TIDMIGAS
RNS Number : 2896J
Igas Energy PLC
09 April 2020
THIS ANNOUNCEMENT CONTAINS INSIDE INFORMATION.
9 April 2020
IGas Energy plc (AIM: IGAS)
("IGas" or "the Company" or "the Group")
Full year results for the year ended 31 December 2019
IGas, one of the leading producers and explorers of hydrocarbons
onshore in Britain, announces its full year results for the year
ended 31 December 2019.
Results Summary
Year ended Year ended
31 Dec 2019 31 Dec 2018
GBPm GBPm
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Revenues 40.9 42.9
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Adjusted EBITDA 13.8 10.8
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Loss after tax(1) (49.8) (21.4)
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Operating cash flow before working
capital adjustments 14.3 11.6
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Net debt 6.2 6.4
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Cash and cash equivalents 8.2 15.1
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Notes
(1) Includes GBP53.9 million of exploration costs relating to NW
shale assets
Operational Summary
-- Net production averaged 2,325 boepd for the year (2018: 2,258
boepd), within guidance, while operating costs for the year were c.
$30/boe (at an average 2019 exchange rate of GBP1:$1.28) (2018:
$31.9/boe).
-- Whilst we still anticipate net production of between 2,250 -
2,450 boepd and operating costs of c.$27.5/boe (assuming an
exchange rate of GBP1:$1.20) in 2020, the challenging environment
and material uncertainty that exists could have future impacts on
the business.
-- DeGolyer & MacNaughton (D&M) CPR as at 31 December
2019 - IGas net reserves and resources* (MMboe):
1P 2P 2C
As at 31 Dec 2018 9.78 14.56 19.20
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As at 31 Dec 2019 10.55 16.05 19.60
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o Significant 2P reserves replacement 277% (1P 192%)
o 2P NPV10 of $183 million*
*based on forward oil curve of 2020 $61.78/bbl; 2021 $58.39/bbl;
2022 $56.97/bbl; 2023 $56.54/bbl; 2024 $57.67/bbl
-- Scampton and Welton waterflood projects expected to be online in summer 2020.
-- Significant exploration growth potential - identified
prospectivity > 1.8bn bbls OIIP across the portfolio.
Corporate and Financial Summary
-- $40 million Reserve Base Loan agreed in October 2019:
o Drawn down in November 2019 to repay secured bonds;
o Greater available capital to grow our conventional business;
and
o Reduction of financing costs of c. $1 million on an annualised
basis.
-- GBP16.5 million of free operating cash flow generated in 2019
from the conventional business before administrative expenses,
capital investment and finance costs.
-- Cash balances as at 31 December 2019 of GBP8.2 million and net debt of GBP6.2 million.
-- Underlying profit of GBP4.6 million (2018: GBP4.0 million).
Loss after tax of GBP49.8 million (2018: loss GBP21.4 million) due
to non-cash exploration write-offs of GBP53.9 million (2018:
GBP29.1 million).
-- As at 31 December 2019, the Group had hedged a total of
420,000 bbls for 2020, using a combination of puts (292,500 bbls at
an average downside protected price of $51.4/bbl) and fixed price
swaps (127,500 bbls at an average fixed price of $58.7/bbl).
-- In light of the current recent weakness of sterling against
the dollar, we hedged $9 million for 2020 at an average rate of
$1.17:GBP1 and $3 million for 2021 at an average rate of $1.20:GBP1
in March 2020.
-- In response to the current oil price environment, we have
revised our capex for 2020 to c. GBP6 million; comprising c. GBP2
million on our production assets and c. GBP4 million on development
assets.
-- In response to the changing environment we are looking to
maximise returns from our existing sites which could include
electricity generation and storage.
-- We are aligning our approach to sustainability with a number
of the UN Sustainable Development Goals.
Commenting today Stephen Bowler, Chief Executive Officer,
said:
"2019 saw production well within guidance and operating costs
marginally better than forecast.
IGas benefits from having a diversified production base which
generated GBP14 million in operating cash flow in 2019. Having
refinanced our debt in October 2019, now with a tenure out to 2024,
which alongside hedging for over 50% of our 2020 production at
US$53/bbl, means we are as well placed as possible in this highly
volatile marketplace.
I was delighted to report our significant reserves replacement,
at over 250%, and a 1P reserves life index of over 10 years,
underpinning both the longevity and potential upside in our
portfolio.
We have limited committed capex in 2020, and given the oil price
environment have trimmed our capital expenditure budget by GBP4
million to GBP6 million, with a focus on key capital projects. We
have a good portfolio of projects and will flex our capital
spending plans, if and when the oil price improves from its current
depressed level.
The Coronavirus pandemic is a deeply concerning international
public health emergency which everyone hopes to see contained
quickly. Our primary focus is the health and safety of our
employees and other stakeholders and we have acted promptly in that
regard. Many of our sites are remotely manned and at this stage we
are well equipped as a business to ensure we maintain business
continuity. We continue to liaise and co-operate with all the
relevant regulators.
Currently, the Group's operations continue to function as
normal. However, we cannot rule out future impacts on the business
given the material uncertainty that exists in the current
environment."
A results presentation will be available at
http://www.igasplc.com/investors/presentations.
Ross Pearson, Technical Director of IGas Energy plc, and a
qualified person as defined in the Guidance Note for Mining, Oil
and Gas Companies, March 2006, of the London Stock Exchange, has
reviewed and approved the technical information contained in this
announcement. Mr Pearson has 19 years oil and gas exploration and
production experience.
For further information please contact:
IGas Energy plc Tel: +44 (0)20 7993 9899
Stephen Bowler, Chief Executive Officer
Julian Tedder, Chief Financial Officer
Ann-marie Wilkinson, Director of Corporate Affairs
Investec Bank plc (NOMAD and Joint Corporate Broker) Tel: +44 (0)20 7597 5970
Sara Hale/Jeremy Ellis/Tejas Padalkar
BMO Capital Markets (Joint Corporate Broker) Tel: +44 (0)20 7653 4000
Tom Rider/Neil Elliot/Jeremy Low/Tom Hughes
Canaccord Genuity (Joint Corporate Broker) Tel: +44 (0)20 7523 8000
Henry Fitzgerald-O'Connor/James Asensio
Vigo Communications Tel: +44 (0)20 7390 0230
Patrick d'Ancona/Chris McMahon
Chairman's Statement
We continued to deliver on our strategic priorities and
generated strong operating cash flow in 2019, alongside further
reducing our financing costs through a $40 million Reserve Based
Lending Facility, which we secured in October 2019.
Nothwithstanding the uncertain political backdrop throughout the
year and challenging operational conditions, we have delivered
production well within guidance, made progress in advancing
incremental production projects and made a potentially world-class
gas discovery at our Springs Road well site.
In November 2019, the UK Government announced an effective
moratorium on hydraulic fracturing in Britain, based on analysis of
one well in Lancashire by the Oil and Gas Authority (OGA), until
new scientific evidence is provided in respect of the impacts of
seismicity during the process of hydraulic fracturing. We have been
working, and will continue to work closely, with the relevant
regulators to demonstrate that we can operate safely and
environmentally responsibly. We have done this to date in our shale
business, and across our existing c. 100 conventional wells that
have been operating onshore UK for many decades.
As an onshore operator, we have, and must continue to have, a
deep understanding of the potential environmental impacts and any
mitigating actions we must take. Each site and basin can have
substantially different geology. The OGA Report found that
susceptibility to seismicity depends strongly on a location's
specific geology with the mere presence of faulting or the
parameters of the injection possibly of less importance.
Whilst we are cognisant that the consumption of fossil fuels has
an impact on the environment, we maintain that the oil and gas
industry is an essential component in delivering secure, efficient
and cost-effective energy, as the world tries to balance its energy
requirements, and is a key enabler in the transition to increased
supply of renewable energy. Delivering a domestic source of
affordable energy is key to a nation's security of supply, growth
of its economy, heating homes and making a contribution to
satisfying the growth of energy demand.
We are committed to supporting the British Government's target
of reducing greenhouse gas emissions to net zero by 2050.
The Committee on Climate Change (CCC) in its May 2019 report,
clearly forecast a very significant UK gas demand out to 2050 and
beyond - approximately 70% of 2019 gas demand still existing in
2050 in a net zero scenario. Under the CCC's recommended pathway to
net zero CO(2) , this gas would be used as both a feedstock for
making hydrogen and a backup supply for generating electricity, and
they have recommended that we use domestically produced gas.
Without new supplies of gas it is expected that we will be
importing over 80% of our gas requirements by 2050 .
Engaging with communities local to our sites, and earning and
maintaining our social licence to operate is imperative to our
success as a business. We endeavour to build respectful, long-term
relationships and earn the trust of those who host our
activities.
Trust can only be earned, and kept, if people see that we share
their concerns and hopes for the future. They can only see that if
we are transparent about what we do and why we do it. Transparency
goes beyond publishing financial results; it is about being as open
as we can be with all our stakeholders.
The more transparent we are about our activities, the better
equipped our investors, communities and wider society are to decide
whether we merit their trust.
Across the Company we strive to achieve the highest standards of
health, safety and environmental protection. All of our production
and drilling operations retained their ISO 14001 and 9001
certifications and we were awarded the ROSPA Presidents Award
again, representing 13 years of commitment to Occupational Health
and Safety.
Board changes
In May 2019, Hans Årstad was appointed as a Non-executive
Director, exercising the right of KKR to take a seat on the Board
through their 14.7% investment in IGas. We welcome Hans to the
Board.
In October 2019, our Chairman, Mike McTighe stepped down for
personal reasons. We thank Mike for his considerable contribution
to the Company and valued leadership over the last three years.
People
All the teams around the business have worked incredibly hard
during 2019. Production teams in keeping the volumes on track,
finance and legal teams in securing the new reserves based lending
facility, our drilling and operational teams for the Springs Road
well which was drilled significantly ahead of schedule and budget,
and lands, planning and project teams for securing permissions and
advancing projects through to the execution phase. Thanks to all
the support teams around the business; it is you supporting all
these activities that enable us to achieve success.
Outlook
The Coronavirus pandemic is a deeply concerning international
public health emergency which everyone hopes to see contained
quickly. Our primary focus is the health and safety of our
employees and other stakeholders and we have acted promptly in that
regard.
We continue to monitor the situation closely and act within
Government guidelines and to that end we have worked up a number of
contingency plans should our operations be significantly affected
by the coronavirus.
In February 2020, the oil price began to be affected by the
global spread of COVID-19 and the resultant reduction in oil
demand. This situation has since been compounded by the failure of
OPEC to reach an agreement on constraining supply and the position
of Saudi Arabia to increase output.
Whilst we have better financial flexibility and a reduced
overall cost of debt, we have re-evaluated our priorities in the
short-term to ensure we weather the current oil price disruption.
