TIDMIGAS
RNS Number : 5171Z
Igas Energy PLC
15 September 2022
THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION
15 September 2022
IGas Energy plc (AIM: IGAS)
("IGas" or "the Company" or "the Group")
Unaudited Interim results for the six months ended 30 June
2022
IGas announces its unaudited interim results for the six months
to 30 June 2022.
Commenting today Chris Hopkinson, Interim Executive Chairman,
said:
"Commodity prices were exceptionally strong during the period
with a resulting positive impact on income and cash generation from
the underlying conventional oil and gas assets. This continues to
give us financial flexibility, enabling a reduction in our net debt
by over GBP2.5 million and allowing capital to be allocated to
sustaining, and in the future, increasing our conventional
production as well as to our growth businesses, geothermal and now
shale.
We welcomed the Government's announcement last week on the
lifting of the effective moratorium on hydraulic fracturing in
England and the review of energy regulation. However, the
accelerated development of this strategic natural resource, which
we believe is imperative in helping with the ongoing energy and
cost-of-living crisis, can only be achieved through a streamlined
regulatory process, something the Government has committed to and
we look forward to working constructively with the new
administration.
With the submission of grant applications to the Green Heat
Network Fund for our pathfinder Stoke-on-Trent geothermal project
and the building of a strong pipeline of project opportunities, we
are moving the geothermal business forward materially.
With strong commodity prices forecast well into 2023, we expect
to continue to be able to support both growth and debt reduction in
the business."
Results Summary
Six months Six months
to 30 June to
2022 30 June 2021
GBPm GBPm
---------------------------------------- ----------- -------------
Revenues 30.5 16.6
---------------------------------------- ----------- -------------
Adjusted EBITDA* 10.7 2.7
---------------------------------------- ----------- -------------
Profit/(loss) after tax - continuing
activities 19.4 (12.2)
---------------------------------------- ----------- -------------
Operating cash flow before working
capital movements and realised hedges* 16.4 6.4
---------------------------------------- ----------- -------------
Net debt* (excluding capitalised fees) 9.7 13.2
Cash and cash equivalents 2.7 2.8
---------------------------------------- ----------- -------------
*these are alternative performance measures which are further
detailed in the financial review
Corporate & Financial Summary
-- Cash balances as at 30 June 2022 were GBP2.7 million (31
December 2021: GBP3.3 million) with net debt of GBP9.7 million (31
December 2021: GBP12.2 million), a reduction of GBP2.5 million
since year end.
-- Operating cash flow before working capital movements and
realised hedges in H1 2022 of GBP16.4 million (H1 2021: GBP6.4
million).
-- GBP2.8 million of capex incurred during six months to 30 June
2022. Net cash capex for FY 2022 expected to be GBP10.2 million,
primarily relating to our conventional assets. In addition, we have
GBP1.8 million of cash outflow in 2022 for projects executed
towards the end of 2021.
-- Successful Reserve Based Lending facility (RBL)
redetermination in July (a semi-annual recalculation), confirming
US$22.0 million of debt capacity. We had headroom of US$12.0
million (GBP10.3 million) as at 31 August 2022.
-- We are required to hedge our production under the RBL and as
at 31 August 2022, we had 70,000 bbls hedged with swaps at an
average price of $76.4/bbl and 35,000 bbls hedged with puts at a
floor price of $44.7 for 2022. We also have 60,000 bbls hedged with
swaps for H1 23 at $95.0/bbl.
-- The estimated Energy Profits Levy for the period ended 30 June 2022 is GBP0.2 million.
-- Ring fence tax losses of GBP263 million.
Operational Summary
-- Net production averaged 1,865 boepd in H1 2022 (H1 2021:
2,005 boepd) impacted by equipment failure as a run-on consequence
of COVID-19 supply chain issues.
-- Full year net production is now forecast to be in the range
of c.1,900-1,950 as we resolve the issues in H1 and wells come back
on-line. Underlying cash operating costs per boe anticipated to be
c.$40.4/boe (based on an exchange rate of GBP1:$1.24).
-- Moratorium on shale lifted in England and Government commits
to a review of energy regulation.
-- We continue to mature our growth opportunities within the
existing conventional assets, including our East Midlands projects
at Corringham and Glentworth.
-- An application to the Government's Green Heat Network Fund
(GHNF) for the Stoke-on-Trent geothermal project was made on 26
August 2022.
-- Applications for grant funding from the Public Sector
Decarbonisation Scheme will be made in partnership with the Carbon
Energy Fund to support the development of six geothermal schemes,
supplying renewable heat to NHS Trusts.
A results presentation will be available at
http://www.igasplc.com/investors/presentations .
Qualified Person's Statement
Ross Pearson, Technical Director of IGas Energy plc, and a
qualified person as defined in the Guidance Note for Mining, Oil
and Gas Companies, March 2006, of the London Stock Exchange, has
reviewed and approved the technical information contained in this
announcement. Mr Pearson has 21 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, Director of Corporate Affairs
Investec Bank plc (NOMAD and Joint Corporate Broker)
Tel: +44 (0)20 7597 5970
Virginia Bull/Jeremy Ellis
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
Introduction and Market Backdrop
The first half of 2022 has been dominated by the tragic events
in Ukraine which impacted already tight energy markets and has
created an energy crisis with high prices affecting people and
businesses.
Oil prices remain around the $100/bbl mark albeit subject to the
vagaries of global supply and demand but European gas prices
continue to be at record highs and as we look into the second half
of the year gas rationing in Europe and potentially the UK is a
real prospect. Never more than now has energy security been of such
critical importance and has been so much in the public eye. IGas,
with its decades of experience of producing energy onshore in the
UK, is uniquely placed to be able to deliver domestic energy,
helping with both energy security and achieving the UK's net zero
targets.
The domestic and international demand for oil and gas will
continue to be strong for many decades. In the transition to 2050,
there is a continuing need for oil and gas, alongside renewable
energy sources. On projections by the Climate Change Committee
(CCC) and the National Grid Future Energy Scenarios the UK will
have a significant import dependency for oil and particularly gas
in the period to 2050 and beyond. This import dependency already
exists and is growing with the Department for Business, Energy and
Industrial Strategy (BEIS) showing that in 2021 net energy imports
increased by 41 per cent to help meet demand. Gas continued to be
the dominant fossil fuel, generating 123.2 TWh of electricity in
2021, an increase of 11 per cent from 2020.
The increase in the oil price in recent months has been a
welcome boost to revenue and cash generation giving us greater
financial flexibility. We successfully completed the scheduled
six-monthly RBL facility redetermination process. The
redetermination exercise confirmed c. GBP18 million of debt
capacity.
Looking forward we anticipate an ongoing oil price volatility
driven by uncertainties around the level of disruption to Russian
supply, the capacity for increased OPEC+ supply, the ongoing impact
of COVID-19 on demand and the impact of the conflict in Ukraine on
economic growth.
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.
Last week, the UK Government, in response to the energy and
cost-of-living crises, announced a lifting of the moratorium on
shale gas in England and committed to undertake a review of energy
regulation. We look forward to working constructively with
Government to deliver timely shale gas production in the national
interest, as well as working closely with local communities to
ensure they share in the benefits of domestic shale gas
development.
The decarbonisation of large scale heat remains a significant
unresolved problem for the country. Some 44 per cent of the UK's
energy demand is for heating homes and other buildings, which
accounts for 37 per cent of the UK's greenhouse gas emissions. The
CCC have stated that only decarbonisation of heat in the UK could
deliver the major reduction in emissions needed to meet the 2050
net zero target. We firmly believe that deep geothermal is the only
utility scale source of renewable heat suitable for deployment in
urban areas. Now that specific provision has been made for drilling
of geothermal wells in the Government's GHNF this gives us a
clearer line of sight to development as we firm up a number of
rapidly emerging opportunities. Moving to geothermal heat is not
only a desire from off-takers, such as network operators and large
heat users such as councils, universities and hospitals as they
seek to decarbonise but has the benefit of being a truly
competitive solution in a landscape of increased gas prices.
Board Changes
In a separate announcement made today, the Board of IGas
announces that it has appointed Chris Hopkinson, Non-Executive
Chairman, to the role of Interim Executive Chairman. Stephen
Bowler, CEO, will leave IGas, by mutual consent, with immediate
effect. Also announced today, Frances Ward has been appointed as
Chief Financial Officer and a Board Director of the Company, with
immediate effect.
Chris Hopkinson 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, Chris took over the role of
Chairman from Cuth McDowell who had served as Interim Non-executive
Chair since October 2019 and on the Board since December 2012.
In February 2022, IGas also welcomed Kate Coppinger to the Board
who took over the role of Chair of the Audit committee from Cuth
McDowell in June 2022.
On 1 July 2022, Tushar Kumar resigned from the Board as a
Non-executive Director.
Energy Profits Levy
The Government announced on 26 May 2022 that it would introduce
an Energy Profits Levy on UK production, and this passed into
legislation on 14 July 2022.
The Levy took effect from 26 May 2022, and based on current
forecasts - oil price of $94/bbl and FX of $1.20:GBP1.00 for
remainder of 2022 - we estimate a payment under the Levy of
c.GBP0.5 million in respect of 2022, taking into account our
current capital expenditure plans. Given that the Levy is part of a
package that includes significant investment incentives, we are
evaluating additional projects that could be brought forward to
offset the impact.
Despite efforts by the industry there have been no changes to
the draft legislation and expenditure for investment relief for
example, in geothermal, which currently sits outside of the UK
ring-fence tax regime has not been included.
Production Operations
Net production for the period averaged 1,864 boepd (H1 2021:
2,005 boepd), impacted by equipment failure as a run-on consequence
of COVID-19 supply chain issues. We now anticipate net production
in the range of c.1,900-1,950 boepd for the full year as we resolve
the issues in H1 and wells come back on-line.
Operating cash flow before working capital movements is expected
to be c.GBP19.7 million in 2022 based on a forecast average oil
price of $94/bbl for the remainder of the year.
