and $1.25/GBP1 for
2024. We also assumed that our existing RBL facility is amortised
in line with its terms, but is not refinanced or extended,
resulting in a reduction in the facility to $nil million from 30
June 2024. Our forecasts show that the Group will have sufficient
financial headroom to meet its financial covenants based on the
existing RBL facility for a period of at least 12 months from the
date of approval of the financial statements.
Management has also prepared a downside case with average oil
prices at $80/bbl for H1 2023, $72/bbl for Q3 2023 and $68/bbl for
Q4 2023, falling further to $65/bbl for H1 2024 and $62/bbl for Q3
2024. We used an average exchange rate of $1.25/GBP1 for the
remainder of H1 2023, $1.27/GBP1 for H2 2023 and H1 2024 and
$1.30/GBP1 for Q3 2024. Our downside case also included an average
reduction in production of 5% over the period. In the event of the
downside scenario, management would take mitigating actions
including delaying capital expenditure and reducing costs, in order
to remain within the Group's debt liquidity covenants over the
remaining facility period, should such actions be necessary. All
such mitigating actions are within management's control. We have
not assumed any extensions or refinancing to the RBL. 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. Management remain focused on maintaining a strong
balance sheet and funding to support our strategy. As part of this
financial policy, management continue to assess funding
opportunities and plan to refinance the existing RBL before its
expiry date.
Based on the analysis above, the Directors have a reasonable
expectation that the Group has adequate resources to continue as a
going concern for at least the next twelve months from the date of
the approval of the Group financial statements and have concluded
it is appropriate to adopt the going concern basis of accounting in
the preparation of the financial statements.
2 Revenue
The Group derives revenue solely within the United Kingdom from
the transfer of control over the 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:
Year ended Year ended
31 December 31 December
2022 2021
GBP000 GBP000
------------------ ----------------------- ------------
Oil sales 52,409 33,254
Electricity sales 2,645 2,048
Gas sales 4,117 2,614
------------------ ----------------------- ------------
59,171 37,916
------------------ ----------------------- ------------
Revenues of approximately GBP26.4 million and GBP26.0 million
were derived from the Group's two largest customers (2021: GBP17.4
million and GBP15.9 million) and are attributed to the oil
sales.
As at 31 December 2022, there are no contract assets or contract
liabilities outstanding (2021: nil).
3 Finance income/(costs ) Year Year
ended ended
31 December 31 December
2022 2021
GBP000 GBP000
--------------------------------------------------- ------------------------------ ------------
Finance income:
Interest on short - term deposits 8 2
Finance income 8 2
--------------------------------------------------- ------------------------------ ------------
Finance costs:
Interest on borrowings (950) (812)
Amortisation of finance fees on borrowings (268) (267)
Net foreign exchange loss (1,417) (151)
Unwinding of discount on decommissioning provision (1,749) (1,659)
Unwinding of discount on contingent consideration - (277)
Interest charge on lease liability (707) (684)
--------------------------------------------------- ------------------------------ ------------
Finance costs (5,091) (3,850)
--------------------------------------------------- ------------------------------ ------------
4 Income tax
(i) Tax credit on loss from continuing ordinary activities Year ended Year ended
31 December 31 December
2022 2021
GBP000 GBP000
------------------------------------------------------------------------ ------------ ------------
Current tax:
Charge on loss for the year - -
Total current tax charge - -
------------------------------------------------------------------------ ------------ ------------
Deferred tax:
Credit relating to the origination or reversal of temporary differences (8,160) (6,360)
Debit/(credit) due to tax rate changes 1,465 (393)
Debit in relation to prior years 57 523
------------------------------------------------------------------------ ------------ ------------
Total deferred tax credit (6,638) (6,230)
------------------------------------------------------------------------ ------------ ------------
Tax credit on loss from continuing activities (6,638) (6,230)
------------------------------------------------------------------------ ------------ ------------
ii) Factors affecting the tax charge
The majority of the Group's profits are generated by
"ring-fence" businesses which attract UK corporation tax and
supplementary charges at a combined average rate of 40% (2021:
40%), in addition to the Energy Profit Levy introduced in May 2022
with an average rate of 15% for the year (2021: 0%).