However, if oil prices remain low for a prolonged period of time we
cannot rule out future impacts on the business given the material
uncertainty that currently exists.
In the longer term, we will continue to drive to maximise our
existing assets, many of which still have significant potential,
whilst developing new assets to deliver future shareholder value,
as we ensure IGas is an important part of the onshore UK energy
transition.
Chief Executive's Statement
Introduction
I am pleased to report a solid set of results for 2019, which
reflect a good operational performance across the business and
continued progress delivering our strategy of optimising our
existing assets and seeking to provide future energy solutions
through our world-class shale gas discovery at Springs Road in the
Gainsborough Trough.
In October 2019, we signed a $40 million Reserve Base Lending
facility with BMO Capital Markets. The facility reduces our overall
cost of debt and provides the financial flexibility for continued
investment into our conventional portfolio to grow our production
over the coming years.
Over recent weeks we have witnessed an unprecedented global
situation in the form of COVID-19 combined with depressed oil
prices.
Currently, the Group's operations continue to function as
normal. Of our 148 employees those that are able to work from home
have been doing so, in a phased way, since early March 2020. We
have approximately 65% of staff who are in operational roles and
have been identified as key workers by the Government. Many of
these are "lone" workers who had already been 'identified, trained
and equipped' pre-COVID-19 so the pandemic does not require a
significant change to existing procedures or protocols.
In respect of IGas's operational sites, our facilities are
designed with operational control provisions that ensure safe and
compliant operation within the normal operational envelope and
automated shutdown functionality should there be an unexpected
excursion outside of these routine conditions. In addition to these
local control and shutdown systems IGas has the ability to monitor
the site operations from remote locations utilising its digital
systems which allow efficient intervention by operational and
maintenance staff to be coordinated alongside the standard
monitoring visits that are conducted by our staff.
However, the inbuilt control systems are able to make any site
and well safe without the need for human intervention and we
continue to liaise with all our regulators.
Whilst we are reliant on transporting oil to UK refineries, we
have significant capacity for managing our production inventory.
All key contractors in terms of transport and refineries are also
classified as key workers.
Operating Review
Production
Production for the year was 2,325 boepd which was in the upper
end of the production target range of 2,200 - 2,400 boepd.
Production in our East Midlands assets benefited from the
success of waterflood and optimisation activities conducted in
2018, alongside 2019 projects being brought online ahead of
schedule and wells performing in the upper range of expectation.
These efforts resulted in not only the complete offset of the
annual decline rate but an uplift of overall production for the
year compared to that delivered in 2018. These results were also
mirrored in our southern operations, where following the successful
completion of our routine maintenance and integrity programs, and
the implementation of a series of optimisation works we were also
able to finish 2019 at a higher production rate than that delivered
in 2018. Our Gas to Wire and Gas to Grid facility at Albury
continued to improve during 2019 and by the close of the year we
were capable of achieving a peak maximum daily production rate of
c. 200 boepd from the combined export streams.
Reserves and Resources
In February 2020, IGas announced the publication of the full and
final results of the Competent Persons Report (CPR) by DeGolyer
& MacNaughton (D&M), a leading international reserves and
resources auditor.
The report comprised an independent evaluation of IGas
conventional oil and gas interests as of 31 December 2019. The full
report can be found on the IGas website
www.igasplc/investors/publications-and-reports
IGas Group Net Reserves & Contingent Resources as at 31(st)
Dec 2019 (MMboe)
1P 2P 2C
Reserves & Resources as at 31(st)
Dec 2018 9.78 14.56 19.20
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Production during the period (0.84) (0.84) -
======= ======= ======
Total change during the period 1.61 2.33 0.40
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Reserves & Resources as at 31(st)
Dec 2019 10.55 16.05 19.60
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The report confirms a continuing high reserves replacement of 2P
reserves of approximately 277% (1P 192%) reflecting the good
performance of our production assets and progression of projects
demonstrating the significant upside that remains in our
conventional portfolio. IGas has a track record of significant
reserves replacement with a three-year average of over 200%.
This independent report valued our conventional assets at c.
$180 million on a 2P NPV10 basis, an increase of $20 million
compared to 2018 (based on forward oil curve of 2020 $61.78/bbl;
2021 $58.39/bbl; 2022 $56.97/bbl; 2023 $56.54/bbl; 2024
$57.67/bbl).
Development - Conventional
We continue to mature our production portfolio opportunities and
achieved final approvals for our Scampton North Waterflood project
during the first half of 2019. This c. GBP2.0 million project to
install water injection capability and convert a suspended well
into a water injector has advanced significantly during the year,
with the project remaining on schedule and budget ready to deliver
initial production in the summer of 2020. This secondary recovery
project (waterflood) is forecast to double the current output of
the field to over 200 bopd and increase the ultimate recovery from
the field. The D&M CPR estimated 180 Mbbl of incremental 2P
(Proved plus Probable Undeveloped) reserves and our mid-case
economics for the project have an IRR of over 40% and a NPV of
GBP2.5 million (which assumes a long term oil price of
$55/bbl).
Following the success of the first phase of the Welton
waterflood project, the technical team recommended an additional
opportunity in the southern section of the Welton Field in the
Tupton & Deep Hard Rock Reservoirs. The project involves
converting a suspended production well (WC01) to a water injector
to improve reservoir sweep and increase field recovery by c. 660
Mbbl (2P reserves) with a peak incremental production rate of c.
100 bopd.
The Company's estimated base-case project economics have an IRR
of over 100% and a NPV10 of c.GBP7.0 million (which assumes a long
term oil price of $55/bbl). Positive well integrity and injectivity
tests allowed full sanction of the project in the third quarter of
2019, with engineering activities, regulatory approvals and long
lead items all being progressed in line with the project schedule,
with full completion planned by the summer of 2020.
This is part of the wider Welton Full Field Development and as
well as increasing production, will aid in de-risking further
injection projects into other areas of the field and provide
critical infrastructure to assist with water disposal and support
future rationalisation work across the Welton sites.
We have continued to mature other projects across the portfolio
as we seek to maximise returns on our existing operations and
infrastructure and will flex our capital spending plans, if and
when the oil price improves from its current depressed level.
For example, Bletchingley is a Gas Monetisation, gas-to wire
project which recently received planning approval. The project
involves the installation of up to 6MW of electrical generation
capability at the Bletchingley Central site fuelled by gas from the
Bletchingley 2 well, which is currently suspended. However, in
light of the current oil price, we have reduced our expenditure in
progressing projects such as this significantly and will not take
this project further forward until energy prices improve.
As part of our ongoing active portfolio management, we
relinquished two non-core PEDLs in the East Midlands, PEDL 137 and
PEDL 337.
Development - Shale
We mobilised a drill rig and ancillary equipment to our Springs
Road site in North Nottinghamshire in early January 2019 and
spudded the well on 22 January 2019. In mid-February 2019, we
encountered shales on prognosis, at c. 2,200 metres depth and
drilled through a significant hydrocarbon bearing shale sequence,
including the Upper and Lower Gainsborough Shale.
The well sought to assess three target zones: the Gainsborough
Shale; the Millstone Grit and the Arundian Shale. All three targets
were encountered, with c.400 m of Gainsborough Shale, the primary
target, with key shale attributes such as Total Organic Content,
kerogen type, and clay content akin to world class shale plays
observed in North America.
IGas acquired 147 metres of core within the Gainsborough Shale,
the first extensive core sample from this basin, which has
subsequently been analysed by Stratum Reservoir (formerly
Weatherford Labs) in their laboratories in both the UK and the USA.
The results from the core analysis confirm that a nationally
significant hydrocarbon resource is present in the Gainsborough
Trough.
The key characteristics of the Gainsborough Shale in the SR-01
well compare favourably to commercial shale operations observed in
North America such as the Eagle Ford, Barnett and the Marcellus.
The core results indicate a mature, organic rich source rock with
good porosity confirming favourable gas resource density, and,
additionally, the low clay content in large sections of the
Gainsborough shale is an encouraging indication of the suitability
for effective hydraulic fracture stimulation.
The analysis we have undertaken will help delineate the resource
potential and help refine the subsequent appraisal programme.
Working with our joint venture partners, IGas will now consider the
attributes of the data set alongside reprocessed 3D seismic for the
area. This will allow us to commence planning for both a future
potential appraisal programme and a pilot development within the
Gainsborough Trough, a geologically well understood and quiescent
basin.
As well as obtaining extremely positive geological results, the
two well drilling programme was highly successful operationally.
Both wells were drilled significantly under budget, principally due
to faster than expected drilling and coring rates. The Springs Road
well, the deepest penetration into the Gainsborough Trough to date,
was 25% under budget, despite obtaining 50% more core than planned.
Through our local sourcing programme, our direct East Midlands
spend through the two well drilling programme was in excess of
GBP10 million, supporting local, skilled jobs. Throughout
operations we were compliant with all stringent planning
permissions and environmental permits for both sites and have been
commended on the high standard of our operations by regulators and
the local community. Whilst protest did occur during the drilling
of the well at Springs Road, the level of protest was negligible
and generally took the form of monitoring as opposed to
obstruction.
The well that was drilled at Tinker Lane, which delineated the
southern extent of the Gainsborough Trough, was plugged and
abandoned earlier in the year and the site was fully restored to
farmland and handed back to the landowner in September 2019, ahead
of schedule.
In the North West, the Ellesmere Port appeal was recovered by
the Secretary of State (SoS) at the end of June 2019 in order to
determine a decision. The Planning Inspectorate then set a deadline
for the report and recommendation by the inquiry inspector of 23
January 2020. The recommendation was sent to the SoS in early
January 2020 and a decision was expected around 8 April 2020. We
have been informed that, similar to other decisions, this has now
been delayed until further notice.
In November 2019, the UK government announced an effective
moratorium on the process of hydraulic fracturing in England based
on a report by the Oil and Gas Authority (OGA) which found that it
is not currently possible to accurately predict the probability or
magnitude of earthquakes linked to fracking operations. The Report
found that susceptibility to seismicity depends strongly on a
location's specific geology with the mere presence of faulting or
the parameters of the injection possibly of less importance. Each
site and basin can have substantially different geology.
The company operates multiple licences across the East Midlands
and in the North West. In the East Midlands along with the OGA, we
are seeking to simplify and focus the various work programmes so
that more rapid and directed appraisal and then development of the
shale resource can take place. As such all licences are now on 2014
model clauses and have linked work plans.
The OGA has granted three-year extensions to the initial terms
on the following 14(th) round, Company operated licences: PEDL 189,
PEDL 235, PEDL 257, PEDL 273, PEDL 278, PEDL 305, PEDL 316 and PEDL
326.