Operating costs are now forecast to be c. $40.4/bbl driven
primarily by increased energy costs and general price increases on
equipment, offset by a more favourable foreign exchange rate.
However, positively, given IGas is a net exporter of electricity,
there is a forecast net benefit to IGas of GBP1.1 million,
equivalent to $1.9/boe.
Despite the challenges of the follow-on impacts of COVID-19 on
the supply chain and in maintaining staffing levels across the
operations, our teams have worked exceptionally hard over the last
six months.
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 allows for the resumption of c.50 bbls/d of
suspended production to be brought back on line. The project has
also provided more operational flexibility in handling produced
water in the Stockbridge area.
In February 2022, we announced the publication of a CPR by
DeGolyer & MacNaughton (D&M), a leading international
reserves and resources auditor.
The report comprised an independent evaluation of IGas
conventional oil and gas interests as of 31 December 2021. The full
report can be found on the IGas website
www.igasplc/investors/publications-and-reports .
IGas Group Net Reserves & Contingent Resources as at
31December 2021 (MMboe)
1P 2P 2C
Reserves & Resources as at 31 December 2020 11.74 17.12 20.34
Production during the period (0.71) (0.71) -
Revision of estimates (0.46) (0.62) -
Reserves & Resources as at 31 December 2021 10.57 15.79 20.34
The report values our conventional assets at c. $190 million on
a 2P NPV10 basis (based on a forward oil curve of c. $67/bbl for
2022-2024 and then escalated at an average rate of 2.5%
thereafter).
Development Assets
Oil and Gas
We are progressing a number of development opportunities across
our portfolio. Whilst all at different stages of maturity they
have, in aggregate, the potential to add, in the medium term, an
initial c.900 boepd and a further c.500 boepd in subsequent phases
.
Two of those development opportunities are in the East Midlands.
The first is an infill drilling project at Corringham which has the
potential to add c.100 bbls/d and 0.35 mmstb 2P reserves in 2023.
The project has existing planning permission, we are now in the
process of discharging the conditions of planning and we applied to
the Environment Agency in May 2022 for the necessary
permitting.
The second, is a larger appraisal/development project to extend
one of our existing fields at Glentworth. Our proposal is for the
construction of a new wellsite, to the west of our existing
Glentworth-K oil production site. The full development is to drill
an appraisal well and up to 7 horizontal development wells. This
opportunity will be progressed in a phased approach, with a
planning application for phase 1 to be submitted in Q4 2022.
If phase 1, the appraisal well with a horizontal side-track is
successful, this will be followed by further development drilling
in subsequent years. The first phase of the project is targeting an
additional c.200 bbls/d and development of c.1.0 mmstb 2P reserves
with the subsequent development having the potential to add an
additional 500bbls/d and the addition of c.2mmstb 2P reserves.
Geothermal
In March 2022, the UK Government put its full support behind
deep geothermal energy by launching the GHNF. The GHNF 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 the drilling of deep geothermal wells and
associated works. The GHNF opened to applications in March 2022 and
confirmed that it will fund up to 50 percent of a project's total
combined commercialisation and construction costs. As the developer
of the Stoke-on-Trent geothermal project, we have applied jointly
with Scottish and Southern Energy (SSE), the developer of the
associated district heat network, for a capital grant in the second
round that closed on 26 August 2022.
Our discussions with SSE to finalise a Thermal Purchase
Agreement on the Stoke-on-Trent project are progressing well and we
expect to conclude these post decision from the GHNF on the grant
application, which we expect in Q4 2022.
In addition to the GHNF, applications for grant funding from the
Public Sector Decarbonisation Scheme will be made in partnership
with the Carbon Energy Fund to support the development of six
geothermal schemes, supplying renewable heat to NHS Trusts. The
Public Sector Decarbonisation Scheme, which provides grants for
public sector bodies to fund site decarbonisation, opened for
applications 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.
We have continued to have positive discussions with the UK
Government regarding future, longer-term financial support for the
deep geothermal industry. We have had several meetings with senior
ministers including the Secretary of State and a working group with
the Department for Business, Energy and Industrial Strategy (BEIS)
has been established to look at a financial model for the long-term
support of deep geothermal heat. BEIS has now commissioned 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.
In July 2022, we submitted written evidence to the Environmental
Audit Committee's inquiry into the role that geothermal
technologies can play in the UK' s journey to net zero.
The opportunities for using deep geothermal energy for heat in
the UK are significant. We continue to receive a high number of
enquiries and are in discussions with 15 off takers, across 15
separate sites which equates to over 100 megawatts of installed
heat generation.
Discussion continues with Manchester City Council (MCC). A site
has been identified and we are currently working through
commercials with MCC on the site.
A first site has now been agreed with Cornish Lithium and a work
programme is being agreed prior to finalising site specific
commercial terms.
Shale
On 5 April 2022, the Government announced that it had
commissioned the British Geological Survey (BGS) to advise on the
latest scientific evidence around shale gas extraction. This review
was delivered to BEIS on 5 July 2022.
We submitted evidence to the BGS which has been shared with both
BEIS and the North Sea Transition Authority (NSTA) formerly the Oil
and Gas Authority. The evidence we submitted was a research report
by Dr Tim Harper PhD.
As well as analysing the publicly available information from
Lancashire, in late 2020 Dr Harper was provided with proprietary
information from the Gainsborough Trough, information that had not
previously been made available to the BGS.
Key points of the report:
1. The data collected by IGas in the Gainsborough Trough over the past 5 years demonstrates:
a. We have a world class shale gas resource in the Gainsborough Trough; and
b. That when compared with other areas of the UK, the geology of
the Gainsborough Trough is much less complex.
2. There is a new method of looking at the likelihood of induced
seismicity occurring, which supplements the techniques we already
use. This method looks at the geomechanical history and setting of
the area and analyses 11 factors which affect the likelihood of
experiencing induced seismicity. Together with existing techniques,
these give us a good idea of how likely we are to experience
induced seismicity in a wider area and on a site by site basis.
3. Using this method to supplement already existing techniques,
the Gainsborough Trough, on a qualitative basis, can be
demonstrated to have a significantly lower chance of induced
seismicity when compared with the Bowland Basin in Lancashire.
4. The method means that this risk of induced seismicity can be
materially better understood. Further hydraulic fracturing in
multiple wells is required to test and calibrate the models
used.
On 8 September 2022, the UK Government announced a lifting of
the moratorium on shale gas in England alongside a review of energy
regulation, both parts of wider government policy addressing the
future of both energy supply and demand. We have always believed
the science, as well as the need for increased domestic production
of gas, supports a lifting of the moratorium. The country's shale
gas opportunity is enormous and aside from potentially reducing the
country's dependency on imports, particularly LNG, has many
benefits. LNG imports do not offer employment, tax take, business
rates, community benefits, energy security or a lower carbon
footprint supply. Domestically produced shale gas does. We have a
world-class resource in our assets in the Gainsborough Trough and
can demonstrate how shale can provide safe, secure and affordable
energy for the UK in the near term.
IGas has the potential to deliver five production well pads,
with each pad having up to 16 wells, which would supply three
million homes with initial production within 12-18 months with the
right Government support. We look forward to working constructively
with the new administration to achieve a streamlined regulatory
process that can deliver accelerated development of this strategic
natural resource.
Polling by YouGov has revealed renewed support for shale gas
extraction as the cost of living crisis bites.
YouGov's poll found that if local shale gas production meant a
reduction in bills for people in the community, then, excluding
don't knows, more than half of British adults (53%) would support
shale development .
Financial review
Income Statement
The Group generated revenue of GBP30.5 million in the first six
months of 2022 from sales of 316,171 barrels of oil, including
sales of third party oil, 6,231 Mwh of electricity and 938,203
therms of gas (H1 2021: revenue GBP16.6 million, sales of 330,984
barrels of oil, 7,112 Mwh of electricity and 1,247,946 therms of
gas). The higher revenue was driven by the improvement in Brent
prices, which averaged $107.6/bbl during H1 2022 compared to
$64.9/bbl in H1 2021 as the war in Ukraine led to disrupted Russian
supply and global concerns over energy security. Limited OPEC
supply increases despite higher prices and increased demand as
economies started to recover from the impacts of the COVID-19
pandemic also supported prices. Revenue was also increased by a
weakening of sterling versus the US dollar with an average USD/GBP
rate of $1.29/GBP1 in H1 2022 compared to $1.39/GBP1 in H1 2021.
The Group incurred a realised loss on oil price hedges reflecting
the higher market prices.
Adjusted EBITDA for H1 2022 was GBP10.7 million (H1 2021: GBP2.7
million) and the profit after tax from continuing activities was
GBP19.4 million (H1 2021: loss of GBP12.2 million). The main
factors explaining the movements between H1 2022 and H1 2021 were
as follows:
-- Revenues of GBP30.5 million (H1 2021: GBP16.6 million) were
higher than the first half of 2021 due to higher oil prices as
described above;
-- DD&A increased to GBP2.7 million (H1 2021: GBP2.4 million);
-- Operating costs increased to GBP10.8 million (H1 2021: GBP8.6
million). We saw the impact of higher commodity prices on operating
costs, particularly in electricity costs which increased by
GBP0.4m. However, as a net electricity exporter, we had a net
revenue of GBP0.5 million for the period. Operating costs were also
higher due to higher staff costs, inflationary increases in
materials and equipment costs and additional workover and
maintenance activity;
-- Administrative expenses increased to GBP2.8 million (H1 2021:
GBP2.3 million) primarily due to higher staff and national
insurance costs and a lower allocation to capital projects. This
was partially offset by lower premises costs;
-- Exploration and evaluation assets of GBP6.5 million relating
to PEDL 184 were written off during the year following the
rejection of planning consent on appeal for a well test of the
Ellesmere Port-1 well. This licence, whilst prospective, is outside
our core shale exploration area and, as the Group have no plans for
further activity on the licence in the short term, the full
capitalised amount has been written off (H1 2021: GBP10.1
million);
-- An impairment reversal of GBP10.5 million (H1 2021: GBPnil)
was recognised on oil and gas assets during the period due to
higher oil prices. 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;
-- A loss was recognised on oil price derivatives of GBP7.5
million (H1 2021: GBP5.4 million loss). We are required to hedge
our production under the RBL with hedges being executed on a
rolling 12 month basis and the loss was generated due to an
increase in the Brent oil benchmark;
-- Increased net finance costs of GBP2.9 million (H1 2021:
GBP1.8 million) were mainly due to foreign exchange losses on our
US$ denominated debt offset by a lower unwinding of discount on
provisions;
-- A tax credit of GBP13.2 million was recognised in the period
(H1 2021: credit GBP1.9 million) principally due to an increase in
the deferred tax asset relating to the value of recognised tax
losses available for offset against future taxable profits as a
result of an increase in oil prices. No charge has been included
for the 25% levy on ringfence profits subsequent to 26 May 2022
under the Energy (Oil and Gas) Profits Levy Bill, as this was not
enacted before the period end. We estimate that the levy payable
related the period to 30 June 2022 is c.GBP0.2 million; and
-- IGas has ring fence tax losses of GBP263 million as at 30 June 2022.