A reconciliation of the UK statutory corporation tax rate
(applicable to oil and gas companies) applied to the Group's loss
before tax to the Group's total tax credit is as follows:
Year ended Year ended
31 December 31 December
2022 2021
GBP000 GBP000
--------------------------------------------------------------------------------------- --------------- ------------
Loss from continuing ordinary activities before tax (18,416) (12,266)
Expected tax credit based on loss from continuing ordinary activities multiplied by an
average
combined rate of corporation tax and supplementary charge and Energy Profit Levy in
the UK
of 55 % (2021: 40%) (10,141) (4,906)
Deferred tax debit in respect of prior years 57 523
Tax effect of expenses not allowable for tax purposes 2,105 2,085
Tax effect of differences in amounts not allowable for supplementary charge purposes* (100) 24
Impact of profits or losses taxed or relieved at different rates 4,499 (2)
Net decrease in unrecognised losses carried forward (1,864) (6,911)
Net (decrease)/increase in unrecognised temporary taxable differences (2,659) 3,422
Tax rate change 1,465 (393)
Other - (72)
--------------------------------------------------------------------------------------- --------------- ------------
Tax credit on loss from continuing activities (6,638) (6,230)
--------------------------------------------------------------------------------------- --------------- ------------
* Amounts not allowable for supplementary charge purposes relate
to net financing costs disallowed for supplementary charge offset
by investment allowance, which is deductible against profits
subject to supplementary charge.
iii) Deferred tax
The movement on the deferred tax asset in the year is shown
below:
2022 2021
GBP000 GBP000
--------------------------------------------------- -------- --------
Asset at 1 January 38,176 31,945
Tax charge relating to prior year (57) (523)
Tax credit during the year 8,160 6,360
Tax charge arising due to the changes in tax rates (1,465) 393
Other (1) 1
--------------------------------------------------- -------- --------
Asset at 31 December 44,813 38,176
--------------------------------------------------- -------- --------
The following is an analysis of the deferred tax asset by
category of temporary difference:
31 December 31 December
2022 2021
GBP000 GBP000
--------------------------------------------------- ----------- -----------
Accelerated capital allowances (20,685) (18,620)
Tax losses carried forward 50,659 44,388
Investment allowance unutilised 2,265 1,837
Decommissioning provision 12,524 8,263
Unrealised gains or losses on derivative contracts (394) 2,083
Share-based payments 155 162
Right-of-use asset and liability 289 63
Deferred tax asset 44,813 38,176
--------------------------------------------------- ----------- -----------
During the period an adjustment was made to how impairment
losses were allocated to different asset classes for tax purposes.
This has resulted in an increase in the deferred tax liability
arising on qualifying fixed assets of GBP9.6 million which supports
the recognition of additional deferred tax assets arising on losses
of the same amount. This has no impact on the deferred taxes
recognised in prior periods.
iv) Tax losses
The Group has gross total tax losses and similar attributes
carried forward of GBP355.3 million (2021: GBP358.3 million).
Deferred tax assets have been recognised in respect of tax losses
and other temporary differences where the Directors believe it is
probable that these assets will be recovered based on a five-year
profit forecast or to the extent that there is offsetting deferred
tax liabilities. Such recognised tax losses include GBP123.2
million (2021: GBP113.2 million) of ringfence corporation tax
losses which will be recovered at 30% of future taxable profits,
GBP119.8 million (2021: GBP103.4 million) of supplementary charge
tax losses which will be recovered at 10% of future taxable profits
and GBP1.9 million (2021: GBPnil) of losses arising under the EPL
regime which will be recovered at 35% of future taxable
profits.
5 Earnings per share (EPS)
Continuing
Basic EPS amounts are based on the loss for the year after
taxation from continuing operations attributable to ordinary equity
holders of the parent of GBP11.8 million (2021: a loss after
taxation from continuing operations attributable to shareholders'
equity of GBP6.0 million) and the weighted average number of
ordinary shares outstanding during the year of 125.9 million (2021:
125.3 million).
Diluted EPS amounts are based on the loss for the year after
taxation from continuing operations attributable to the ordinary
equity holders of the parent and the weighted average number of
shares outstanding during the year 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.
As at 31 December 2022, there are 11.9 million potentially
dilutive share options (31 December 2021: 11.7 million potentially
dilutive share options) which were not included in the calculation
of diluted earnings per share as their conversion to ordinary
shares would have decreased the loss per share.