Moving resources to reserves
Significant exploration potential exists in our prospective
resources.
In early July 2019, we announced plans for a proposed new site
in the Weald basin on PEDL 235, which IGas owns and operates 100%.
The intention is to drill up to two wells to explore and evaluate
the resource potential of both the Portland Sandstones and the
Kimmeridge Micrites.
The Portland Sandstone has an existing gas discovery (IGas 2C
resources includes c. 2.1 MMBoe
http://www.igasplc.com/media/40892/dm-2019-ye-cpr-2020.pdf and
technical studies conducted by the IGas team have concluded that
there is significant upside potential for the Portland reservoir to
be considerably larger with 5-10 MMboe of recoverable gas.
Additionally, the underlying Kimmeridge Micrite formations, has the
potential for a large additional resource.
Work has temporarily ceased on this project but when energy
prices improve we will seek to submit a planning application given
the significant returns available. As part of the planning process,
IGas would undertake community consultation to take account of
feedback from local residents before submitting the full planning
application.
Diversifying our energy portfolio
IGas has a wide land portfolio across the East Midlands and the
Weald basin where our well sites, gathering centres and pipelines
are located. As a part of broadening the Company's approach to
energy production, not least in light of its intentions to play an
important role in the UK's energy transition, work has commenced on
assessing various sites for their suitability for electricity
generation and storage as well as bio-methane production. Given the
current energy price environment we do not see these projects
coming to fruition in the short term.
Outlook
Given the fall in oil prices, we have reviewed our capital
expenditure programme for the year and reduced it principally to
maintenance capex, abandonment and capital for projects already in
execution. We will continue to review our priorities to ensure we
weather any prolonged depressed oil price scenario. There remains,
however, material uncertainty of the potential impact of Covid-19
on the Group's operational activities, future commodity prices and
the outcome of the May 2020 redetermination of the RBL.
The greater than 250% 2P reserves replacement demonstrates the
significant upside in our conventional portfolio and we continue to
identify and progress projects with short-term growth potential and
good returns even in this oil price environment.
The UK currently imports in excess of 50% of its energy
requirements. As we transition to becoming independent from the EU
and focus on our climate change ambitions, there is a growing need
to develop domestic energy sources, including oil and gas, which
have both economic and environmental advantages compared to
imports.
Whilst there is a clear need for oil and gas in a 2050 net zero
environment, we have also begun to look at ways of maximising
returns from our sites and high grading for potential opportunities
for electricity generation, storage and bio-methane production, as
we seek to ensure IGas positions itself as a flexible deliverer of
a variety of energy sources to the UK.
I am proud of our response, as a business, to the COVID-19
pandemic and want to thank all our colleagues for their
professionalism and "can do" attitude in such difficult times. We
continue to monitor and respond to the situation as it develops and
believe that we will come out of this a stronger and more cohesive
Company than ever before.
Financial Review
Results for the year
Oil prices remained volatile in 2019 with the average monthly
price of Brent crude ranging between $59/bbl and $71/bbl. The lower
average price of $64/bbl for the year versus $71/bbl for 2018 had a
negative impact on our revenues. The average GBP/USD exchange rate
for the year was GBP1: $1.28 (2018: GBP1: $1.34) which positively
impacted revenue for the year.
For the year ended 31 December 2019 adjusted EBITDA was GBP13.8
million (2018: GBP10.8 million) whilst a loss was recognised from
continuing activities after tax of GBP49.8 million (2018: loss
GBP21.4 million). The main factors driving the movements between
the years were as follows:
-- Revenues decreased to GBP40.9 million (2018: GBP42.9 million)
principally due to lower oil prices and a 3% decrease in oil sales
volumes. The decrease was partially offset by a weaker average
sterling to US dollar exchange rate and increased gas sales from
our Albury field which commenced production in November 2018;
-- Other costs of sales decreased to GBP20.5 million (2018:
GBP21.9 million). Operating costs were GBP1.4 million lower than
the prior year due to the capitalisation of operating lease costs
of GBP1.7 million on adoption of IFRS 16 and a refund for rent and
rates. The decrease was partially offset by an increase in
regulatory, production and workover costs;
-- Administrative expenses decreased by GBP1.0 million to GBP4.5
million (2018: GBP5.5 million). A continued focus on costs resulted
in lower staff, external consultants and premises costs;
-- The GBP53.9 million exploration expense relates primarily to
our shale assets in the North West. In November 2019, the UK
Government announced an effective moratorium on the process of
hydraulic fracturing in England. We will now work with industry
partners and government and should the moratorium be lifted we
would focus on our core area of the Gainsborough Trough in the
short to medium term. (2018: GBP29.1 million related to PEDL 145
Doe Green, an Albury well and various relinquished licences);
-- Goodwill of GBP4.8 million relating to the acquisition of
Dart shale assets has been written off due to the moratorium
announced by the government in November 2019; and
-- A tax credit of GBP9.3 million was recognised mainly due to
the recognition of a deferred tax asset relating to ring-fence tax
losses (2018: a tax credit of GBP3.7 million mainly due to the
recognition of a deferred tax asset relating to ring-fence tax
losses).
New Debt Facility Signed
IGas signed a $40 million senior secured Reserve-Based Lending
Facility (RBL) with BMO Capital Markets (BMO) in October 2019.
In addition to the committed $40 million RBL, a further $20
million accordion facility is available on an uncommitted basis,
subject to new bank commitments. The RBL has a five-year term, an
interest rate of LIBOR plus 4.0% and matures in September 2024. 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. The Company also exercised its call
option and issued a redemption notice with respect to all
outstanding bonds (Secured Bonds) pursuant to the 10 per cent. IGas
Energy PLC Senior Secured Callable Bond Issue 2013/2018 - ISIN NO
001 0673791. The Secured Bonds were redeemed at par value (100%)
plus accrued interest on the redeemed amount up until, but not
including, the settlement date of the call option on 19 November
2019. The proceeds from the new RBL were used to repay the Secured
Bonds and will be used to fund development opportunities in the
conventional portfolio and for general corporate purposes.
Income statement
The Group recognised revenues of GBP40.9 million for the year
(2018: GBP42.9 million). Group production for the year averaged
2,325 boepd (2018: 2,258 boepd). Revenues included GBP2.4 million
(2018: GBP2.4 million) relating to the sale of third party oil, the
bulk of which is processed through our gathering centre at
Holybourne in the Weald Basin.
The average pre-hedge realised price for the year was $61.7/bbl
(2018: $67.0/bbl) and post-hedge $60.1/bbl (2018: $57.4/bbl). A
loss of GBP1 million was realised on hedges during the year
primarily relating to the premium cost of puts (2018: realised loss
of GBP5.5 million). The average GBP/USD exchange rate for the year
was GBP1: $1.28 (2018: GBP1: $1.34) which positively impacted
revenue for the year.
Cost of sales for the year were GBP29.6 million (2018: GBP28.8
million) including depreciation, depletion and amortisation
(DD&A) of GBP9.1 million (2018: GBP6.8 million), and operating
costs of GBP20.5 million (2018: GBP21.9 million). Operating costs
were GBP1.4 million lower than the prior year due to a decrease
relating to the re-classification of operating leases under IFRS 16
of GBP1.7 million and a refund for rent and rates, partially offset
by an increase in regulatory, production and workover costs.
Operating costs include a cost of GBP2.2 million (2018: GBP2.3
million) relating to third party oil. The contribution received
from processing this third party oil was GBP0.2 million (2018:
GBP0.2 million).
Operating costs per barrel of oil equivalent (boe) were GBP23.6
($30.1), excluding third party costs (2018: GBP23.6 ($31.9) per
boe). The reduction was due to lower absolute operating costs and
higher production volumes.
Adjusted EBITDA in the year was GBP13.8 million (2018: GBP10.8
million). Gross profit for the year was GBP11.3 million (2018:
GBP14.2 million). Administrative costs decreased by GBP1.0 million
to GBP4.5 million (2018: GBP5.5 million) principally due to a
reduction in staff, external consultants and premises costs.
Exploration costs written off of GBP53.9 million relates to our
shale assets in the North West as we plan to focus on our core area
of the Gainsborough Trough in the short to medium term (2018:
GBP29.1 million).
Net finance costs were GBP3.4 million (2018: GBP3.9 million)
primarily related to interest on borrowings of GBP1.9 million
(2018: GBP1.9 million) and the unwinding of discount on provisions
of GBP1.3 million (2018: GBP1.1 million), finance charges relating
to right-of-use assets GBP0.7 million (2018: GBPnil), offset by a
net foreign exchange gain of GBP0.3 million, principally on US$
denominated debt and bank balances (2018: loss GBP0.9 million). A
loss of GBP0.7 million was incurred relating to the refinancing of
debt including the write-off of costs relating to the bond which
had previously been capitalised.
The Group made a loss on oil price derivatives of GBP3.3 million
for the year due to the premiums on options placed in 2019 and an
increase in underlying prices impacting hedges placed in 2018
(2018: loss GBP0.7 million) and a gain on foreign exchange hedges
of GBP0.3 million (2018: loss GBP0.2 million).
A tax credit of GBP9.3 million was recognised mainly due to the
recognition of a deferred tax asset relating to an increase in the
recoverability of ring-fence tax losses (2018: a tax credit of
GBP3.7 million mainly due to the recognition of a deferred tax
asset relating to ring-fence tax losses).
Cash flow
Net cash generated from operating activities for the year was
GBP12.0 million (2018: GBP12.9 million). The decrease was primarily
due to lower revenue and an increase in working capital, offset by
a decrease in administrative expenses and lower payments to
counterparties in respect of realised hedges.
The Group invested GBP6.4 million across its asset base during
the year (2018: GBP10.6 million). GBP3.7 million was invested in
our conventional assets including the Scampton North Waterflood
project, the Welton water injection project and the installation of
gas pump compressors on additional sites, resulting in additional
production during the year. We continued to invest in new projects
to increase production across our existing sites. We invested
GBP2.7 million in unconventional assets in relation to our shale
development programme including the Group's net share of the cost
of drilling a vertical well at Tinker Lane and costs to progress
the Ellesmere Port planning appeal.
The Group also continued its abandonment programme and spent
GBP1.8 million on abandoning five wells during the year.
Following a successful refinancing, IGas repaid GBP21.4 million
($27.6 million) of principal on its Norwegian bond borrowings to
bondholders during the year. (2018: repaid GBP1.7 million ($2.3
million)). The Group made a net drawdown of GBP14.7 million ($19.0
million) on its new reserves-based loan facility. IGas paid GBP2.0
million ($2.6 million) in interest (2018: GBP1.8 million ($2.3
million)).