Cash Flow
Net cash generated from operations after cash hedge losses and
before working capital movements in the period amounted to GBP10.6
million (H1 2021: GBP3.7 million). The Group invested GBP2.9
million across its asset base in the period (H1 2021: GBP2.6
million). GBP2.5 million (H1 2021: GBP1.7 million) was invested in
conventional assets, primarily to convert an existing, suspended
well in the Stockbridge field to a water disposal well allowing
c.50 bbls/d of suspended production to be brought back on line. The
project will also provide more operational flexibility in handling
produced water in the Stockbridge area. We also invested in smaller
projects to upgrade existing facilities and systems and optimise
production at a number of sites. GBP0.3 million (H1 2021: GBP0.8
million) was invested primarily in working up additional
exploration opportunities on conventional assets.
Higher operating cashflows enabled us to repay GBP4.6 million
($6.0 million) of principal on borrowings under the RBL facility
(H1 2021: net drawdown of GBP1.4 million ($2.0 million)). We
continue to have significant headroom under the facility.
IGas paid GBP0.4 million ($0.4 million) in interest (H1 2021:
GBP0.5 million ($0.6 million)). The impact of lower outstanding
balances was partially offset by increasing interest rates and a
stronger US$. Repayment of obligations under leases was GBP0.9
million (H1 2021: GBP0.8 million).
Cash and cash equivalents were GBP2.7 million at the end of the
period (31 December 2021: GBP3.3 million).
Balance Sheet
Net assets were GBP88.5 million at 30 June 2022 (31 December
2021: GBP68.6 million). The increase is related primarily to the
reversal of impairment of oil and gas assets offset by an
impairment of exploration and evaluation assets, an increase in
deferred tax assets and reductions to borrowings.
Shareholder's equity increased by GBP19.9 million to GBP88.5
million (31 December 2021 GBP68.6 million).
Non-IFRS Measures
The Group uses non-IFRS measures of performance that are not
specifically defined under IFRS or other generally accepted
accounting principles. The non-IFRS measures include net debt,
adjusted EBITDA, underlying cash operating costs and operating cash
flow before working capital movements and realised hedges, which
are considered by the Company to be useful additional measures to
help understand underlying performance.
Net Debt
Net debt, being borrowings excluding capitalised fees less cash
and cash equivalents, decreased to GBP9.7 million at 30 June 2022
(31 December 2021: GBP12.2 million; 30 June 2021: GBP13.2 million).
The Group's definition of net debt does not include the Group's
lease liabilities.
Six months Six months
ended ended Year ended
30 June 30 June 31 December
2022 2021 2021
GBPm GBPm GBPm
----------- ----------- -------------
Debt (nominal value excluding
capitalised expenses) (12.4) (16.0) (15.5)
----------- ----------- -------------
Cash and cash equivalents 2.7 2.8 3.3
----------- ----------- -------------
Net Debt (9.7) (13.2) (12.2)
----------- ----------- -------------
Adjusted EBITDA
Adjusted EBITDA includes adjustments in relation to non-cash
items such as share-based payment charges and unrealised gain/loss
on hedges along with other one-off exceptional items, and after
deducting lease rentals capitalised under IFRS 16.
Six months Six months Year ended
ended ended 31 December
30 June 30 June 2021
2022 2021
GBPm GBPm GBPm
----------- ----------- -------------
Profit/(loss) before tax 6.2 (14.2) (12.3)
----------- ----------- -------------
Net finance costs 2.9 1.8 3.9
----------- ----------- -------------
Changes in fair value of
contingent consideration - 0.2 (0.6)
----------- ----------- -------------
Depletion, depreciation &
amortisation 2.7 2.5 4.9
----------- ----------- -------------
Impairment (reversals)/write-offs (2.5) 10.1 10.5
----------- ----------- -------------
EBITDA 9.3 0.4 6.4
----------- ----------- -------------
Lease rentals capitalised
under IFRS 16 (0.9) (0.8) (1.5)
----------- ----------- -------------
Share-based payment charges 0.6 0.5 0.9
----------- ----------- -------------
Unrealised loss on hedges 1.7 2.6 0.1
----------- ----------- -------------
Adjusted EBITDA 10.7 2.7 5.9
----------- ----------- -------------
Underlying cash operating costs
Six months Six months Year ended
ended ended 31 December
30 June 30 June 2021
2022 2021
GBPm GBPm GBPm
----------- ----------- -------------
Other cost of sales 10.9 8.6 19.1
----------- ----------- -------------
Lease rentals capitalised
under IFRS 16 0.9 0.8 1.5
----------- ----------- -------------
Underlying cash operating
costs 11.8 9.4 20.6
----------- ----------- -------------
Operating cash flow before working capital movements and
realised hedges
Six months Six months Year ended
ended ended 31 December
30 June 30 June 2021
2022 2021
GBPm GBPm GBPm
----------- ----------- -------------
Operating cash flow before
working capital movements 10.6 3.7 7.4
----------- ----------- -------------
Realised loss on oil price
derivatives 5.8 2.7 6.6
----------- ----------- -------------
Operating cash flow before
working capital movements
and realised hedges 16.4 6.4 14.0
----------- ----------- -------------
Principal risks and uncertainties
The Group constantly monitors the Group's risk exposures and
management reports to the Audit Committee and the Board on a
regular basis. The Audit Committee receives and reviews these
reports and focuses on ensuring that the effective systems of
internal financial and non-financial controls including the
management of risk are maintained. The results of this work are
reported to the Board which in turn performs its own review and
assessment.
The principal risks for the Group remain as previously detailed
on pages 20-21 of the 2021 Annual Report and Accounts and can be
summarised as:
-- Political risk such as change in Government or the effect of
local or national referendums which can result in changes to the
regulatory or fiscal regime;
-- Strategy, and its execution, fails to meet shareholder expectations;
-- Climate change risks that causes changes to laws,
regulations, policies, obligations and social attitudes relating to
the transition to a lower carbon economy which could have a cost
impact or reduced demand for hydrocarbons for the Group and could
impact our Strategy;
-- Cyber security risk that gives exposure to a serious
cyber-attack which could affect the confidentiality of data, the
availability of critical business information and cause disruption
to our operations;
-- Planning, environmental, licensing and other permitting risks
associated with its operations and, in particular, with drilling
and production operations;
-- Oil or gas production, as no guarantee can be given that they
can be produced in the anticipated quantities from any or all of
the Group's assets or that oil or gas can be delivered
economically;
-- Development of shale gas resources not successful;
-- Loss of key staff;
-- Pandemic that impacts the ability to operate the business effectively;
-- Oil market price risk through variations in the wholesale
price in the context of the production from oil fields it owns and
operates;
-- Gas and electricity market price risk through variations in
the wholesale price in the context of its future unconventional
production volumes;
-- Exchange rate risk through both its major source of revenue
and its major borrowings being priced in US$ while most of the
Group's operating and G&A costs are denominated in UK pounds
sterling;
-- Liquidity risk through its operations; and
-- Capital risk resulting from its capital structure, including
operating within the covenants of its RBL facility.
Going concern
The Group continues to closely monitor and manage its liquidity
risks. Cash flow forecasts for the Group are regularly produced
based on, inter alia, the Group's production and expenditure
forecasts, management's best estimate of future oil prices,
management's best estimate of foreign exchange rates and the
Group's available loan facility under the RBL. Sensitivities are
run to reflect different scenarios including, but not limited to,
possible further reductions in commodity prices, strengthening of
sterling and reductions in forecast oil and gas production
rates.
The Group's operating cash flows have improved in 2022 as a
result of improving commodity prices and we have successfully
completed the May 2022 redetermination. However, the ability of the
Group to operate as a going concern is dependent upon the continued
availability of future cash flows and the availability of the
monies drawn under its RBL, which is redetermined semi-annually
based on various parameters (including oil price and level of
reserves) and is also dependent on the Group not breaching its RBL
covenants. We also assumed that our existing RBL facility is
amortised in line with its terms, but is not refinanced or
extended, resulting a reduction in the facility to $7 million from
01 January 2024. To mitigate these risks, the Group has a hedging
policy with 70,000 bbls hedged for September to December 2022 using
swaps at an average price of $76/bbl and 35,000 bbls using puts
with an average price, net of premiums, of $45/bbl, and a further
60,000 bbls hedged for H1 23 using swaps at an average price of
$95/bbl.
Management has considered the impact of supply chain constraints
on the Group's operations. We have seen some impact on production
during 2022 but we have developed a number of contingency plans to
mitigate this and any future COVID-19 related disruptions. Many of
our sites are remotely manned and we are well equipped as a
business to ensure we maintain business continuity recognising that
our production comes from a large number of wells in a variety of
locations and we have flexibility in our off-take arrangements.
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 war and
sanctions imposed on Russia have led to concerns about oil and gas
supply disruption 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.