The following reflects the income and share data used in the
basic and diluted earnings per share from continuing
operations:
Year ended Year ended
31 December 31 December
2022 2021
----------------------------------------------------------- ------------ ------------
Basic loss per share - ordinary shares of 0.002 pence each (9.35p) (4.82p)
Diluted loss per share - ordinary shares of 0.002 pence
each (9.35p) (4.82p)
Loss for the year attributable to equity holders of the
parent from continuing operations - GBP000 (11,778) (6,036)
Weighted average number of ordinary shares in the year-
basic EPS 125,923,609 125,269,135
Weighted average number of ordinary shares in the year-
diluted EPS 125,923,609 125,269,135
----------------------------------------------------------- ------------ ------------
Discontinued
The following reflects the income and share data used in the
basic and diluted earnings per share including discontinued
operations:
Year ended Year ended
31 December 31 December
2022 2021
----------------------------------------------------------- ------------ ------------
Basic loss per share - ordinary shares of 0.002 pence each (9.35p) (4.98p)
Diluted loss per share - ordinary shares of 0.002 pence
each (9.35p) (4.98p)
Loss for the year attributable to equity holders of the
parent - GBP000 (11,778) (6,239)
Weighted average number of ordinary shares in the year-
basic EPS 125,923,609 125,269,135
Weighted average number of ordinary shares in the year-
diluted EPS 125,923,609 125,269,135
----------------------------------------------------------- ------------ ------------
6 Intangible assets
2022 2021
----------------------------------------- -----------------------------------------
Exploration Exploration
and evaluation Development and evaluation Development
assets costs Total assets costs Total
GBP'000 GBP'000 GBP'000 GBP'000 GBP'000 GBP'000
--------------------------- ---------------- ------------ --------- ---------------- ------------ ---------
At 1 January 34,844 3,478 38,322 43,421 3,290 46,711
Additions 722 232 954 888 188 1,076
Changes in decommissioning* 10 - 10 998 - 998
Impairment (30,018) - (30,018) (10,463) - (10,463)
---------------------------- ---------------- ------------ --------- ---------------- ------------ ---------
At 31 December 5,558 3,710 9,268 34,844 3,478 38,322
---------------------------- ---------------- ------------ --------- ---------------- ------------ ---------
*The decommissioning asset increased in line with the
decommissioning liability following a review of the estimate at 31
December 2022 .
Exploration and evaluation assets
Exploration costs impaired in the financial year to 31 December
2022 were GBP30.0 million (2021: GBP10.5 million) of which GBP23.8
million related to our shale assets in the Gainsborough Trough,
GBP6.0 million related to PEDL 184 (Ellesmere Port) and GBP0.2
million related to trailing costs on relinquished licences. The
capitalised costs remaining on our Exploration and Evaluation
assets at the end of the year relate to our conventional assets.
The 2021 exploration costs written off substantially all related to
the relinquishment of the PEDL 200 (Tinker Lane) licence.
Further analysis by location of assets is as follows:
North West: The Group impaired previously capitalised
exploration expenditure relating to Ellesmere Port of GBP6.0
million resulting in a nil balance at the end of the year (2021:
GBP6.4 million). This follows the rejection of planning consent on
appeal for a well test in the Ellesmere Port-1 well and, as the
Group have no plans for further activity on the licence, the full
capitalised amount has been written off. Despite the rejection of
the planning consent, Cheshire West and Chester Council reimbursed
previously capitalised costs to appeal their decision to refuse the
initial planning application of GBP0.4 million which has been
netted off against the additions to exploration and evaluation
assets in these financial statements.
East Midlands: The Group has impaired previously capitalised
exploration expenditure relating to the Gainsborough Trough which
includes PEDLs 12, 139, 140, 169 and 210 of GBP23.8 million
resulting in a nil balance at the end of the year (2021: GBP23.2
million) . The decision to impair was taken following the
reintroduction of the moratorium on hydraulic fracturing for shale
gas by the UK Government in October 2022, a month after it was
temporarily lifted. Whilst disappointed by the decision, the Board
concluded that, given the broad political consensus in the UK on
this issue, the moratorium is unlikely to be lifted in the near to
medium-term and therefore that the Group is unlikely to be able to
proceed with the commercial development of this asset.