To protect against the volatile oil price, the Group places
commodity hedges for a period of up to twelve months. As at 31
December 2019, the Group had hedged a total of 420,000 bbls for
2020, using a combination of puts (292,500 bbls at an average
downside protected price of $51.4/bbl) and fixed price swaps
(127,500 bbls at an average fixed price of $58.7/bbl).
Cash and cash equivalents were GBP8.2 million at the end of the
year (2018: GBP15.1 million).
Balance sheet
Net assets decreased by GBP48.6 million to GBP113.1 million at
31 December 2019 (2018: GBP161.7 million), mainly related to an
impairment of intangible exploration and evaluation assets and
goodwill of GBP58.7 million, offset by an income tax credit of
GBP9.3 million.
Changes to the estimate of decommissioning costs following an
internal review increased both assets and liabilities by GBP7.7
million.
The Group adopted IFRS 16 Leases (effective 1 January 2019)
resulting in the capitalisation of leasing costs of GBP7.7 million
and the recognition of a lease liability of GBP7.2 million as at 31
December 2019.
At 31 December 2019, the Group has a combined carried gross work
programme of up to $214 million (GBP161 million) (2018: $220
million (GBP170 million)) from its partner, INEOS Upstream Limited.
In 2019, GBP7.3m (2018: GBP9.2 million) gross costs were carried,
principally in relation to activities at Springs Road, which have
not been included in the additions to intangible exploration and
evaluation assets during the year.
At 31 December 2019, the Group's oil derivative instruments had
a net negative fair value of GBP0.2 million (2018: net positive
fair value of GBP2.2 million).
Borrowings decreased from GBP21.0 million to GBP13.1 million
following the refinancing carried out during the year as, under the
new financing arrangements, there is no requirement to maintain a
minimum cash balance and repayments can be made in the short-term
using excess cash.
Net debt at the year end, being the nominal value of borrowings
less cash and cash equivalents, was GBP6.2 million (2018: GBP6.4
million).
31 December 31 December
2019 2018
GBPm GBPm
------------ ------------
Debt (nominal value
excluding capitalised
expenses) (14.4) (21.5)
------------ ------------
Cash and cash equivalents 8.2 15.1
------------ ------------
Net Debt (6.2) (6.4)
------------ ------------
Disposal of Non-core Fields
As announced in July 2019, we were unable to agree a transaction
with Onshore Petroleum Limited and consequently all non-core assets
will now remain with IGas.
Adjusted EBITDA
Adjusted EBITDA and underlying Operating Profit are considered
by the Company to be a useful additional measure to help understand
underlying performance.
Adjusted EBITDA
2019 2018
------- -------
GBPm GBPm
------- -------
Loss before tax (59.1) (25.1)
------- -------
Net finance costs 3.4 3.8
------- -------
Loss on refinancing 0.7 -
------- -------
Depletion, depreciation
& amortisation 9.4 6.9
------- -------
Impairments/write-offs 58.7 29.1
------- -------
EBITDA 12.9 14.7
------- -------
Lease rentals capitalised (2.0) -
under IFRS 16
------- -------
Share based payment charges 0.8 0.8
------- -------
Unrealised (gain)/loss
on hedges 2.1 (4.7)
------- -------
Adjusted EBITDA 13.8 10.8
------- -------
Underlying operating profit
2019 2018
------- -------
GBPm GBPm
------- -------
Operating loss (55.0) (21.2)
------- -------
Operating lease rentals (2.0) -
capitalised under IFRS
16
------- -------
Share-based payment charge 0.8 0.8
------- -------
Impairments/write-offs 58.7 29.1
------- -------
Unrealised (gain)/ loss
on hedges 2.1 (4.7)
------- -------
Underlying operating profit 4.6 4.0
------- -------
Principal risks and uncertainties
The Group constantly monitors the Group's risk exposures and
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 can be summarised as:
-- Strategy fails to meet shareholder expectations;
-- Planning, environmental, licensing and other permitting risks
associated with its operations and, in particular, with drilling
and production operations;
-- 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;
-- No guarantee can be given that oil or gas 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;
-- Market price risk through variations in the wholesale price
of oil in the context of the production from oil fields it owns and
operates;
-- Market price risk through variations in the wholesale price
of gas and electricity 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;
-- Capital risk resulting from its capital structure, including
operating within the covenants of its RBL facility;
-- Political risk such as change in Government or the effect of
local or national referendum; and
-- Pandemic that impacts the ability to operate the business effectively.
Going Concern
The Group continues to closely monitor and manage its liquidity
risks. Cash forecasts for the Group are regularly produced based
on, inter alia, management's best estimate of:
-- The Group's production and expenditure forecasts;
-- Future oil prices;
-- The level of available facilities under the group's RBL; and
-- Foreign exchange rates.
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.
In the first quarter of 2020, the oil price has been affected by
the global spread of COVID-19 and the resultant reduction in oil
demand. This situation has since been compounded by the failure of
OPEC to reach an agreement on constraining supply and the decision
of several countries to increase output. At the date of this
report, there remains significant uncertainty over the impact of
COVID-19 on future global demand for oil and therefore the price of
oil.
The ability of the Group to operate as a going concern is
dependent upon the future oil prices and foreign exchange rates as
they impact the continued generation of future cash flows and the
loan facility available under its RBL (which is redetermined
semi-annually based on various parameters including oil price and
level of reserves) and is also dependent on the Group not breaching
its RBL covenants. To mitigate these risks, the Group benefits from
its hedging policy with 420,000 bbls hedged at an average minimum
price of $53.6/bbl for 2020. The Group also has $12 million of
foreign exchange hedges in place at rates between $1.17-$1.20:GBP1
for the period to 30 June 2021. Furthermore, the Group's net
reserves position has increased by 1.5 mmboe during 2019 which will
partially offset any impact of lower prices in its RBL facility at
the next redetermination in May 2020.
Management has considered the impact of the COVID-19 global
crisis on the Group's operations. We continue to monitor the
situation closely and act within Government guidelines and have a
number of contingency plans in place should our operations be
significantly affected by COVID-19. Many of our sites are remotely
manned and at this stage we are well equipped as a business to
ensure we maintain business continuity. Our production comes from a
large number of wells in a variety of locations (all of which are
on land and in the UK) and we have flexibility in our off-take
arrangements, as we transport oil via road. In this regard, we
continue to liaise and co-operate with all the relevant
regulators.
The Group's base case going concern model was run with average
oil prices of $32/bbl for April to December 2020 rising to $45/bbl
from January 2021 and a foreign exchange rate of $1.20:GBP1 during
the period. Our forecasts show that the Group will have sufficient
financial headroom to meet its financial covenants based on the
existing RBL facility, as well as an estimate, based on
management's knowledge and past experience, of the outcome of the
next half-yearly redetermination due in May 2020, and the following
redetermination date in December 2020, albeit the level of the
facility available to us is dependent on the facility provider,
BMO, and is beyond our control.
Given the uncertainties described above, the level of Group
revenues and availability of facilities under the RBL are
inherently uncertain. As such management has also prepared a
downside forecast with the following assumptions:
-- Oil prices at $20/bbl in the second quarter of 2020 rising to
$30/bbl in the fourth quarter of 2020 and $43-$45/bbl in 2021. As
this assumption is lower than external current forward curves,
management considers this is a reasonable downside scenario that
reflects further potential reductions in price caused by the
failure of OPEC to reach an agreement on constraining supply and
lower demand from reduced industrial activity caused by COVID-19.
This downside is partially mitigated by the commodity hedges the
Group has in place. However, oil price is outside the Company's
control and this could be lower should there be further market
disruption either from COVID-19, or OPEC disagreements;
-- No change to the level of available RBL loan facility during
the forecast period as this reflects longer term oil price
assumptions that have been considered in conjunction with recent
discussions with the RBL facility provider;
-- A reduction in production of 10% to reflect a disruption risk
to operational and production related activities from the COVID-19
crisis. As the Group is providing a government designated essential
service and due to the large number of operational wells, the
impact of COVID-19 on production has to date been very limited and
has been assumed to remain so as management does not currently
foresee wells needing to be shut down due to the impact of
COVID-19. Management therefore considers this assumption represents
a reasonable downside in this uncertain time based on management's
experience of previous unplanned shut downs;
-- Exchange rates of $1.20:GBP1 for 2020 and $1.25:GBP1 for 2021
to reflect a downside caused by the weakening of the dollar later
in the period. This downside is partially mitigated by the currency
hedges the Group has in place; and
-- Includes the impact of action management could take to reduce
cash outflow, including delaying capital expenditure and additional
reductions in costs in order to remain within the Company's debt
liquidity covenants based on the Group's expected RBL
redeterminations in May 2020 and December 2020. All such mitigating
actions are within management's control and could be actioned
within the required time frame.
In this downside scenario, our forecast shows that the Group
will have sufficient liquidity and financial headroom to meet its
financial covenants for the 12 months from the date of approval of
the financial statements. However, should oil price or demand (and
therefore revenue) fall further, the Company may not have
sufficient funds available for 12 months from the date of approval
of these financial statements. As a result, at the date of approval
of the financial statements, there is material uncertainty over
future commodity prices, the outcome of the May 2020
redetermination of the RBL and the potential impact of COVID-19 on
the Group's operational activities. These material uncertainties
may cast significant doubt upon the Group's ability to continue as
a going concern. Notwithstanding these material uncertainties, the
Directors have a reasonable expectation that the Group has adequate
resources to continue in existence for the foreseeable future and
have concluded it is appropriate to adopt the going concern basis
of accounting in the preparation of the financial statements. The
financial statements do not include the adjustments that would
result if the Group was unable to continue as a going concern.