The Group's base case cash flow forecast was run with average
oil prices of $98/bbl for the remainder of 2022, falling to an
average of $90/bbl in 2023 and $80/bbl in Q1 24 based on the
forward curve, and a foreign exchange rate of $1.22/GBP1. Our
forecasts show that the Group will have sufficient financial
headroom to meet its financial covenants based on the existing RBL
facility for 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 $88/bbl for the remainder of 2022;
$80/bbl for H1 2023, falling to $75/bbl and $70/bbl for Q3 and Q4
2023,respectively, and $65/bbl for Q1 2024. We forecast an average
exchange rate of $1.26/GBP1.00 for the remainder of 2022, an
average of $1.29/GBP1.00 for 2023 and $1.30/GBP1.00 for Q1 2024.
Our downside case also included an average reduction in production
of 5% over the period. Management would take mitigating actions
including delaying capital expenditure and additional reductions in
costs in order to remain within the Group's debt liquidity
covenants 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 at least 12 months from
the date of approval of the financial statements.
Based on the analysis above, the Directors have a reasonable
expectation that the Group has adequate resources to continue in
existence for the foreseeable future and have concluded it is
appropriate to adopt the going concern basis of accounting in the
preparation of the financial statements.
Statement of Directors' responsibilities
The Directors confirm that these Condensed Interim Consolidated
Financial Statements have been prepared in accordance with
UK-adopted International Accounting Standard 34, 'Interim Financial
Reporting' ("IAS 34") and the AIM Rules for Companies; and these
Unaudited Interim results include:
a) a fair review of the information required (i.e., an
indication of important events and their impact and a description
of the principal risks and uncertainties for the remaining six
months of the financial year); and
b) a fair review of the information required on related party transactions.
By order of the Board,
Chris Hopkinson
Interim Executive Chairman
15 September 2022
Independent review report to IGas Energy plc
Report on the condensed consolidated interim financial
statements
Our conclusion
We have reviewed IGas Energy plc's condensed consolidated
interim financial statements (the "interim financial statements")
in the Unaudited Interim Results of IGas Energy plc for the 6 month
period ended 30 June 2022 (the "period").
Based on our review, nothing has come to our attention that
causes us to believe that the interim financial statements are not
prepared, in all material respects, in accordance with UK adopted
International Accounting Standard 34, 'Interim Financial Reporting'
and the AIM Rules for Companies.
The interim financial statements comprise:
-- the Condensed Interim Consolidated Balance Sheet as at 30 June 2022;
-- the Condensed Interim Consolidated Income Statement and
Condensed Interim Consolidated Statement of Comprehensive Income
for the period then ended;
-- the Condensed Interim Consolidated Cash Flow Statement for the period then ended;
-- the Condensed Interim Consolidated Statement of Changes in
Equity for the period then ended; and
-- the explanatory notes to the interim financial statements.
The interim financial statements included in the Unaudited
Interim Results of IGas Energy plc have been prepared in accordance
with UK adopted International Accounting Standard 34, 'Interim
Financial Reporting' and the AIM Rules for Companies.
Basis for conclusion
We conducted our review in accordance with International
Standard on Review Engagements (UK) 2410, 'Review of Interim
Financial Information Performed by the Independent Auditor of the
Entity' issued by the Financial Reporting Council for use in the
United Kingdom. A review of interim financial information consists
of making enquiries, primarily of persons responsible for financial
and accounting matters, and applying analytical and other review
procedures.
A review is substantially less in scope than an audit conducted
in accordance with International Standards on Auditing (UK) and,
consequently, does not enable us to obtain assurance that we would
become aware of all significant matters that might be identified in
an audit. Accordingly, we do not express an audit opinion.
We have read the other information contained in the Unaudited
Interim Results and considered whether it contains any apparent
misstatements or material inconsistencies with the information in
the interim financial statements.
Conclusions relating to going concern
Based on our review procedures, which are less extensive than
those performed in an audit as described in the Basis for
conclusion section of this report, nothing has come to our
attention to suggest that the directors have inappropriately
adopted the going concern basis of accounting or that the directors
have identified material uncertainties relating to going concern
that are not appropriately disclosed. This conclusion is based on
the review procedures performed in accordance with this ISRE.
However, future events or conditions may cause the group to cease
to continue as a going concern.
Responsibilities for the interim financial statements and the
review
Our responsibilities and those of the directors
The Unaudited Interim Results, including the interim financial
statements, are the responsibility of, and have been approved by
the directors. The directors are responsible for preparing the
Unaudited Interim Results in accordance with the AIM Rules for
Companies which require that the financial information must be
presented and prepared in a form consistent with that which will be
adopted in the Company's annual financial statements. In preparing
the Unaudited Interim Results, including the interim financial
statements, the directors are responsible for assessing the Group's
ability to continue as a going concern, disclosing, as applicable,
matters related to going concern and using the going concern basis
of accounting unless the directors either intend to liquidate the
Group or to cease operations, or have no realistic alternative but
to do so.
Our responsibility is to express a conclusion on the interim
financial statements in the Unaudited Interim Results based on our
review. Our conclusion, including our Conclusions relating to going
concern, is based on procedures that are less extensive than audit
procedures, as described in the Basis for conclusion paragraph of
this report. This report, including the conclusion, has been
prepared for and only for the Company for the purpose of complying
with the AIM Rules for Companies and for no other purpose. We do
not, in giving this conclusion, accept or assume responsibility for
any other purpose or to any other person to whom this report is
shown or into whose hands it may come save where expressly agreed
by our prior consent in writing.
PricewaterhouseCoopers LLP
Chartered Accountants
London
15 September 2022
Condensed Interim Consolidated Income Statement
Unaudited Unaudited Audited
6 months 6 months year ended
ended ended 31 December
30 June 30 June 2021
2022 2021 GBP000
Notes GBP000 GBP000
-------------------------------------------- ----- --------- --------- -------------
Revenue 4 30,456 16,574 37,916
Cost of sales
Depletion, depreciation and amortisation (2,651) (2,379) (4,794)
Other costs of sales (10,850) (8,608) (19,105)
-------------------------------------------- ----- --------- --------- -------------
Total cost of sales (13,501) (10,987) (23,899)
Gross profit/(loss) 16,955 5,587 14,017
Administrative expenses (2,849) (2,314) (5,827)
Exploration and evaluation assets written
off 9 (6,517) (10,097) (10,463)
Oil and gas assets net impairment reversal 10 8,977 - -
Loss on oil price derivatives (7,458) (5,370) (6,715)
Operating profit/(loss) 9,108 (12,194) (8,988)
Finance income 5 3 135 2
Finance costs 5 (2,877) (1,893) (3,850)
Changes in fair value of contingent
consideration 12 - (230) 570
Profit/ (loss) from continuing activities
before tax 6,234 (14,182) (12,266)
Income tax credit 6 13,187 1,942 6,230
-------------------------------------------- ----- --------- --------- -------------
Profit/ (loss) after tax from continuing
operations attributable to shareholders'
equity 19,421 (12,240) (6,036)
Loss after tax from discontinued operations 7 - (106) (203)
-------------------------------------------- ----- --------- --------- -------------
Net profit/ (loss) for the period/year
attributable to shareholders' equity 19,421 (12,346) (6,239)
-------------------------------------------- ----- --------- --------- -------------
Earnings/ (Loss) attributable to equity
shareholders from continuing
operations:
Basic earnings/ (loss) per share 8 15.45p (9.78p) (4.82p)
Diluted earnings/ (loss) per share 8 14.33p (9.78p) (4.82p)
-------------------------------------------- ----- --------- --------- -------------
Earnings/ (Loss) attributable to equity
shareholders including discontinued
operations:
Basic earnings/ (loss) per share 8 15.45p (9.87p) (4.98p)
Diluted earnings/ (loss) per share 8 14.33p (9.87p) (4.98p)
-------------------------------------------- ----- --------- --------- -------------
Condensed Interim Consolidated Statement of Comprehensive
Income
Unaudited Unaudited Audited
6 months 6 months year ended
ended ended 31 December
30 June 30 June 2021
2022 2021 GBP000
GBP000 GBP000
------------------------------------------ --------- --------- -------------
Profit/ (loss) for the period/year 19,421 (12,346) (6,239)
Other comprehensive income/(loss) for the
period/year:
Currency translation adjustments recycled
to the income statement (note 7) - 326 326
Total comprehensive profit/ (loss) for
the period/year 19,421 (12,020) (5,913)
------------------------------------------ --------- --------- -------------
Condensed Interim Consolidated Balance Sheet
Unaudited Unaudited Audited
At 30 June At 30 June At 31December
2022 2021 2021
Notes GBP000 GBP000 GBP000
------------------------------------- ----- ----------- ------------ --------------
Assets
Non-current assets
Intangible assets 9 32,337 37,661 38,322
Property, plant and equipment 10 84,010 73,264 74,583
Right-of-use assets 6,980 7,458 7,017
Restricted cash 410 410 410
Deferred tax asset 6 51,362 33,888 38,176
175,099 152,681 158,508
------------------------------------- ----- ----------- ------------ --------------
Current assets
Inventories 1,414 1,094 1,092
Trade and other receivables 7,701 5,289 5,509
Cash and cash equivalents 13 2,681 2,755 3,289
11,796 9,138 9,890
------------------------------------- ----- ----------- ------------ --------------
Total assets 186,895 161,819 168,398
------------------------------------- ----- ----------- ------------ --------------
Liabilities
Current liabilities
Trade and other payables (6,948) (4,588) (6,863)
Derivative financial instruments 11 (3,112) (3,897) (1,410)
Lease liabilities (831) (720) (815)
Provisions 12 (5,798) (358) (2,419)
(16,689) (9,563) (11,507)
------------------------------------- ----- ----------- ------------ --------------
Non-current liabilities
Borrowings 13 (11,817) (15,123) (14,836)
Other creditors (586) (970) (770)
Lease liabilities (6,265) (6,667) (6,362)
Provisions 12 (63,016) (67,591) (66,307)
(81,684) (90,351) (88,275)
Total liabilities (98,373) (99,914) (99,782)
------------------------------------- ----- ----------- ------------ --------------
Net assets 88,522 61,905 68,616
------------------------------------- ----- ----------- ------------ --------------
Equity
Capital and reserves
Called up share capital 14 30,333 30,333 30,333
Share premium account 14 103,035 102,969 102,992
Foreign currency translation reserve 3,799 3,799 3,799
Other reserves 36,699 35,676 36,257
Accumulated deficit (85,344) (110,872) (104,765)
------------------------------------- ----- ----------- ------------ --------------
Total equity 88,522 61,905 68,616
------------------------------------- ----- ----------- ------------ --------------
Condensed Interim Consolidated Statement of Changes in
Equity
Called Foreign
up Share currency
share premium translation Other Accumulated Total
capital account reserve** Reserves*** deficit Equity
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
---------------------------------- -------- -------- ------------- ------------ ----------- --------
At 1 January 2021 (audited) 30,333 102,906 3,473 35,117 (98,526) 73,303
Loss for the period - - - - (12,346) (12,346)
Share options issued and vested
under the employee share plan
(note 14) - 63 - 559 - 622
Currency translation adjustments* - - 326 - - 326
---------------------------------- -------- -------- ------------- ------------ ----------- --------
At 30 June 2021 (unaudited) 30,333 102,969 3,799 35,676 (110,872) 61,905
Profit for the period - - - - 6,107 6,107
---------------------------------- -------- -------- ------------- ------------ ----------- --------
Share options issued and vested
under the employee share plan
(note 14) - 23 - 581 - 604
At 31 December 2021 (audited) 30,333 102,992 3,799 36,257 (104,765) 68,616
Profit for the period - - - - 19,421 19,421
Share options issued and vested
under the employee share plan
(note 14) - 43 - 442 - 485
At 30 June 2022 (unaudited) 30,333 103,035 3,799 36,699 (85,344) 88,522
---------------------------------- -------- -------- ------------- ------------ ----------- --------
* The only other comprehensive income for the six months to 30
June 2021 comprises the currency translation adjustments recycled
to the income statement. There was no other comprehensive income in
the six month periods to 31 December 2021 and 30 June 2022.