Conventional assets: The Group has GBP5.6 million (2021: GBP5.2
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
31 December 2022 and assessed it for impairment. The development of
the Stoke-on-Trent project has taken longer than anticipated due to
COVID-19 related delays and the delay in the Government
establishing a replacement for the Renewable Heat Incentive scheme
which expired in March 2021. The UK Government launched the Green
Heat Network Fund ("GHNF") in March 2022 and confirmed that it will
fund up to 50% of a project's total combined commercialisation and
construction costs.
GT Energy applied jointly with SSE for a grant from the GHNF in
the second half of 2022. We are awaiting the outcome of the grant
award imminently.
Although the development of the project has been delayed, this
does not materially impact the overall economics and, therefore, no
impairment of development costs has been recognised for the year
(2021: GBPnil). The principal assumptions are the heat sale
volumes, unit price and discount rate. A 10% reduction in sales
volume would result in a decline of the recoverable amount by
GBP2.5 million. A 10% reduction in price would result in a decline
of the recoverable amount by GBP2.9 million. An increase in the
discount rate assumed of 1% (from 10% to 11%) would result in a
decline of the recoverable amount by GBP2.6 million. There would be
no impairment in any of these cases.
7 Property, plant and equipment
2022 2021
------------------------------------- -------------------------------------
Other Other
Oil property, Oil and property,
and gas plant gas plant
assets and equipment Total assets and equipment Total
GBP'000 GBP'000 GBP'000 GBP'000 GBP'000 GBP'000
----------------------------- --------- --------------- --------- --------- --------------- ---------
Cost
At 1 January 215,222 2,430 217,652 209,225 2,951 212,176
Additions 7,757 79 7,836 3,700 - 3,700
Disposals/write-offs - (463) (463) - (521) (521)
Changes in decommissioning* (2,678) - (2,678) 2,297 - 2,297
At 31 December 220,301 2,046 222,347 215,222 2,430 217,652
------------------------------ --------- --------------- --------- --------- --------------- ---------
Accumulated Depreciation,
Depletion and Impairment
At 1 January 142,034 1,035 143,069 138,233 1,504 139,737
Charge for the year 5,020 22 5,042 3,801 52 3,853
Disposals/write-offs - (463) (463) - (521) (521)
Impairment 10,457 - 10,457 - - -
Impairment reversal (10,489) - (10,489) - - -
At 31 December 147,022 594 147,616 142,034 1,035 143,069
------------------------------ --------- --------------- --------- --------- --------------- ---------
NBV at 31 December 73,279 1,452 74,731 73,188 1,395 74,583
------------------------------ --------- --------------- --------- --------- --------------- ---------
*The decommissioning asset reduced in line with the
decommissioning liability following a review of the estimate at 31
December 2022 .
Capital Expenditure incurred during the year related to
conversion of a suspended well in the Stockbridge field to a water
disposal well, a number of projects to generate near-time
production and work to offset field declines by upgrading existing
facilities and systems and optimising production at a number of
sites.
Impairment of oil and gas assets
Year ended 31 December 2022
Cash Generating Units (CGUs) for impairment purposes are the
group of fields whereby technical, economic and/or contractual
features create underlying interdependence in the cash flows. The
Group has identified the three main producing CGUs as: North,
South, and Scotland. At each balance sheet date, the Group assesses
its CGUs for impairment whenever events or changes in circumstances
indicate that the carrying amount of the CGU may not be
recoverable. If any such indication exists, the Group makes an
estimate of the asset's recoverable amount.
At 30 June 2022, due to the high oil and gas prices and
favourable foreign exchange rates, management identified impairment
reversal indicators for the North and South CGUs and performed a
detailed exercise to determine the amount of reversal at that
date.
Due to subsequent increases in interest rates, the imposition of
the Energy Profits Levy and a reduction in commodity price forward
curves in the second half of the year, management identified
impairment indicators at the North and South CGUs and performed an
impairment assessment as at 31 December 2022.
The Scotland CGU comprising the Lybster field is currently
undergoing a redevelopment plan. Possible increased development
costs under the plan indicated a potential impairment for this CGU
leading to an impairment assessment being performed at 30 June
2022. No further impairment assessment was performed at year end,
given no impairment indicators were identified at 31 December
2022.