Stephen Bowler Julian Tedder
Chief Executive Officer Chief Financial Officer
8 April 2020 8 April 2020
CONSOLIDATED INCOME STATEMENT
FOR THE YEARED 31 DECEMBER 2019
Year ended Year ended
31 December 2019 31 December 2018
Note GBP000 GBP000
-------------------------------------------------------------------------- ---- ----------------- -----------------
Revenue 2 40,901 42,928
Cost of sales:
Depletion, depreciation and amortisation (9,058) (6,824)
Other costs of sales (20,542) (21,932)
-------------------------------------------------------------------------- ---- ----------------- -----------------
(29,600) (28,756)
Gross profit 11,301 14,172
Administrative expenses (4,533) (5,527)
Exploration and evaluation assets written-off 7 (53,928) (29,067)
Goodwill impairment 6 (4,801) -
Loss on oil price derivatives (3,348) (638)
Gain/(loss) on foreign exchange contracts 265 (180)
Operating loss (55,044) (21,240)
Finance income 3 460 69
Finance costs 3 (3,861) (3,948)
Loss on extinguishment of debt re-financing 11 (692) -
-------------------------------------------------------------------------- ---- ----------------- -----------------
Loss from continuing activities before tax (59,137) (25,119)
Income tax credit 4 9,307 3,745
-------------------------------------------------------------------------- ---- ----------------- -----------------
Loss after tax from continuing operations attributable to shareholders'
equity (49,830) (21,374)
(Loss)/profit after taxation from discontinued operations
after tax from discontinued operations (396) 41
-------------------------------------------------------------------------- ---- ----------------- -----------------
Net loss for the year attributable to shareholders' equity (50,226) (21,333)
-------------------------------------------------------------------------- ---- ----------------- -----------------
Loss attributable to equity shareholders from continuing operations:
Basic loss per share 5 (40.93p) (17.59p)
Diluted loss per share 5 (40.93p) (17.59p)
Loss attributable to equity shareholders including discontinued
operations:
Basic loss per share 5 (41.26p) (17.56p)
Diluted loss per share 5 (41.26p) (17.56p)
-------------------------------------------------------------------------- ---- ----------------- -----------------
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
FOR THE YEARED 31 DECEMBER 2019
Year ended Year ended
31 December 2019 31 December 2018
GBP000 GBP000
------------------------------------------------------------------ ----------------- -----------------
Loss for the year (50,226) (21,333)
Other comprehensive loss for the year:
Currency translation adjustments recycled to the income statement (63) -
Currency translation adjustments 68 (235)
------------------------------------------------------------------ ----------------- -----------------
Total comprehensive loss for the year (50,221) (21,568 )
------------------------------------------------------------------ ----------------- -----------------
CONSOLIDATED BALANCE SHEET
AS AT 31 DECEMBER 2019
31 December 31 December
2019 2018
Note GBP000 GBP000
--------------------------------------------- ---- ----------- -----------
ASSETS
Non - current assets
Goodwill 6 - 4,801
Intangible exploration and evaluation assets 7 41,455 89,282
Property, plant and equipment 8 104,532 91,403
Right-of-use assets 9 7,668 -
Restricted cash 10 410 410
Deferred tax asset 4 29,961 20,656
184,026 206,552
--------------------------------------------- ---- ----------- -----------
Current assets
Inventories 1,193 1,149
Trade and other receivables 5,986 9,589
Cash and cash equivalents 10 8,194 15,112
Restricted cash 10 - 193
Derivative financial instruments 127 2,158
Assets held for sale - 10,100
15,500 38,301
--------------------------------------------- ---- ----------- -----------
Total assets 199,526 244,853
--------------------------------------------- ---- ----------- -----------
LIABILITIES
Current liabilities
Trade and other payables (9,288) (11,878)
Borrowings 11 - (2,389)
Derivative financial instruments (266) (180)
Lease liabilities 9 (988) -
Liabilities held for sale - (10,272)
(10,542) (24,719)
--------------------------------------------- ---- ----------- -----------
Non - current liabilities
Borrowings 11 (13,071) (18,591)
Other creditors (1,529) (1,916)
Lease liabilities 9 (6,173) -
Provisions 12 (55,101) (37,946)
(75,874) (58,453)
Total liabilities (86,416) (83,172)
--------------------------------------------- ---- ----------- -----------
Net assets 113,110 161,681
--------------------------------------------- ---- ----------- -----------
EQUITY
Capital and reserves
Called up share capital 30,333 30,333
Share premium account 102,680 102,501
Foreign currency translation reserve (7,289) (7,294)
Other reserves 32,781 31,310
Accumulated (deficit)/surplus (45,395) 4,831
Total equity 113,110 161,681
--------------------------------------------- ---- ----------- -----------
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
FOR THE YEARED 31 DECEMBER 2019
Foreign
Share currency
Called up premium translation Other Accumulated Total
share capital account reserve* reserves ** surplus/(deficit) equity
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
------------------------------ --------------- --------- ------------- ------------- ------------------ --------
At 1 January 2018 30,333 102,342 (7,059) 29,994 25,991 181,601
Loss for the year - - - - (21,333) (21,333)
Share options issued under the
employee share plan (note 25) - - - 1,489 - 1,489
Issue of shares - 159 - - - 159
Lapse of options under the
employee share plan - - - (173) 173 -
Currency translation
adjustments - - (235) - - (235)
------------------------------ --------------- --------- ------------- ------------- ------------------ --------
At 31 December 2018 30,333 102,501 (7,294) 31,310 4,831 161,681
Loss for the year - - - - (50,226) (50,226)
Share options issued under the
employee share plan (note 25) - - - 1,599 - 1,599
Issue of shares - 179 - - - 179
Forfeiture of options under
the employee share plan - - - (128) - (128)
Currency translation
adjustments - - 5 - - 5
------------------------------ --------------- --------- ------------- ------------- ------------------ --------
At 31 December 2019 30,333 102,680 (7,289) 32,781 (45,395) 113,110
------------------------------ --------------- --------- ------------- ------------- ------------------ --------
* The foreign currency translation reserve represents exchange
gains and losses arising on translation of foreign currency
subsidiaries net assets and results, and on translation of those
subsidiaries intercompany balances which form part of the net
investment of the Group.
** Other reserves include: 1) EIP/MRP/LTIP/VCP/EDRP reserves
which represent the cost of share options issued under the long
term incentive plans; 2) share investment plan reserve which
represents the cost of the partnership and matching shares; 3)
treasury shares reserve which represents the cost of shares in IGas
Energy plc purchased in the market and held by the IGas Employee
Benefit Trust to satisfy awards held under the Group incentive
plans; and 4) capital contribution reserve which arose following
the acquisition of IGas Exploration UK Limited.
CONSOLIDATED CASH FLOW STATEMENT
FOR THE YEARED 31 DECEMBER 2019
Notes
Year Year
ended ended
31 December 31 December
2019 2018
GBP000 GBP000
Cash flows from operating activities:
Loss before tax for the year (59,137) (25,119)
Net loss on extinguishment of debt re-financing 11 692 -
Depletion, depreciation and amortisation* 9,449 6,923
Abandonment costs/other provisions utilised 12 (1,760) (91)
Share based payment charge 801 1,606
Exploration and evaluation assets written-off 7 53,928 29,067
Goodwill impairment 6 4,801 -
Unrealised loss/(gain) on oil price derivatives 2,380 (4,906)
Unrealised (gain)/loss on foreign exchange
contracts (265) 180
Finance income 3 (460) (69)
Finance costs 3 3,861 3,948
Other non-cash adjustments (14) 43
------------------------------------------------- ------ ------------- --------------
Operating cash flow before working capital
movements 14,276 11,582
Increase/(decrease) in trade and other
receivables and other financial assets (602) 993
Decrease/(increase) in trade and other
payables (1,733) 536
(Increase)/decrease in inventories (44) 173
Cash from continuing operating activities 11,897 13,284
------------------------------------------------- ------ ------------- --------------
Decrease/(increase) in discontinued operating
activities 105 (335)
------------------------------------------------- ------ ------------- --------------
Taxation paid - continuing operating activities - (9)
Net cash from operating activities 12,002 12,940
------------------------------------------------- ------ ------------- --------------
Cash flows from investing activities:
Purchase of intangible exploration and
evaluation assets (2,716) (2,496)
Purchase of property, plant and equipment (3,668) (8,152)
Proceeds from disposal of assets 1 18
Other income received 14 38
Interest received 129 69
------------------------------------------------- ------ ------------- --------------
Cash used in continuing investing activities (6,240) (10,523)
Net cash used in investing activities (6,240) (10,523)
------------------------------------------------- ------ ------------- --------------
Cash flows from financing activities:
Cash proceeds from issue of ordinary share
capital 69 70
Drawdown on reserves-based loan facility 10 19,319 -
Repayment on reserves-based loan facility 10 (4,639) -
Fees paid related to debt re-financing 10 (1,059) -
Repayment of bonds 10 (21,355) (1,722)
Repayment of principal portion of lease
liability (2,687) -
Interest paid 10 (2,021) (1,751)
Net cash used in financing activities (12,373) (3,403)
------------------------------------------------- ------ ------------- --------------
Net decrease in cash and cash equivalents
in the year (6,611) (986)
Net foreign exchange difference (307) 371
Cash and cash equivalents at the beginning
of the year 15,112 15,727
-------------------------------------------------
Cash and cash equivalents at the end of
the year 10 8,194 15,112
------------------------------------------------- ------ ------------- --------------
CONSOLIDATED FINANCIAL STATEMENTS - NOTES
FOR THE YEARED 31 DECEMBER 2019
1 Accounting policies
(a) Basis of preparation of financial statements and corporate
information
Whilst the financial information in this preliminary
announcement has been prepared in accordance with International
Financial Reporting Standards (IFRS) and International Financial
Reporting Interpretation Committee (IFRIC) interpretations adopted
for use by the European Union, with those parts of the Companies
Act 2006 applicable to companies reporting under IFRS and with the
requirements of the United Kingdom Listing Authority (UKLA) Listing
Rules, this announcement does not contain sufficient information to
comply with IFRS. The Group will publish full financial statements
that comply with IFRS in May 2020.
The financial information for the year ended 31 December 2019
does not constitute statutory financial statements as defined in
sections 435 (1) and (2) of the Companies Act 2006. Statutory
financial statements for the year ended 31 December 2018 have been
delivered to the Registrar of Companies and those for 2019 will be
delivered following the Company's annual general meeting. The
auditor has reported on these financial statements; their reports
were unqualified, though they drew attention to a material
uncertainty related to going concern in 2019. These reports did not
contain a statement under section 498 (2) or (3) of the Companies
Act 2006.
The accounting policies applied are consistent with those
adopted and disclosed in the Group's financial statements for the
year ended 31 December 2018. There have been a number of amendments
to accounting standards and new interpretations issued by the
International Accounting Standards Board which were applicable from
1 January 2019. These did not have a material impact on the
accounting policies, methods of computation or presentation applied
by the Group, except for IFRS 16 Leases. The Group had to change
its accounting policies as a result of adopting IFRS 16. The Group
elected to adopt the new rules under the modified retrospective
approach but recognised the cumulative effect of initially applying
the new standard on 1 January 2019.
There are also a number of amendments to accounting standards
and new interpretations issued by the International Accounting
Standards Board which will be applicable from 1 January 2020
onwards. These are not expected to have a material impact on the
accounting policies, methods of computation or presentation applied
by the Group and have not been adopted early.
Further details on new International Financial Reporting
Standards adopted and yet to be adopted will be disclosed in the
2019 Annual Report and Financial Statements.
IGas Energy plc is a public limited company incorporated and
registered in England and Wales and is listed on the Alternative
Investment Market ("AIM"). The Group's principal area of activity
is exploring for, appraising, developing and producing oil and gas
resources in Great Britain.
The financial information is presented in UK pounds sterling and
all values are rounded to the nearest thousand (GBP000) except when
otherwise indicated.