** The foreign currency translation reserve represents exchange
gains and losses on translation of previously held foreign currency
subsidiaries' net assets and results, and on translation of those
subsidiaries' intercompany balances, which formed part of the net
investment of the Group. During the year ended 31 December 2021, we
commenced the liquidation process for the remaining of these
foreign currency subsidiaries' and control over these entities was
transferred to the administrators. This process is ongoing at 30
June 2022.
*** Other reserves include: 1) EIP/MRP/LTIP/VCP/EDRP reserves
which represent the cost of share options issued under the long
term incentive plans; 2) share investment plan reserve which
represents the cost of the partnership and matching shares; 3)
treasury shares reserve which represents the cost of shares in IGas
Energy plc purchased in the market and previously held by the IGas
Employee Benefit Trust (EBT) to satisfy awards held under the Group
incentive plans; 4) capital contribution reserve which arose
following the acquisition of IGas Exploration UK Limited; and 5)
merger reserve which arose on the reverse acquisition of Island Gas
Limited.
Condensed Interim Consolidated Cash Flow Statement
Notes Unaudited Unaudited Audited
6 Months 6 Months year
ended ended ended
30 June 30 June 31 December
2022 2021 2021
GBP000 GBP000 GBP000
Cash flows from operating activities:
Profit/ (Loss) from continuing activities
before tax for the period/year 6,234 (14,182) (12,266)
Depletion, depreciation and amortisation 2,664 2,475 4,903
Abandonment costs/other provisions utilised (841) (122) (356)
Share-based payment charge 585 467 878
Exploration and evaluation assets written-off 9 6,517 10,097 10,463
Oil and gas assets impairment reversal 10 (10,489) - -
Oil and gas assets impairment 10 1,512 - -
Change in unrealised loss on oil price
derivatives 11 1,702 2,626 138
Change in unrealised loss on foreign
exchange contracts - 314 315
Changes in fair value of contingent consideration 12 - 230 (570)
Finance income 5 (3) (135) (2)
Finance costs 5 2,877 1,893 3,850
Other non-cash adjustments (185) (1) 9
Operating cash flow before working capital
movements 10,573 3,662 7,362
(Increase)/decrease in trade and other
receivables and other financial assets (2,294) (1,103) (1,637)
(Decrease)/increase in trade and other
payables (130) 352 1,699
(Increase)/decrease in inventories (320) (71) (69)
Cash from continuing operating activities 7,829 2,840 7,355
--------------------------------------------------- ------ ---------- ---------- -------------
Cash used in discontinued operating activities - (124) (221)
--------------------------------------------------- ------ ---------- ---------- -------------
Net cash from operating activities 7,829 2,716 7,134
--------------------------------------------------- ------ ---------- ---------- -------------
Cash flows from investing activities:
Purchase of intangible exploration and
evaluation assets (263) (794) (734)
Purchase of property, plant and equipment (2,500) (1,743) (3,905)
Purchase of intangible development assets (88) (35) (167)
Interest received 3 5 2
--------------------------------------------------- ------ ---------- ---------- -------------
Cash used in continuing investing activities (2,848) (2,567) (4,804)
Net cash used in investing activities (2,848) (2,567) (4,804)
--------------------------------------------------- ------ ---------- ---------- -------------
Cash flows from financing activities:
Cash proceeds from issue of ordinary
share capital 14 22 21 40
Drawdown on Reserves Based Lending facility 13 - 1,432 1,432
Repayment on Reserves Based Lending facility 13 (4,648) - (756)
Repayment of principal portion of lease
liability (590) (484) (747)
Repayment of interest on lease liabilities (307) (340) (684)
Interest paid 13 (390) (454) (812)
Net cash from/(used in) financing activities (5,913) 175 (1,527)
--------------------------------------------------- ------ ---------- ---------- -------------
Net increase/(decrease) in cash and
cash equivalents during the period /year (932) 324 803
Net foreign exchange difference 324 (7) 48
Cash and cash equivalents at the beginning
of the period /year 3,289 2,438 2,438
---------------------------------------------------
Cash and cash equivalents at the end
of the period /year 13 2,681 2,755 3,289
--------------------------------------------------- ------ ---------- ---------- -------------
Notes to the Unaudited Condensed Interim Consolidated Financial
Statements
1 Corporate information
The unaudited condensed interim consolidated financial
statements of IGas Energy plc and subsidiaries (the Group) for the
six months ended 30 June 2022, which are unaudited, were authorised
for issue in accordance with a resolution of the Directors on 15
September 2022.
IGas Energy plc is a public limited company incorporated and
domiciled in England whose shares are publicly traded on the AIM
market. The Group's principal activity is exploring for,
appraising, developing and producing oil and gas resources in the
UK. The Group is also diversifying into the wider UK energy markets
and is appraising geothermal and hydrogen projects.
2 Accounting policies
Basis of preparation
These unaudited condensed interim consolidated financial
statements for the six months ended 30 June 2022 have been prepared
in accordance with UK-adopted International Accounting Standard 34,
'Interim Financial Reporting' ("IAS 34") and the AIM Rules for
Companies. The unaudited condensed interim consolidated financial
statements should be read in conjunction with the consolidated
financial statements for the year ended 31 December 2021, which
have been prepared in accordance with UK-adopted International
Accounting Standards.
The financial information contained in this document does not
constitute statutory accounts as defined by Section 435 of the
Companies Act 2006 (England & Wales). The financial information
as at 31 December 2021 is based on the statutory accounts for the
year ended 31 December 2021. A copy of the statutory accounts for
that year, has been delivered to the Register of Companies and is
available on the Company's website at www.igasplc.com. The
auditors' report in accordance with Chapter 3 Part 16 of the
Companies Act 2006 in relation to those accounts was unqualified
and did not contain any matters on which the auditors are required
to report an exception in accordance with section 498 (2) and (3)
of the Companies Act 2006.
The accounting policies adopted are consistent with those of the
previous financial year and corresponding interim reporting period,
except for the new and amended standards and interpretations
discussed below.
Going concern
The Group continues to closely monitor and manage its liquidity
risks. Cash flow forecasts for the Group are regularly produced
based on, inter alia, the Group's production and expenditure
forecasts, management's best estimate of future oil prices,
management's best estimate of foreign exchange rates and the
Group's available loan facility under the RBL. Sensitivities are
run to reflect different scenarios including, but not limited to,
possible further reductions in commodity prices, strengthening of
sterling and reductions in forecast oil and gas production
rates.
The Group's operating cash flows have improved in 2022 as a
result of improving commodity prices and we have successfully
completed the May 2022 redetermination. However, the ability of the
Group to operate as a going concern is dependent upon the continued
availability of future cash flows and the availability of the
monies drawn under its RBL, which is redetermined semi-annually
based on various parameters (including oil price and level of
reserves) and is also dependent on the Group not breaching its RBL
covenants. 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 $7 million
from 01 January 2024. To mitigate these risks, the Group has a
hedging policy with 70,000 bbls hedged for September to December
2022 using swaps at an average price of $76/bbl and 35,000 bbls
using puts with an average price, net of premiums, of $45/bbl, and
a further 60,000 bbls hedged for H1 23 using swaps at an average
price of $95/bbl.
Management has considered the impact of supply chain constraints
on the Group's operations. We have seen some impact on production
during 2022 but we have developed a number of contingency plans to
mitigate this and any future COVID-19 related disruptions. Many of
our sites are remotely manned and we are well equipped as a
business to ensure we maintain business continuity recognising that
our production comes from a large number of wells in a variety of
locations and we have flexibility in our off-take arrangements.
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 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.
The Group's base case cash flow forecast was run with average
oil prices of $98/bbl for the remainder of 2022, falling to an
average of $90/bbl in 2023 and $80/bbl in Q1 24 based on the
forward curve, and a foreign exchange rate of $1.22/GBP1. Our
forecasts show that the Group will have sufficient financial
headroom to meet its financial covenants based on the existing RBL
facility for 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 $88/bbl for the remainder of 2022;
$80/bbl for H1 2023, falling to $75/bbl and $70/bbl for Q3 and Q4
2023, respectively, and $65/bbl for Q1 2024. We forecast an average
exchange rate of $1.26/GBP1.00 for the remainder of 2022, an
average of $1.29/GBP1.00 for 2023 and $1.30/GBP1.00 for Q1 2024.