The future cash flows in the impairment assessments at 30 June
2022 and 31 December 2022 were estimated using the following key
assumptions:
31 December 2022 30 June 2022
Oil Price (Brent) $70-$80/bbl for the years 2023-2027 and $80-$100/bbl for the years 2022-2026 and
$65/bbl thereafter $65/bbl thereafter
USD/GBP foreign exchange rate Range of $1.22:GBP1.00 - $1.30:GBP1 Range of $1.25:GBP1.00 - $1.35:GBP1
Post-tax discount rate 10.5% 9%
Outcome of impairment reviews:
The 30 June 2022 impairment assessment resulted in a recoverable
amount greater than the carrying amount by GBP16.0 million in the
South CGU (recoverable amount of GBP44.8 million) and GBP0.8
million in the North CGU (recoverable amount of GBP39.7 million) .
We capped the impairment reversal recorded in the South CGU to
GBP10.5 million, comprising the net book value of the full amount
previously impaired, in line with the requirements in IAS 36. No
impairment reversal was recorded in the North CGU as reasonable
downside cases indicated that an impairment could be required if
certain sensitivities were applied. Therefore, the factors that led
to the initial impairment were assessed to have not fully reversed
and management did not consider it appropriate to reverse a portion
of the past impairment.
At the Scotland CGU, an impairment of GBP1.5 million was
recognised as at 30 June 2022 (with a recoverable amount of GBP1.3
million) , as it is not expected that all past costs would be
recovered through the development of the site .
The 31 December 2022 impairment assessment resulted in an
impairment in the North CGU of GBP8.9 million , with a final
recoverable amount of GBP34.5 million . However, in the South CGU,
the recoverable amount increased to GBP45.9 million as a result of
change in the reserves profile, hence no impairment was
recorded.
Sensitivity of changes in assumptions
The principal assumptions are future production, estimated Brent
prices, the USD/GBP foreign exchange rate, and the discount rate.
The impact on the recoverable amount that would result from changes
to the key assumptions at 31 December 2022 are shown below:
CGU 10% reduction 10% reduction USD/GBP foreign Increase
in price in production exchange rate @ in discount
$1.4 rate by
1%
GBPm GBPm GBPm GBPm
North (7.67) (7.82) (5.99) (1.39)
South (5.49) (5.39) (6.65) (2.03)
The sensitivity analysis above does not take into account any
mitigating actions available to management should these changes
occur.
Year ended 31 December 2021
The Group reviewed the carrying value of oil and gas assets as
at 31 December 2021 and assessed it for impairment indicators. The
impact of the downward revision of the reserves estimate was offset
by an improving economic outlook and a significantly improved oil
price environment at the reporting date. On this basis, management
concluded that there were no impairment indicators as at 31
December 2021. However, as at 31 December 2021, continued
uncertainty existed regarding the future impact of the COVID-19
pandemic including the emergence of new variants which may have a
negative impact on economic activity and therefore on the demand
for oil. As a result, management concluded that there were no
impairment reversal indicators as at 31 December 2021 and that a
reversal of prior years' impairments was not appropriate.
8 Cash and cash equivalents
31 December 31 December
2022 2021
GBP000 GBP000
------------------------- ----------- -----------
Cash at bank and in hand 3,092 3,289
------------------------- ----------- -----------
The cash and cash equivalents do not include restricted
cash.
Restricted cash
31 December 31 December
2022 2021
GBP000 GBP000
------------ ----------- -----------
Non-current 410 410
------------ ----------- -----------
The restricted cash represents restoration deposits paid to
Nottinghamshire County Council, which serve as collateral for the
restoration of drilling sites at the end of their life. The
restoration deposits are subject to regulatory and other
restrictions and are therefore not available for general use of the
Group.