(b) Going concern
The Group continues to closely monitor and manage its liquidity
risks. Cash forecasts for the Group are regularly produced based
on, inter alia, management's best estimate of:
-- The Group's production and expenditure forecasts;
-- Future oil prices;
-- The level of available facilities under the group's RBL; and
-- Foreign exchange rates.
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.
In the first quarter of 2020, the oil price has been affected by
the global spread of COVID-19 and the resultant reduction in oil
demand. This situation has since been compounded by the failure of
OPEC to reach an agreement on constraining supply and the decision
of several countries to increase output. At the date of this
report, there remains significant uncertainty over the impact of
COVID-19 on future global demand for oil and therefore the price of
oil.
The ability of the Group to operate as a going concern is
dependent upon the future oil prices and foreign exchange rates as
they impact the continued generation of future cash flows and the
loan facility available under its RBL (which is redetermined
semi-annually based on various parameters including oil price and
level of reserves) and is also dependent on the Group not breaching
its RBL covenants. To mitigate these risks, the Group benefits from
its hedging policy with 420,000 bbls hedged at an average minimum
price of $53.6/bbl for 2020. The Group also has $12 million of
foreign exchange hedges in place at rates between $1.17-$1.20:GBP1
for the period to 30 June 2021. Furthermore, the Group's net
reserves position has increased by 1.5 mmboe during 2019 which will
partially offset any impact of lower prices in its RBL facility at
the next redetermination in May 2020.
Management has considered the impact of the COVID-19 global
crisis on the Group's operations. We continue to monitor the
situation closely and act within Government guidelines and have a
number of contingency plans in place should our operations be
significantly affected by COVID-19. Many of our sites are remotely
manned and at this stage we are well equipped as a business to
ensure we maintain business continuity. Our production comes from a
large number of wells in a variety of locations (all of which are
on land and in the UK) and we have flexibility in our off-take
arrangements, as we transport oil via road. In this regard, we
continue to liaise and co-operate with all the relevant
regulators.
The Group's base case going concern model was run with average
oil prices of $32/bbl for April to December 2020 rising to $45/bbl
from January 2021 and a foreign exchange rate of $1.20:GBP1 during
the period. Our forecasts show that the Group will have sufficient
financial headroom to meet its financial covenants based on the
existing RBL facility, as well as an estimate, based on
management's knowledge and past experience, of the outcome of the
next half-yearly redetermination due in May 2020, and the following
redetermination date in December 2020, albeit the level of the
facility available to us is dependent on the facility provider,
BMO, and is beyond our control.
Given the uncertainties described above, the level of Group
revenues and availability of facilities under the RBL are
inherently uncertain. As such management has also prepared a
downside forecast with the following assumptions:
-- Oil prices at $20/bbl in the second quarter of 2020 rising to
$30/bbl in the fourth quarter of 2020 and $43-$45/bbl in 2021. As
this assumption is lower than external current forward curves,
management considers this is a reasonable downside scenario that
reflects further potential reductions in price caused by the
failure of OPEC to reach an agreement on constraining supply and
lower demand from reduced industrial activity caused by COVID-19.
This downside is partially mitigated by the commodity hedges the
Group has in place. However, oil price is outside the Company's
control and this could be lower should there be further market
disruption either from COVID-19, or OPEC disagreements;
-- No change to the level of available RBL loan facility during
the forecast period as this reflects longer term oil price
assumptions that have been considered in conjunction with recent
discussions with the RBL facility provider;
-- A reduction in production of 10% to reflect a disruption risk
to operational and production related activities from the COVID-19
crisis. As the Group is providing a government designated essential
service and due to the large number of operational wells, the
impact of COVID-19 on production has to date been very limited and
has been assumed to remain so as management does not currently
foresee wells needing to be shut down due to the impact of
COVID-19. Management therefore considers this assumption represents
a reasonable downside in this uncertain time based on management's
experience of previous unplanned shut downs;
-- Exchange rates of $1.20:GBP1 for 2020 and $1.25:GBP1 for 2021
to reflect a downside caused by the weakening of the dollar later
in the period. This downside is partially mitigated by the currency
hedges the Group has in place; and
-- Includes the impact of action management could take to reduce
cash outflow, including delaying capital expenditure and additional
reductions in costs in order to remain within the Company's debt
liquidity covenants based on the Group's expected RBL
redeterminations in May 2020 and December 2020. All such mitigating
actions are within management's control and could be actioned
within the required time frame.
In this downside scenario, our forecast shows that the Group
will have sufficient liquidity and financial headroom to meet its
financial covenants for the 12 months from the date of approval of
the financial statements. However, should oil price or demand (and
therefore revenue) fall further, the Company may not have
sufficient funds available for 12 months from the date of approval
of these financial statements. As a result, at the date of approval
of the financial statements, there is material uncertainty over
future commodity prices, the outcome of the May 2020
redetermination of the RBL and the potential impact of COVID-19 on
the Group's operational activities. These material uncertainties
may cast significant doubt upon the Group's ability to continue as
a going concern. Notwithstanding these material uncertainties, the
Directors have a reasonable expectation that the Group has adequate
resources to continue in existence for the foreseeable future and
have concluded it is appropriate to adopt the going concern basis
of accounting in the preparation of the financial statements. The
financial statements do not include the adjustments that would
result if the Group was unable to continue as a going concern.
2 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. The Group's major product lines
are:
Year ended Year ended
31 December 31 December
2019 2018
GBP000 GBP000
------------------ ------------ ------------
Oil sales 39,248 41,978
Electricity sales 966 888
Gas sales 687 62
------------------ ------------ ------------
40,901 42,928
------------------ ------------ ------------
Revenues of approximately GBP18.8 million and GBP20.5 million
were derived from the Group's two largest customers (2018: GBP21.6
million and GBP20.4 million) and are attributed to the oil
sales.
3 Finance income and costs
Year ended Year ended
31 December 31 December
2019 2018
GBP000 GBP000
---------------------------------------------------- ------------ ------------
Finance income:
Interest on short - term deposits 127 63
Foreign exchange gains 333 -
Other interest and finance charges - 6
Finance income 460 69
---------------------------------------------------- ------------ ------------
Finance expense:
Interest on borrowings (1,874) (1,948)
Foreign exchange loss - (895)
Unwinding of discount on provisions ( note 12) (1,310) (1,105)
Finance charge on lease liability for assets in use (677) -
---------------------------------------------------- ------------ ------------
Finance expense (3,861) (3,948)
---------------------------------------------------- ------------ ------------
4 Income tax credit
(i) Tax credit on loss from continuing ordinary activities
Year ended Year ended
31 December 31 December
2019 2018
GBP000 GBP000
------------------------------------------------------------------------ ------------ ------------
Current tax:
Charge on loss for the year - -
Charge in relation to prior years - 9
Total current tax charge - 9
------------------------------------------------------------------------ ------------ ------------
Deferred tax:
Credit relating to the origination or reversal of temporary differences (3,461) (782)
Charge due to tax rate changes - 84
Credit in relation to prior years (5,846) (3,056)
------------------------------------------------------------------------ ------------ ------------
Total deferred tax credit (9,307) (3,754)
------------------------------------------------------------------------ ------------ ------------
Tax credit on loss on ordinary activities (9,307) (3,745)
------------------------------------------------------------------------ ------------ ------------
ii) Factors affecting the tax charge
The majority of the Group's profits are generated by
"ring-fence" businesses which attract UK corporation tax and
supplementary charge at a combined average rate of 40%.
A reconciliation of the UK statutory corporation tax rate
applied to the Group's loss before tax to the Group's total tax
credit is as follows:
Year ended Year ended
31 December 31 December
2019 2018
GBP000 GBP000
------------------------------------------------------------------------------------------ ------------ ------------
Loss from continuing ordinary activities before tax (59,137) (25,119)
Expected tax credit based on loss from continuing ordinary activities multiplied by an
average
combined rate of corporation tax and supplementary charge in the UK of 40 % (2018: 40%) (23,655) (10,047)
Deferred tax credit in respect of the prior year (5,846) (3,056)
Current tax charge related to prior year - 9
Tax effect of expenses not allowable for tax purposes 9,850 1,190
Tax effect of differences in amounts not allowable for supplementary charge purposes* (121) 999
Impact of profits or losses taxed or relieved at different rates 292 603
Use of losses under the loss restriction rules - (827)
Net increase in unrecognised losses carried forward 10,197 7,138
Intra-group transfer of assets - 11
Tax rate change - 84
Other (24) 151
------------------------------------------------------------------------------------------ ------------ ------------
Tax credit on loss on ordinary activities (9,307) (3,745)
------------------------------------------------------------------------------------------ ------------ ------------
* Amounts not allowable for supplementary charge purposes relate
to net financing costs disallowed for supplementary charge offset
by investment allowance which is deductible against profits subject
to supplementary charge.
iii) Deferred tax
The movement on the deferred tax asset in the year is shown
below:
Year ended Year ended
31 December 31 December
2019 2018
GBP000 GBP000
--------------------------------------------------- ------------ ------------
Asset at 1 January 20,656 16,900
Tax credit relating to prior year 5,846 3,056
Tax credit during the year 3,461 782
Tax charge arising due to the changes in tax rates - (84)
Other (2) 2
--------------------------------------------------- ------------ ------------
Asset at 31 December 29,961 20,656
--------------------------------------------------- ------------ ------------
The following is an analysis of the deferred tax asset by
category of temporary difference:
31 December 31 December
2019 2018
GBP000 GBP000
--------------------------------------------------- ----------- -----------
Accelerated capital allowances (13,993) (26,409)
Tax losses carried forward 29,735 35,721
Investment allowance unutilised 1,297 840
Decommissioning provision 9,628 8,095
Unrealised gains or losses on derivative contracts 1,799 924
Share based payments 1,675 1,483
Right-of-use asset and liability (180) -
Other - 2
--------------------------------------------------- ----------- -----------
Deferred tax asset 29,961 20,656
--------------------------------------------------- ----------- -----------
iv) Tax losses
Deferred tax assets have been recognised in respect of tax
losses and other temporary differences where the Directors believe
it is probable that these assets will be recovered. Such tax losses
include GBP94.4 million (2018: GBP114.3 million) of ring-fence
corporation tax losses.
The Group has further tax losses and other similar attributes
carried forward of approximately GBP234.8 million (2018: GBP203.0
million) for which no deferred tax asset is recognised due to
insufficient certainty regarding the availability of appropriate
future taxable profits. The unrecognised losses may affect future
tax charges should certain subsidiaries in the Group generate
taxable trading profits in future periods.
5 Earnings per share (EPS)
Continuing
Basic EPS amounts are based on the loss for the year after
taxation attributable to ordinary equity holders of the parent of
GBP49.8 million (2018: a loss of GBP21.4 million) and the weighted
average number of ordinary shares outstanding during the year of
121.7 million (2018: 121.5 million).