Our downside case also included an average reduction in production
of 5% over the period. Management would take mitigating actions
including delaying capital expenditure and additional reductions in
costs in order to remain within the Group's debt liquidity
covenants 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 at least 12 months
from the date of approval of the financial statements.
Based on the analysis above, the Directors have a reasonable
expectation that the Group has adequate resources to continue in
existence for the foreseeable future and have concluded it is
appropriate to adopt the going concern basis of accounting in the
preparation of the financial statements.
New and amended standards and interpretations
During the period, the Group adopted the following new and
amended IFRSs for the first time for their reporting period
commencing 1 January 2022:
Amendments to IFRS 3 Reference to the Conceptual Framework
Amendments to IAS 16 Property, Plant and Equipment-Proceeds
before Intended Use
Amendments to IAS 37 Onerous Contracts-Cost of Fulfilling
a Contract
Annual Improvements to IFRS Amendments to IFRS 1 First-time Adoption
Standards 2018-2020 Cycle of International Financial Reporting
Standards, IFRS 9 Financial Instruments,
IFRS 16 Leases, and IAS 41 Agriculture
These standards do not have a material impact on the Group in
the current or future reporting periods. There are no other
standards that are not yet effective and that would be expected to
have a material impact on the entity in the current or future
reporting periods.
Estimates and judgements
The preparation of the unaudited condensed interim consolidated
financial statements requires management to make judgements,
estimates and assumptions that affect the application of accounting
policies and the reported amounts of assets and liabilities, income
and expense. Actual results may differ from these estimates.
In preparing these unaudited condensed interim consolidated
financial statements, the significant judgements made by management
in applying the Group's accounting policies and the key sources of
estimation uncertainty were the same as those applied to the
consolidated financial statements for the year ended 31 December
2021.
Financial risk management
The Group's activities expose it to a variety of financial
risks; market risk (including interest rate, commodity price and
foreign currency risks), credit risk and liquidity risk.
The unaudited condensed interim consolidated financial
statements do not include all financial risk management information
and disclosures required in the annual financial statements; they
should be read in conjunction with the Group's annual financial
statements as at 31 December 2021.
3 Basis of consolidation
The unaudited condensed interim consolidated financial
statements present the results of IGas Energy plc and its
subsidiaries as if they formed a single entity. The financial
information of subsidiaries used in the preparation of these
unaudited condensed interim consolidated financial statements are
based on consistent accounting policies to those of the Company.
All intercompany transactions and balances between Group companies,
including unrealised profits/losses arising from them, are
eliminated in full. Where shares are issued to an Employee Benefit
Trust, and the Company is the sponsoring entity, it is treated as
an extension of the entity.
4 Revenue
The Group derives revenue solely within the United Kingdom from
the transfer of goods and services to external customers which is
recognised at a point in time when the performance obligation has
been satisfied by the transfer of goods. The Group's major product
lines are:
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2022 2021 2021
GBP000 GBP000 GBP000
------------------------------ ----------- ---------- -------------
Oil sales 27,343 15,284 33,254
Electricity sales 1,394 550 2,048
Gas sales 1,719 740 2,614
------------------------------ ----------- ---------- -------------
Revenue for the period /year 30,456 16,574 37,916
------------------------------ ----------- ---------- -------------
5 Finance income and costs
Unaudited Unaudited Audited
6 months 6 months year
ended ended ended
30 June 30 June 31 December
2022 2021 2021
GBP000 GBP000 GBP001
--------------------------------------------------- ----------- ---------- -------------
Finance income:
Interest on short-term deposits 3 1 2
Foreign exchange gains - 134 -
Finance income for the period /year 3 135 2
--------------------------------------------------- ----------- ---------- -------------
Finance expense:
Interest on borrowings (439) (448) (812)
Amortisation of finance fees on borrowings (134) (165) (267)
Foreign exchange loss (1,181) - (151)
Unwinding of discount on decommissioning
provisions (note 12) (816) (811) (1,659)
Unwinding of discount on contingent consideration
(note 12) - (129) (277)
Finance charge on lease liability for assets
in use (307) (340) (684)
--------------------------------------------------- ----------- ---------- -------------
Finance expense for the period /year (2,877) (1,893) (3,850)
--------------------------------------------------- ----------- ---------- -------------
6 Tax on profit on ordinary activities
The Group calculates the period income tax expense using the UK
corporation tax rate that would be applicable to expected total
annual earnings for the 12 months ended 31 December 2022 (40% for
UK ring fenced activities and 19% for all other UK activities). The
effective tax rate for the period is -212% (six months ended 30
June 2021: 13%, year ended 31 December 2021: 50%), reflecting the
deferred tax credit of GBP13.2 million in the period as a result of
a higher recognition of deferred tax losses primarily due to higher
forecast commodity prices. The major components of income tax
expense in the unaudited condensed interim consolidated income
statement are:
Unaudited Unaudited
6 months 6 months Audited
ended ended year ended
30 June 30 June 31 December
2022 2021 2021
GBP000 GBP000 GBP000
-------------------------------------------- ---------- --------- -------------
UK corporation tax
Charge on loss for the period/year - - -
Total current tax charge - - -
-------------------------------------------- ---------- --------- -------------
Deferred tax
Charge/(credit) relating to the origination
or reversal of temporary differences (13,187) (1,526) (6,360)
Credit due to tax rate changes - (416) (393)
Credit in relation to prior periods - - 523
Total deferred tax credit (13,187) (1,942) (6,230)
-------------------------------------------- ---------- --------- -------------
Tax credit on loss on ordinary activities
for the period/year (13,187) (1,942) (6,230)
-------------------------------------------- ---------- --------- -------------
A deferred tax asset of GBP51.4 million (30 June 2021: GBP33.9
million, 31 December 2021: GBP38.2 million) has been recognised in
respect of tax losses and other temporary differences where the
Directors believe that it is probable that these assets will be
recovered based on estimated taxable profit forecast.
The Energy (Oil and Gas) Profits Levy Bill, which introduces an
additional 25% levy on ringfence profit was substantially enacted
in July 2022. The estimated impact of this is discussed within Note
15, Subsequent events.
7 Loss after tax from discontinued operations
The divestment of assets acquired as part of the Dart
Acquisition, namely the Rest of the World segment, was completed in
2016. The Group had a presence in a small number of Australian,
Indian and Singaporean registered operations and we have continued
the liquidation process for the remaining of these overseas dormant
subsidiaries, with control over these entities currently with
administrators. The total loss after tax in respect of discontinued
operations was GBPnil (six months ended 30 June 2021: loss after
tax of GBP0.1 million; year ended 31 December 2021: loss after tax
of GBP0.2 million, primarily relating to the recycling of the
currency translations reserve administration costs).
Effect of liquidation/strike off on the financial
statements:
Unaudited Unaudited
6 months 6 months Audited
ended ended year ended
30 June 30 June 31 December
2022 2021 2021
GBP000 GBP000 GBP000
-------------------------------------------- ------------ ----------- -------------
Other receivables - (10) (11)
Cash and cash equivalents - (20) (118)
Other payables - 15 15
Net assets and liabilities disposed - (15) (114)
-------------------------------------------- ------------ ----------- -------------
Disposal consideration - - -
-------------------------------------------- ------------ ----------- -------------
Translation reserve re-classification to
income statement on liquidation/strike off - (326) (326)
Loss on liquidation/strike off charged
to the income statement - (341) (440)
-------------------------------------------- ------------ ----------- -------------
8 Earnings per share (EPS)
Basic EPS amounts are based on the profit from continuing
operations for the period after taxation attributable to ordinary
equity holders of the parent of GBP19.4 million (six months ended
30 June 2021: a loss after tax of GBP12.2 million; year ended 31
December 2021: a loss after tax of GBP6.0 million) and the weighted
average number of ordinary shares outstanding during the period of
125.7 million (six months ended 30 June 2021: 125.1 million; year
ended 31 December 2021: 125.3 million).
Diluted EPS amounts are based on the profit/ loss for the
period/ year after taxation attributable to the ordinary equity
holders of the parent and the weighted average number of shares
outstanding during the period/ 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.
There are 9.8 million potentially dilutive employee share
options (six months ended 30 June 2021: 11.7 million, year ended 31
December 2021: 11.7 million). These are included in the calculation
of diluted earnings per share in the current period. These were not
included in the calculation in prior periods as their conversion to
ordinary shares would have decreased the loss per share.
9 Intangible assets
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2022 30 June 2021 31 December 2021
GBP'000 GBP'000 GBP'000
--------------------------------- ---------------------------------- ----------------------------------
Exploration Exploration Exploration
and Develop- and Develop- and Develop-
evaluation ment evaluation ment evaluation ment
assets costs Total assets costs Total assets costs Total
----------------- ------------ --------- -------- ------------ --------- --------- ------------ --------- ---------
Cost
At 1 January 34,844 3,478 38,322 43,421 3,290 46,711 43,421 3,290 46,711
Additions 321 101 422 621 38 659 888 188 1,076
Changes in
decommissioning
(note 12) 110 - 110 388 - 388 998 - 998
Amounts written
off (6,517) - (6,517) (10,097) - (10,097) (10,463) - (10,463)
At 30 June/
31 December 28,758 3,579 32,337 34,333 3,328 37,661 34,844 3,478 38,322
----------------- ------------ --------- -------- ------------ --------- --------- ------------ --------- ---------
Exploration and evaluation assets
Exploration costs written off in the period to 30 June 2022 were
GBP6.5 million (6 months to 30 June 2021: GBP10.1 million, year
ended 31 December 2021: GBP10.5 million) of which GBP6.4 million
related to the PEDL 184 (Ellesmere Port) and GBP0.1 million related
to trailing costs on relinquished licences. The 2021 exploration
costs written off substantially all related to the relinquishment
of the PEDL 200 (Tinker Lane) licence.