Net debt reconciliation
31 December 31 December
2022 2021
GBP000 GBP000
---------------------------------------- -------------------------- -----------
Cash and cash equivalents 3,092 3,289
(8,743)
Borrowings - including capitalised fees (8,743)( (14,836)
---------------------------------------- -------------------------- -----------
Net debt (5,651) (11,547)
---------------------------------------- -------------------------- -----------
Capitalised fees (401) (669)
---------------------------------------- -------------------------- -----------
Net debt excluding capitalised fees (6,052) (12,216)
---------------------------------------- -------------------------- -----------
2022 2021
----------------------------- ---------------------------------- ---------------------------------------
Cas h
and cash Cas h and
equivalents Borrowings Total cash equivalents Borrowings Total
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
----------------------------- ------------ ---------- -------- ----------------- ---------- --------
At 1 January 3,289 (14,836) (11,547) 2,438 (13,695) (11,257)
Interest paid on borrowings (950) - (950) (812) - (812)
Drawdown of RBL - - - 1,432 (1,432) -
Repayment of RBL (7,985) 7,985 - (756) 756 -
Foreign exchange adjustments 217 (1,624) (1,407) 48 (198) (150)
Other cash flows 8,521 - 8,521 939 - 939
Other non-cash movements - (268) (268) - (267) (267)
----------------------------- ------------ ---------- -------- ----------------- ---------- --------
At 31 December 3,092 (8,743) (5,651) 3,289 (14,836) (11,547)
----------------------------- ------------ ---------- -------- ----------------- ---------- --------
9 Borrowings
31 December 31 December
2022 2021
GBP000 GBP000
------------------------------------------------------------- ----------- -----------
Reserve-Based Lending Facility (RBL) - secured (current) (3,325) -
Reserve-Based Lending Facility (RBL) - secured (non-current) (5,418) (14,836)
------------------------------------------------------------- ----------- -----------
(8,743) (14,836)
------------------------------------------------------------- ----------- -----------
The carrying amounts of each of the Group's financial
liabilities included within borrowings are considered to be a
reasonable approximation of their fair value.
Reserves-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 USD LIBOR plus 4.0%,
matures in June 2024 and is secured on IGas Energy plc's assets.
USD LIBOR will cease to be published from 30 June 2023 and the
Group is therefore continuing its preparation for transition to
incorporate alternative risk-free rates and is monitoring the
market and discussing the potential changes with its counterparties
in order to effectively transition from USD LIBOR to alternative
risk-free rates. Management does not expect any material impact on
its financial position and performance resulting from this
transition.
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. Subsequent to the
reporting date, the Group had successfully completed the November
2022 redetermination which confirmed an available facility limit of
$17 million; GBP14.1 million (2021: $26.2million; GBP19.3 million)
until the next scheduled redetermination. The current portion of
the borrowings have been assessed on the basis of the RBL loan
facility amortising in line with the contractual terms.
We made a repayment on the loan of GBP8.0 million during the
year (2021: net drawdown of GBP 0.7 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. The Group complied with its covenants
for the financial years ended 31 December 2022 and 31 December
2021.
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).
10 Provisions
2022 2021
-------------------------------------------- --------------------------------------------
Decommissioning Contingent Decommissioning Contingent
provisions consideration Total provisions consideration Total
GBP'000 GBP'000 GBP'000 GBP'000 GBP'000 GBP'000
--------------------- ---------------- --------------- --------- ---------------- --------------- ---------
At 1 January (65,995) (2,731) (68,726) (61,819) (3,024) (64,843)
Utilisation of
provision 2,251 - 2,251 778 - 778
Unwinding of discount (1,749) - (1,749) (1,659) (277) (1,936)
Reassessment of
decommissioning
provision 2,668 - 2,668 (3,295) - (3,295)
Changes in fair value
of contingent
consideration - - - - 570 570
At 31 December (62,825) (2,731) (65,556) (65,995) (2,731) (68,726)
---------------------- ---------------- --------------- --------- ---------------- --------------- ---------
2022 2021
-------------------------------------------- --------------------------------------------
Decommissioning Contingent Decommissioning Contingent
provisions consideration Total provisions consideration Total
GBP'000 GBP'000 GBP'000 GBP'000 GBP'000 GBP'000
---------------- ---------------- --------------- --------- ---------------- --------------- ---------
Current (6,560) (280) (6,840) (2,139) (280) (2,419)
Non-current (56,265) (2,451) (58,716) (63,856) (2,451) (66,307)
At 31 December (62,825) (2,731) (65,556) (65,995) (2,731) (68,726)
----------------- ---------------- --------------- --------- ---------------- --------------- ---------
Decommissioning provision
The Group spent GBP2.3 million on decommissioning activities
during the year (2021: 0.8 million) related primarily to plugging
and abandoning wells at the Stockbridge and Egmanton sites.