Diluted EPS amounts are based on the loss for the year after
taxation attributable to the ordinary equity holders of the parent
and the weighted average number of shares outstanding during the
year plus the weighted average number of ordinary shares that would
be issued on the conversion of all the potentially dilutive
ordinary shares into ordinary shares, except where these are
anti-dilutive.
As at 31 December 2019, there are 6.3 million potentially
dilutive employee share options (31 December 2018: 4.6 million
potentially dilutive share options) which are not included in the
calculation of diluted earnings per share as their conversion to
ordinary shares would have decreased the loss per share.
The following reflects the income and share data used in the
basic and diluted earnings per share from continuing
operations:
Year ended Year ended
31 December 31 December
2019 2018
----------------------------------------------------------- ------------ ------------
Basic loss per share - ordinary shares of 0.002 pence each (40.93p) (17.59p)
Diluted loss per share - ordinary shares of 0.002 pence
each (40.93p) (17.59p)
Loss for the year attributable to equity holders of the
parent from continuing operations - GBP000 (49,830) (21,374)
Weighted average number of ordinary shares in the year-
basic EPS 121,729,407 121,483,931
Weighted average number of ordinary shares in the year-
diluted EPS 128,047,666 126,104,420
----------------------------------------------------------- ------------ ------------
Discontinued
The following reflects the income and share data used in the
basic and diluted earnings per share including discontinued
operations:
Year ended Year ended
31 December 31 December
2019 2018
----------------------------------------------------------- ------------ ------------
Basic loss per share - ordinary shares of 0.002 pence each (41.26p) (17.56p)
Diluted loss per share - ordinary shares of 0.002 pence
each (41.26p) (17.56p)
Loss for the year attributable to equity holders of the
parent from continuing operations - GBP000 (50,226) (21,333)
Weighted average number of ordinary shares in the year-
basic EPS 121,729,407 121,483,931
Weighted average number of ordinary shares in the year-
diluted EPS 128,047,666 126,104,420
----------------------------------------------------------- ------------ ------------
6 Goodwill
2019 2018
GBP000 GBP000
--------------- ------- -------
At 1 January 4,801 4,801
Impairment (4,801) -
--------------- ------- -------
At 31 December - 4,801
--------------- ------- -------
The carrying value of goodwill related to unconventional assets
acquired as part of the Dart acquisition in 2014. The Group tests
goodwill for impairment annually or more frequently if there are
indications that goodwill might be impaired. The Group reviewed the
valuation of goodwill as at 31 December 2019 and assessed it for
impairment. Following a moratorium on fracking announced by the UK
Government in late 2019, management assessed that the carrying
value of goodwill was not recoverable and impaired the brought
forward balance of GBP4.8 million in full for the year (2018:
GBPnil) .
7 Intangible exploration and evaluation assets
2019 2018
GBP'000 GBP'000
---------------------------------- --------- --------
At 1 January 89,282 115,130
Additions 3,984 3,561
Transfers from/(to) held for sale 342 (342)
Changes in decommissioning* 1,775 -
Amounts written-off (53,928) (29,067)
---------------------------------- --------- --------
At 31 December 41,455 89,282
---------------------------------- --------- --------
*The decommissioning asset increased in line with the
decommissioning liability following a review of the estimate at 31
December 2019 .
In November 2019, the UK Government announced an effective
moratorium on fracking in Britain, based on analysis of one well in
the North West by the Oil and Gas Authority ("OGA"), until new
scientific evidence is provided in respect of the impacts of
seismicity during the process of hydraulic fracturing. Management
have been working and will continue to work closely with the
relevant regulators to demonstrate that the Group can operate
safely and environmentally responsibly. However, following an
impairment review, the Group impaired in full those assets outside
our core area where the Group does not have plans in the near-term
to continue exploration or development activities. Exploration
costs written off were GBP53.9 million (31 December 2018: GBP29.1
million), of which GBP51.8 million related to licences in the North
West, primarily PEDL145 (Doe Green), PEDL 193, PEDL147 and PEDL 189
where the previously capitalised assets have been written off in
full; and GBP0.8 million related to PEDL 146, EXL 288 and 56-1 in
the East Midlands where relinquishment of the licences are planned
in 2020. The balance relates to exploration costs on a number of
other licences outside our core area. (2018 impairment comprised:
GBP20.7 million related to the Doe Green production facility in the
North West (PEDL 145) where a long-term test determined that there
was no potential for a commercial development; GBP3.2 million
related to a well not being used in the Albury development and
GBP5.2 million related to relinquished licences). As part of our
ongoing active portfolio management, we are continually reviewing
our acreage positions and will continue to seek to relinquish
non-core licences or impair licences where the carrying value
cannot be supported.
An analysis by location of the remaining exploration and
evaluation assets is as follows:
North West: The group has GBP5.9 million (2018: GBP48.7 million)
of capitalised exploration expenditure relating to Ellesmere Port
where IGas has lodged an appeal against the decision made by
Cheshire West and Chester Council's Planning and Licensing
Committee to refuse planning consent for routine tests on a rock
formation encountered in the Ellesmere Port-1 well. The appeal has
been recovered by the Secretary of State and the decision is
expected in mid-2020. As the outcome is still undetermined it is
appropriate to keep the carrying value of the asset
capitalised.
East Midlands: The group has GBP31.6 million (2018: GBP36.9
million) of capitalised exploration expenditure relating to our
core area in the Gainsborough Trough which includes PEDL's 12, 139,
140, 169, 200 and 210. The Gainsborough Trough is an area with
significant shale potential and we have a work programme in place.
Following the moratorium on fracking, we will work with the UK
Government to demonstrate that we can develop shale in this area in
a safe manner.
Weald: The group has GBP4.0 million (2018: GBP3.5 million) of
capitalised exploration expenditure which includes PEDL235.
At 31 December 2019, the Group has a combined carried gross work
programme of up to $214 million (GBP161 million) (2018: $220
million (GBP170 million)) from its partner, INEOS Upstream Limited.
In 2019 GBP7.3m (2018: GBP9.2 million) gross costs were carried,
principally in relation to activities at and Springs Road, which
have not been included in the additions to intangible exploration
and evaluation assets during the year.
8 Property, plant and equipment
31 December 2019 31 December 2018
--------------------------------- ---------------------------------
Other Other
Oil property, Oil property,
and plant and plant
gas and gas and
assets equipment Total assets equipment Total
GBP'000 GBP'000 GBP'000 GBP'000 GBP'000 GBP'000
------------------------------ --------- ----------- --------- --------- ----------- ---------
Cost
At 1 January 154,649 2,871 157,520 171,888 3,603 175,491
Additions 5,491 10 5,501 10,135 104 10,239
Disposals (118) - (118) (25) (57) (82)
Changes in decommissioning** 5,908 - 5,908 4,596 - 4,596
Transfers from/(to)
assets held for
sale 31,945 779 32,724 (31,945) (779) (32,724)
At 31 December 197,875 3,660 201,535 154,649 2,871 157,520
------------------------------- --------- ----------- --------- --------- ----------- ---------
Depreciation and
Impairment
At 1 January 65,002 1,115 66,117 80,756 1,577 82,333
Charge for the year* 7,688 258 7,946 6,638 285 6,923
Disposals (117) - (117) (25) (57) (82)
Transfers from/(to)
assets held for
sale 22,367 690 23,057 (22,367) (690) (23,057)
------------------------------- --------- ----------- --------- --------- ----------- ---------
At 31 December 94,940 2,063 97,003 65,002 1,115 66,117
------------------------------- --------- ----------- --------- --------- ----------- ---------
NBV at 31 December 102,935 1,597 104,532 89,647 1,756 91,403
------------------------------- --------- ----------- --------- --------- ----------- ---------
* Charge for the year includes GBP48 thousand categorised as
administration expenses in the profit and loss (2018: GBP99
thousand).
**The decommissioning asset increased in line with the
decommissioning liability following a review of the estimate at 31
December 2019 .
Impairment of oil and gas properties
Due to the continuing volatility in oil and gas prices and
foreign exchange rates, the Group's oil and gas properties were
reviewed for impairment as at 31 December 2019. CGUs for impairment
purposes are the group of fields whereby technical, economic and/or
contractual features create underlying interdependence in cash
flows. The Group has identified the three main producing CGUs as:
North, South, and Scotland. The impairment assessment for the
North, South and Scotland 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 price
assumption for Brent of $60/bbl for the years 2020-2024 and $70/bbl
(2018: $75/bbl) thereafter, and a USD/GBP foreign exchange rate of
$1.35:GBP1.00 (2018: $1.30/GBP1.00). Cash flows were discounted
using a pre-tax discount rate of 8.5% (2018: 11%). No impairment
was required in the year (2018: GBPnil).
Sensitivity of changes in assumptions
As discussed above, the principal assumptions are recoverable
future production and resources, estimated Brent prices and the
USD/GBP foreign exchange rate.
Impairments that would result from changes to the key
assumptions are shown below:
CGU Discount Prices USD/GBP foreign Combined sensitivity
rate exchange rate (Discount
rate, Price,
foreign exchange)
$35/bbl
in 2020,
rising by
$5 each
year to
2024 and 1.2/GBP1.0
$60/bbl to 2024 and$1.35
9.5% thereafter thereafter
------------ ------------ ------------------ ---------------------
GBP'million GBP'million GBP'million GBP'million
------------ ------------ ------------------ ---------------------
North 1.2 31.4 N/A 27.9
------------ ------------ ------------------ ---------------------
South N/A 21.4 N/A 16.4
------------ ------------ ------------------ ---------------------
Scotland 0.2 0.7 N/A 0.6
------------ ------------ ------------------ ---------------------
The sensitivity analysis above does not take into account any
mitigating actions available to management should these changes
occur.
In addition, management considered the impact of climate change
on the value of the Group's conventional assets. Assessing the
impact is difficult and very subjective. However, management have
assumed that this might result in lower oil prices or increased
costs in the medium term and have therefore calculated a
sensitivity based on a reduced price of GBP50/bbl from 2030 onwards
and a cessation of production after 2050. This would result in an
impairment of GBP7.9 for the North CGU, GBP1.3 for the South CGU
and GBP0.1 for the Scotland CGU.
9 Right-of-use assets and lease liabilities
The Group adopted IFRS 16 Leases, which sets out the principles
for the recognition, measurement, presentation and disclosure of
leases, for periods commencing after 1 January 2019. On adoption of
IFRS 16, the Group recognised lease liabilities in relation to
leases which were previously classified as operating leases under
the provisions of IAS 17 Leases.
The Group's leasing activities and how these are accounted
for
The Group leases property, land, cars and other equipment.