Further analysis by location of asset is as follows:
North West: The group has GBPnil (H1 2021: GBP6.3 million, year
ended 31 December 2021: GBP6.4 million) of capitalised exploration
expenditure relating to Ellesmere Port, with the full capitalised
amount of GBP6.4 million being written off in the period. This
follows the rejection of planning consent on appeal for a well test
in the Ellesmere Port-1 well. This licence, whilst prospective, is
outside our core shale exploration area and, as the Group have no
plans for further activity on the licence in the short term, the
full capitalised amount has been written off.
East Midlands: The group has GBP23.5 million (H1 2020: GBP23.1
million, year ended 31 December 2021: GBP23.2 million) of
capitalised exploration expenditure relating to our core area in
the Gainsborough Trough which includes PEDLs 12, 139, 140, 169 and
210. The Gainsborough Trough is an area with significant shale
potential. Following the moratorium on fracking, we engaged with
the NSTA and the Department for Business, Energy and Industrial
Strategy (BEIS) to demonstrate that we can develop shale in this
area in a safe manner. Our discussions have focused on the new
science that would be brought forward on a sector wide and site
specific basis that would allow the moratorium to be lifted. On 5
April 2022, the Government announced that it had commissioned the
British Geological Survey (BGS) to advise on the latest scientific
evidence around shale gas extraction. This review, which we
provided scientific evidence to, was delivered to BEIS on 5 July
2022. We believe the science, as well as the need for increased
domestic production of gas, should support a lifting of the
moratorium. We also have confidence that we can develop our assets
in a safe manner as we firmly believe that the geo-mechanics of the
Gainsborough Trough present a significantly reduced risk of induced
seismicity of the type experienced elsewhere in the UK. The
evidence submitted to the BGS review has been shared with both BEIS
and NSTA, and we continue our engagement with NSTA, BEIS and other
industry participants. As the discussions regarding the moratorium
are still ongoing, the Directors consider that it is appropriate to
continue to capitalise this asset.
Conventional assets: The Group has GBP5.2 million (six months
ended 30 June 2021: GBP4.9 million, year ended 31 December 20201:
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
30 June 2022 and assessed it for impairment indicators. The
development of the Stoke-on-Trent project has taken longer than
anticipated initially due to COVID-19 and more recently on account
of delays on receiving certainty on a Government support mechanism.
The UK Government launched the Green Heat Network Fund (GHNF) in
March 2022 which will support the commercialisation and
construction of new low and zero carbon heat networks including the
drilling of deep geothermal wells and associated works. The GHNF
opened to applications in March 2022 and confirmed that it will
fund up to 50% of a project's total combined commercialisation and
construction costs. We have applied for funding for the
Stoke-on-Trent project and expect to hear the outcome in Q4 2022.
Our discussions with SSE to finalise a Thermal Purchase Agreement
on the Stoke-on-Trent project are also progressing. The delayed
timing does not adversely impact the overall economics of the
project materially and a successful outcome on our grant
application to the GHNF will significantly de-risk the project. On
this basis, the group has concluded that there are no impairment
indicators as at 30 June 2022. No impairment was required for the
period ( year ended 31 December 2021 : GBPnil).
10 Property, plant and equipment
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2022 30 June 2021 31 December 2021
GBP'000 GBP'000 GBP'000
------------------------------ ---------------------------- ----------------------------
Oil Oil Oil
and Other and Other and Other
gas fixed gas fixed gas fixed
assets assets Total assets assets Total assets assets Total
---------------------- --------- -------- --------- -------- -------- -------- -------- -------- --------
Cost
At 1 January 215,222 2,430 217,652 209,225 2,951 212,176 209,225 2,951 212,176
Additions 2,773 - 2,773 1,152 - 1,152 3,700 - 3,700
Disposals - 3 3 - (518) (518) - (521) (521)
Changes in
decommissioning
(note 12) (206) - (206) 1,591 - 1,591 2,297 - 2,297
At 30 June/ 31
December 217,789 2,433 220,222 211,968 2,433 214,401 215,222 2,430 217,652
---------------------- --------- -------- --------- -------- -------- -------- -------- -------- --------
Depreciation and
Impairment
At 1 January 142,034 1,035 143,069 138,233 1,504 139,737 138,233 1,504 139,737
Charge for the
period/year 2,109 8 2,117 1,879 39 1,918 3,801 52 3,853
Disposals - 3 3 - (518) (518) - (521) (521)
Impairment 1,512 - 1,512 - - - - - -
Impairment reversal (10,489) - (10,489) - - - - - -
At 30 June/ 31
December 135,166 1,046 136,212 140,112 1,025 141,137 142,034 1,035 143,069
---------------------- --------- -------- --------- -------- -------- -------- -------- -------- --------
Net book value at
30 June/ 31 December 82,623 1,387 84,010 71,856 1,408 73,264 73,188 1,395 74,583
---------------------- --------- -------- --------- -------- -------- -------- -------- -------- --------
Impairment of oil and gas properties
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. 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 hence
performed a detailed exercise to determine the amount of reversal
as at 30 June 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.
The impairment assessment was prepared on a fair value less
costs of disposal basis using discounted future cash flows based on
2P reserve profiles. The future cash flows were estimated using
nominal price assumptions for Brent of between $80-100/bbl for the
years 2022-2026 and $65/bbl thereafter. A foreign exchange rate of
between $1.25:GBP1.00 and $1.35:GBP1.00 was used. Cash flows were
discounted using a post-tax discount rate of 9%.
This resulted in a recoverable amount greater than the carrying
amount by GBP16.0 million at the South CGU and GBP0.8 million at
the North CGU. We have capped the impairment reversal recorded at
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 at the North CGU as
reasonable downside cases indicated that an impairment could be
required if certain sensitivities were applied. Therefore, the
factors that lead to the initial impairment 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 GBP1.5m was recognised, as
it is not expected that all past costs would be recovered through
the development of the site.
Sensitivity of changes in assumptions
The principal assumptions are recoverable future production and
resources, 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 are shown
below:
CGU 10% reduction 10% reduction USD/GBP foreign Discount
in price in production exchange rate @ 10%
rate @ $1.4
GBPm GBPm GBPm GBPm
-------------- --------------- ---------------- ------------
North (7.88) (8.72) (3.28) (1.77)
South (6.06) (5.98) (3.54) (1.62)
Scotland (0.91) (0.75) (0.41) (0.13)
-------------- --------------- ---------------- ------------
Total (14.85) (15.45) (7.23) (3.52)
-------------- --------------- ---------------- ------------
The sensitivity analysis above does not take into account any
mitigating actions available to management should these changes
occur.
11 Financial Instruments - fair value disclosure
The Group uses the following hierarchy for determining and
disclosing the fair value of the financial instruments by valuation
technique:
-- Level 1: quoted (unadjusted) prices in active markets for identical assets or liabilities;
-- Level 2: other valuation techniques for which all inputs
which have a significant effect on the recorded fair value are
observable, either directly or indirectly; and
-- Level 3: valuation techniques which use inputs which have a
significant effect on the recorded fair value that are not based on
observable market data.
There are no non-recurring fair value measurements nor have
there been any transfers between levels of the fair value
hierarchy.
There were no financial assets measured at fair value. The
financial liabilities measured at fair value are categorised into
the fair value hierarchy as at the reporting dates as follows:
Level Unaudited Unaudited
6 months 6 months Audited
ended ended year ended
30 June 30 June 31 December
2022 2021 2021
GBP'000 GBP'000 GBP'000
----------------------------------- ------ ---------- ---------- ------------
Financial liabilities:
Derivative financial instruments -
oil hedges 2 (3,112) (3,897) (1,410)
Contingent consideration (note 12) 3 (2,731) (3,383) (2,731)
At 30 June /31 December (5,843) (7,280) (4,141)
----------------------------------- ------ ---------- ---------- ------------
Fair value of derivative financial instruments
Commodity price hedges
The fair values of the commodity price options were provided by
counterparties with whom the trades have been entered into. These
consist of Asian style put and call options and swaps to sell/buy
oil. The options are valued using a Black-Scholes methodology;
however, certain adjustments are made to the spot-price volatility
of oil prices due to the nature of the options. These adjustments
are made either through Monte Carlo simulations or through
statistical formulae. The inputs to these valuations include the
price of oil, its volatility, and risk free interest rates.
Fair value of other financial assets and financial
liabilities
The fair values of all other financial assets and financial
liabilities are considered to be materially equivalent to their
carrying values.
12 Provisions
Unaudited Unaudited Audited
6 months ended 6 months ended year ended
30 June 2022 30 June 2021 31 December 2021
GBP'000 GBP'000 GBP'000
-------------------------------------------- ------------------------------------- -------------------------------------
Decommis- Decommis-
Decommis-sioning Contingent sioning Contingent sioning Contingent
provision consideration Total provision consideration Total provision consideration Total
----------------- ----------------- -------------- --------- ---------- -------------- --------- ---------- -------------- ---------
At 1 January (65,995) (2,731) (68,726) (61,819) (3,024) (64,843) (61,819) (3,024) (64,843)
Acquisitions - - -
Utilisation
of provision 632 - 632 43 - 43 778 - 778
Unwinding of
discount (note
5) (816) - (816) (811) (129) (940) (1,659) (277) (1,936)
Reassessment
of
decommissioning
provision (note
9 and 10) 96 - 96 (1,979) - (1,979) (3,295) - (3,295)
Changes in
fair value
of contingent
consideration - - - - (230) (230) - 570 570
At 30 June/
31 December (66,083) (2,731) (68,814) (64,566) (3,383) (67,949) (65,995) (2,731) (68,726)
----------------- ----------------- -------------- --------- ---------- -------------- --------- ---------- -------------- ---------
Less current
portion 5,518 280 5,798 - 358 358 2,139 280 2,419
----------------- ----------------- -------------- --------- ---------- -------------- --------- ---------- -------------- ---------
Non-current (60,565) (2,451) (63,016) (64,566) (3,025) (67,591) (63,856) (2,451) (66,307)
----------------- ----------------- -------------- --------- ---------- -------------- --------- ---------- -------------- ---------
Decommissioning provision
The Group spent GBP0.6 million on decommissioning activities
during the period (six months ended 30 June 2021: GBP0.0 million;
year ended 31 December 2021: GBP0.8 million).