Provision has been made for the discounted future cost of
abandoning wells and restoring sites to a condition acceptable to
the relevant authorities. This is expected to take place between 1
to 30 years from year end (2021: 1 to 40 years). The provisions are
based on the Group's internal estimate as at 31 December 2022.
Assumptions are based on our cumulative experience from
decommissioning wells which management believes is a reasonable
basis upon which to estimate the future liability. The estimates
are based on a planned programme of abandonments but also include a
provision to be spent in 2023-2024 on preparing for the abandonment
campaign, abandoning wells and restoring sites which for
regulatory, integrity or other reasons fall outside the planned
campaign. The wells to be decommissioned in 2023 and 2024 are in
line with management's discussions with the regulator. 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.
The Group applies an inflation adjustment to the current cost
estimates and discounts the resulting cash flows using a risk free
discount rate. The provision estimate reflects a higher inflation
percentage in the near term for the period 2022 - 2024 and
thereafter incorporates the long term UK target inflation rate for
the period 2025 and beyond.
The discount rate used in the provision calculation as at 31
December 2022 ranged from 3.0% to 5.1% (2021: 1.2% to 3.00%). The
increase in the risk free discount rate during the year is mainly
due to the increase in the yield on UK government bond for periods
comparable to the life of the provision.
At 31 December 2022, the Group reassessed the decommissioning
provision which resulted in a reduction of GBP2.7m to the value of
the liability. The reduction is comprised of GBP7.4 million due to
the increase in the risk free rate, partially offset by an increase
of GBP0.9 million due to the change in expected timing of the
utilisation of provision and an increase of GBP3.8 million due to
the change in inflation assumptions used in the provision
calculation.
Sensitivity of changes in assumptions
Management performed sensitivity analysis to assess the impact
of changes to the risk free rate and short term inflation
assumption on the Group's decommissioning provision balance. A 0.5%
decrease in the risk free rate assumption would result in an
increase in the decommissioning provision by GBP3.4 million whereas
a 1% increase in inflation applied to each of the next three years
would result in an increase in the decommissioning provision by
GBP1.7 million.
Management also performed sensitivity analysis to assess the
impact of changes to the undiscounted future cost of abandoning
wells and restoring sites on the Group's decommissioning provision
balance. A 10% increase in the undiscounted future cost would
result in an increase in the decommissioning provision by GBP6.5
million.
Contingent consideration
The contingent consideration relates to the acquisition of GT
Energy. The contingent consideration is payable in shares, and is
dependent on the timing of various milestones being achieved. It is
also dependent on the inputs to an agreed-form economic model which
determines the level of the consideration for each milestone in
accordance with the SPA. These inputs relate to targets for aspects
of the Stoke-on-Trent project, including funding, amount of heat
delivered, and costs and revenues achieved. The fair value of the
consideration for each milestone recognised was calculated by
determining the probability weighted value of each payment and
discounted using a WACC of 8.3%. In addition, there is a business
development milestone relating to securing and achieving targets
for a second geothermal project or generating additional capacity
for the Stoke-on-Trent project. The acquisition agreement and
economic model assumed the availability of the Renewable Heat
Incentive (RHI), which closed to applications from 31 March 2021.
In March 2022, the UK Government launched the GHNF and we have
applied for funding for the Stoke-on-Trent project in the first
round. The change in nature of the government support for the
project is not provided for in the economic model or the SPA.
Whilst the contractual implications on the acquisition agreement
are being assessed, management believes that the current value
provides the best estimate of the contingent consideration at this
time. The estimated fair value will be reviewed as the project
progresses and more information becomes available.
11 Subsequent events
On 25 January 2023, the Group issued 144,205 Ordinary GBP0.00002
shares in relation to the Group's SIP scheme. The shares were
issued at GBP0.202 resulting in share premium of GBP29,129.
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
BCF billions of standard cubic feet of gas
boepd Barrels of oil equivalent per day
bopd Barrels of oil per day
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.
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
NBP National balancing point - a virtual trading location for
the sale and purchase and exchange of UK natural gas
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
FR PPUWUWUPWPPB
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March 30, 2023 02:00 ET (06:00 GMT)
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