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 39 years from period end (30 June 2021: 1 to 37 years; 31
December 2021: 1 to 30 years). The provisions are based on the
Group's internal estimate as at 30 June 2022. Assumptions are based
on the current experience from decommissioning wells which
management believes is a reasonable basis upon which to estimate
the future liability. The estimates are based on a planned
programme of abandonments but also include a provision to be spent
in 2022-2025 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 2022 and 2023 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.
A risk free rate range of 2.27% to 3.00% is used in the
calculation of the provision as at 30 June 2022 (30 June 2021: Risk
free rate range of 1.2% to 3.00%, 31 December 2021: Risk free rate
range of 1.20% to 3.00%).
Management performed sensitivity analysis to assess the impact
of changes to the risk free rate on the Group's decommissioning
provision balance. A 0.5% decrease in the risk free rate would
result in an increase in the decommissioning provision by GBP3.5
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 GBP6.7
million.
Contingent consideration
The carrying value of contingent consideration relates to the
acquisition of GT Energy. The 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.
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.
13 Cash and cash equivalents and other financial assets
Unaudited Unaudited Audited
As at As at As at
30 June 30 June 31 December
2022 2021 2021
GBP000 GBP000 GBP000
----------------------------------------- ---------- ---------- -------------
Cash and cash equivalents 2,681 2,755 3,289
Borrowings - including capitalised fees (11,817) (15,123) (14,836)
----------------------------------------- ---------- ---------- -------------
Net debt (9,136) (12,368) (11,547)
Capitalised fees (535) (803) (669)
----------------------------------------- ---------- ---------- -------------
Net debt excluding capitalised fees at
30 June/31 December (9,671) (13,171) (12,216)
----------------------------------------- ---------- ---------- -------------
Net debt reconciliation
Cash and Borrowings Total
cash
equivalents GBP000 GBP000
GBP000
------------------------------ ------------- ----------- ---------
At 1 January 2021 2,438 (13,695) (11,257)
------------------------------ ------------- ----------- ---------
Interest paid on borrowings (454) - (454)
Drawdown of RBL 1,432 (1,432) -
Foreign exchange adjustments (7) 137 130
Other cash flows (654) - (654)
Other non-cash movements - (133) (133)
------------------------------ ------------- ----------- ---------
At 30 June 2021 2,755 (15,123) (12,368)
------------------------------ ------------- ----------- ---------
Interest paid on borrowings (358) - (358)
Repayment of RBL (756) 756 -
Foreign exchange adjustments 55 (335) (280)
Other cash flows 1,593 - 1,593
Other non-cash movements - (134) (134)
------------------------------ ------------- ----------- ---------
At 31 December 2021 3,289 (14,836) (11,547)
------------------------------ ------------- ----------- ---------
Interest paid on borrowings (390) - (390)
Repayment of RBL (4,648) 4,648 -
Foreign exchange adjustments 324 (1,494) (1,170)
Other cash flows 4,106 - 4,106
Other non-cash movements - (135) (135)
At 30 June 2022 2,681 (11,817) (9,136)
------------- ----------- ------------
Reserve Based Lending facility
On 3 October 2019, the Company announced that it had signed a
$40.0 million RBL facility with BMO Capital Markets (BMO). In
addition to the committed $40.0 million RBL, a further $20.0
million is available on an uncommitted basis, and can be used for
any future acquisitions or new conventional developments. The RBL
has a five-year term, an interest rate of USD LIBOR plus 4.0%,
matures in June 2024 and is secured on the Company's assets. The
RBL is subject to a semi-annual redetermination in May and November
when the loan availability will be recalculated taking into account
forecast commodity prices, remaining field reserves (assessed by an
independent reserves auditor annually) and the latest forecast of
operating and capital costs. On 2 August 2022, the Group announced
it had successfully completed the May 2022 redetermination which
confirmed an available facility limit of $22.0 million. Under the
terms of the RBL, the Group is subject to a financial covenant
whereby, as at 30 June and 31 December each year, the ratio of Net
Debt at the period end to Earnings before Interest, Tax,
Depreciation, Amortisation and Exceptional items (EBITDAX as
defined in the RBL agreement) for the previous 12 months shall be
less than or equal to 3.5:1. The Group complied with its covenants
for the six months ended 30 June 2022.
Collateral against borrowing
A Security Agreement was executed between BMO and IGas Energy
plc and some of its subsidiaries, namely; Island Gas Limited,
Island Gas Operations Limited, Star Energy Weald Basin Limited,
Star Energy Group Limited, Star Energy Limited, Island Gas
(Singleton) Limited, Dart Energy (East England) Limited, Dart
Energy (West England) Limited, IGas Energy Development Limited,
IGas Energy Enterprise Limited, Dart Energy (Europe) Limited and
IGas Energy Production Limited. Under the terms of this Agreement,
BMO have a floating charge over all of the assets of these legal
entities, other than property, assets, rights and revenue detailed
in a fixed charge. The fixed charge encompasses the Real Property
(freehold and/or leasehold property), the specific petroleum
licences, all pipelines, plant, machinery, vehicles, fixtures,
fittings, computers, office and other equipment, all related
property rights, all bank accounts, shares and assigned agreements
and rights including related property rights (hedging agreements,
all assigned intergroup receivables and each required insurance and
the insurance proceeds).
14 Share capital
Share Share
Ordinary shares Deferred shares capital premium
--------------------- ----------------------- --------- ---------
Nominal Nominal Nominal
value value value Value
No. GBP000 No. GBP000 GBP000 GBP000
---------------------------- ----------- -------- ------------ --------- --------- ---------
Issued and fully paid
At 1 January 2021 124,797,169 2 303,305,534 30,331 30,333 102,906
SIP issue partnership 185,212 - - - - 21
SIP issue matching 271,971 - - - - 42
At 30 June 2021 125,254,352 2 303,305,534 30,331 30,333 102,969
SIP issue partnership 118,555 - - - - 19
SIP issue matching 109,055 - - - - 4
Shares issued in respect of
MRP issues 13,543 - - - - -
At 31 December 2021 125,495,505 2 303,305,534 30,331 30,333 102,992
SIP issue partnership 154,872 - - - - 22
SIP issue matching 154,272 - - - - 21
Shares issued in respect of - - - -
MRP issues 8,307 -
---------------------------- ----------- -------- ------------ --------- --------- ---------
At 30 June 2022 125,812,956 2 303,305,534 30,331 30,333 103,035
---------------------------- ----------- -------- ------------ --------- --------- ---------
15 Subsequent events
On 25 May 2022, the Government announced the introduction of the
Energy Profits Levy, effective 26 May 2022. At the balance sheet
date, the proposal to introduce the Energy Profits Levy had not
been substantively enacted. Therefore, its effects are not included
in these financial statements. However, it was subsequently
substantively enacted on 11 July 2022. Had it been substantively
enacted by the balance sheet date it would have decreased the
deferred tax asset and credit for the period by GBP0.3 million and
generated a current tax expense of GBP0.2 million.
Glossary
GBP The lawful currency of the United Kingdom
$ The lawful currency of the United States of America
1P Low estimate of commercially recoverable reserves
2P Best estimate of commercially recoverable reserves
3P High estimate of commercially recoverable reserves
1C Low estimate or low case of Contingent Recoverable Resource
quantity
2C Best estimate or mid case of Contingent Recoverable Resource
quantity
3C High estimate or high case of Contingent Recoverable Resource
quantity
AIM AIM market of the London Stock Exchange
Bbl(s)/d Barrel(s) of oil per day
boepd Barrels of oil equivalent per day
bopd Barrels of oil per day
CCUS Carbon capture usage and storage
Contingent Recoverable Resource - Contingent Recoverable
Resource estimates are prepared in accordance with the Petroleum
Resources Management System (PRMS), an industry recognised
standard. A Contingent Recoverable Resource is defined as
discovered potentially recoverable quantities of hydrocarbons where
there is no current certainty that it will be commercially viable
to produce any portion of the contingent resources evaluated.
Contingent Recoverable Resources are further divided into three
status groups: marginal, sub -- marginal, and undetermined. IGas'
Contingent Recoverable Resources all fall into the undetermined
group. Undetermined is the status group where it is considered
premature to clearly define the ultimate chance of
commerciality.
Drill or drop - A drill or drop well carries no commitment to
drill. The decision whether or not to drill the well rests entirely
with the Licensee being driven by the results of geotechnical
analysis. The Licence will, however, still expire at the end of the
Initial Term if the well has not been drilled.
Firm well - A firm well is classified as a firm commitment to
drill a well. It is not contingent on any further geotechnical
evaluation (i.e. it is a fully evaluated Prospect).
GIIP Gas initially in place
m Million
Mbbl Thousands of barrels
MMboe Millions of barrels of oil equivalent
MMscfd Millions of standard cubic feet per day
PEDL United Kingdom petroleum exploration and development
licence
PL Production licence
Tcf Trillions of standard cubic feet of gas
UK United Kingdom
This information is provided by RNS, the news service of the
London Stock Exchange. RNS is approved by the Financial Conduct
Authority to act as a Primary Information Provider in the United
Kingdom. Terms and conditions relating to the use and distribution
of this information may apply. For further information, please
contact rns@lseg.com or visit www.rns.com.
RNS may use your IP address to confirm compliance with the terms
and conditions, to analyse how you engage with the information
contained in this communication, and to share such analysis on an
anonymised basis with others as part of our commercial services.
For further information about how RNS and the London Stock Exchange
use the personal data you provide us, please see our Privacy
Policy.
END
IR LIMMTMTTBTBT
(END) Dow Jones Newswires
September 15, 2022 02:02 ET (06:02 GMT)
Igas Energy (LSE:IGAS)
Historical Stock Chart
From Apr 2024 to May 2024
Igas Energy (LSE:IGAS)
Historical Stock Chart
From May 2023 to May 2024