Rental contracts are typically made for fixed periods of between 3
and 30 years but may have extension options. Lease terms are
negotiated on an individual basis and contain a wide range of terms
and conditions. Leased assets may not be used as security for
borrowing purposes.
Until 31 December 2018, leases of property, land, cars and other
equipment were classified as operating leases. From 1 January 2019,
leases are recognised as a right-of-use asset and a corresponding
liability at the date at which the leased asset is available for
use by the Group.
(a) Adjustments recognised on adoption of IFRS 16
In accordance with the transition provisions in IFRS 16, the
modified retrospective approach has been adopted with the
cumulative effect of initially applying the new standard recognised
on 1 January 2019. Comparatives for the 2018 financial year have
not be restated. The financial impact of transition to IFRS 16 for
the year ended 31 December 2019 has been summarised within this
note. In applying IFRS 16 for the first time, the Group has used
the practical expedient permitted by the standard, relying on
previous assessments on whether leases are onerous as an
alternative to performing an impairment review - there were no
onerous contracts as at 1 January 2019. The Group has elected to
use the recognition exemptions for lease contracts that, at the
commencement date, have a lease term of 12 months or less and do
not contain a purchase option, and lease contracts for which the
underlying asset is of low value ('low-value assets'). The Group
recognises lease expenses for these contracts on a straight-line
basis as permitted by IFRS 16. Lease liabilities related to
operated Joint Ventures are disclosed gross.
1 January 2019
GBP000
-----------------------------------------------------------------------------------------------------
Operating lease commitments disclosed as at 31 December 2018 9,605
Operating leases relating to assets transferred from 'held for sale' assets 958
Impact of discounting using the incremental borrowing rate (IBR) on transition (4,237)
Less: low-value leases recognised on a straight-line basis as expense (17)
Add: adjustments as a result of a different treatment of extension and termination options 1,421
Lease liability recognised as at 1 January 2019 7,730
-------------------------------------------------------------------------------------------- -------
31 December 2019 1 January 2019
GBP000 GBP000
------------------ ---------------- --------------
Lease liabilities
Current 988 1,533
Non-current 6,173 6,197
------------------ ---------------- --------------
7,161 7,730
------------------ ---------------- --------------
( b) Amounts recognised in the balance sheet
The Group has identified lease portfolios for property, land,
cars and other equipment as follows:
31 December 2019 1 January 2019
GBP000 GBP000
----------------------------------- ---------------- --------------
Right-of-use assets
Land 7,182 6,548
Motor vehicles and other equipment 156 350
Property 330 832
7,668 7,730
----------------------------------- ---------------- --------------
Additions to the right-of-use assets during the 2019 financial
year were GBP1.4 million and depreciation GBP1.5 million
Sensitivity
Management performed sensitivity analysis to assess the impact
of changes to the incremental borrowing rate on the Group's lease
liability and right-of-use asset balances. A 3% increase in the IBR
would result in an increase in right-of-use asset of GBP1.1 million
and lease liability by GBP1.1 million.
(c) Amounts recognised in the income statement
The income statement includes the following amounts relating to
leases:
31 December
2019 31 December 2018
GBP000 GBP000
-------------------------------------------------------------- ----------------------- ----------------
Depreciation charge of right-of-use assets
Land 1,025 -
Property 268 -
Motor vehicles and other equipment 210 -
-------------------------------------------------------------- ----------------------- ----------------
1,503 -
-------------------------------------------------------------- ----------------------- ----------------
Interest expense (included in finance cost) 677 -
Expense relating to leases of low-value and short-term leases
(included in cost of sales administrative expense) 77 -
-------------------------------------------------------------- ----------------------- ----------------
During the year ended 31 December 2019, the Group had a total
cash outflow of GBP2.7 million on qualifying leases.
The financial effect of revising lease terms to reflect the
effect of exercising extension and termination options was an
increase in recognised lease liabilities and right-of-use assets of
GBP1.4 million.
10 Cash and cash equivalents
31 December 31 December
2019 2018
GBP000 GBP000
------------------------- ----------- -----------
Cash at bank and in hand 8,194 15,112
------------------------- ----------- -----------
The cash and cash equivalents does not include restricted
cash.
Restricted cash
31 December 31 December
2019 2018
GBP000 GBP000
------------ ----------- -----------
Current - 193
Non-current 410 410
------------ ----------- -----------
The restricted cash represents restoration deposits paid to
Nottinghamshire County Council which serve as collateral for the
restoration of drilling sites at the end of their life. The
restoration deposits are subject to regulatory and other
restrictions and are therefore not available for general use by the
other entities within the group.
Net debt reconciliation
31 December 31 December
2019 2018
GBP000 GBP000
-------------------------------------------------------------------- ----------------------- -------------------
Cash and cash equivalents 8,194 15,112
Borrowings - including capitalised fees (13,071) (20,980 )
-------------------------------------------------------------------- ----------------------- -------------------
Net debt (4,877) (5,868)
Capitalised fees (1,272) (518)
Net debt excluding capitalised fees (6,149) (6,386)
-------------------------------------------------------------------- ----------------------- -------------------
31 December 2019 31 December 2018
----------------------- ------------------------------------------- --------------------------------------------
Cas h and cash Cas h and cash
equivalents Borrowings Total equivalents Borrowings Total
----------------------- ---------------------- ---------- ------- ----------------------- ---------- -------
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
At 1 January 15,112 (20,980) (5,868) 15,727 (21,240) (5,513)
Repayment of bond (21,355) 21,355 - (1,722) 1,722 -
Interest paid on
borrowings (2,021) - (2,021) (1,751) - (1,751)
Drawdown of RBL 19,319 (19,319) - - - -
Capitalised fees (1,059) 1,308 249 - - -
Repayment of RBL (4,639) 4,639 - - - -
Foreign exchange
adjustments (307) 645 338 371 (1,238) (867)
Other cash flows 3,144 - 3,144 2,487 - 2,487
Other non-cash
movements - (719) (719) - (224) (224)
At 31 December 8,194 (13,071) (4,877) 15,112 (20,980) (5,868)
----------------------- ---------------------- ---------- ------- ----------------------- ---------- -------
11 Borrowings
31 December 2019 31 December 2018
------------------------------ ------------------------------
Current Non-current Total Current Non-current Total
GBP000 GBP000 GBP000 GBP000 GBP000 GBP000
----------------------------------------------- ------- ----------- -------- ------- ----------- --------
Bonds - secured - - - (2,389) (18,591) (20,980)
Reserve-Based Lending Facility (RBL) - secured - (13,071) (13,071) - - -
----------------------------------------------- ------- ----------- -------- ------- ----------- --------
In 2013, the Company and Norsk Tillitsmann ("Bond Trustee")
entered into a Bond Agreement for the Company to issue up to $165.0
million secured bonds and up to $30.0 million unsecured bonds
(issued at 96% of par). These bonds were subsequently listed on
Oslo Bors and the Alternative bond market in Oslo. Both secured and
unsecured bonds carried a coupon of 10% per annum (where interest
was payable semi-annually in arrears). The secured bonds were
amortised semi-annually at 2.5% of the initial loan amount. Final
maturity on the secured notes was on 22 March 2018 and on the
unsecured notes was 11 December 2018.
In April 2017, the Company restructured its debt resulting in
the equitisation of the unsecured bonds and a
repayment/equitisation of a portion of the secured bonds. The
restructuring reduced the total aggregate face value of the secured
bonds to $30.4 million. The interest rate was reduced to 8%, the
repayment term was extended to 30 June 2021, and the amortisation
rate was increased to 5% of the initial loan amount from 23 March
2018.
On 19 November 2019, the Group repaid its secured bonds at par
value (100%) plus accrued interest through the drawdown of $25
million from the RBL with BMO Capital Markets.
Reserve Based Lending Bank Facility Loan (RBL)
On 3 October 2019, the Company announced that it had signed a
$40.0 million RBL Facility with BMO Capital Markets (BMO). In
addition to the committed $40.0 million RBL, a further $20.0
million is available on an uncommitted basis, and can be used for
any future acquisitions or new conventional developments. The RBL
has a five-year term, an interest rate of LIBOR plus 4.0%, matures
in September 2024 and is secured on the Company's assets. The RBL
is subject to a semi-annual redetermination in May and November
when the loan availability will be recalculated taking into account
forecast commodity prices, remaining field reserves (assessed by an
independent reserves auditor annually) and the latest forecast of
operating and capital costs.
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 EBITDAX for the previous 12
months shall be less than or equal to 3.5:1.
A loss of GBP0.7 million arising from debt re-financing was
recognised for the year ended 31 December 2019.
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).
12 Provisions
31 December 31 December
2019 2018
Decommissioning provision GBP000 GBP000
-------------------------------------------------------------- ----------- -----------
At 1 January (37,946) (42,117)
Utilisation of provision 1,760 91
Unwinding of discount (note 3) (1,310) (1,105)
Reassessment of decommissioning provision (note 7 and note 8) (7,683) (4,737)
Transfer (from)/to liabilities held for sale (9,922) 9,922
-------------------------------------------------------------- ----------- -----------
At 31 December (55,101) (37,946)
-------------------------------------------------------------- ----------- -----------
The Group spent GBP1.8 million on decommissioning during the
year.
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 36 years from year-end (2018: 1 to 26 years). The provisions are
based on the Groups' internal estimate as at 31 December 2019.
Assumptions are based on the current experience from
decommissioning wells which management believes is a reasonable
basis upon which to estimate the future liability. The estimates
are reviewed regularly to take account of any material changes to
the assumptions. Actual decommissioning costs will ultimately
depend upon future costs for decommissioning which will reflect
market conditions and regulations at that time. Furthermore, the
timing of decommissioning is uncertain and is likely to depend on
when the fields cease to produce at economically viable rates.
This, in turn, will depend on factors such as future oil and gas
prices, which are inherently uncertain.
A risk free rate range of 1.27% to 3.03% is used in the
calculation of the provision as at 31 December 2019 (2018: Risk
free rate range of 0.98% to 3.04%).
13 Subsequent events
On 24 January 2020, the Group issued 66,076 Ordinary GBP0.00002
shares in relation to the Group's SIP scheme. The shares were
issued at GBP0.47 resulting in share premium of GBP31,054.
The global pandemic of Covid-19 in early 2020 has caused
worldwide economic disruption. The Group considers this to be a
non-adjusting post balance sheet event as of 31 December 2019. As
described in our going concern assessment there is material
uncertainty of the potential impact of Covid-19 on the Group's
operational activities, future commodity prices and the outcome of
the May 2020 redetermination of the RBL.
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
boepd Barrels of oil equivalent per day
bopd Barrels of oil per day
GIIP Gas initially in place
Mbbl Thousands of barrels
MMboe Millions of barrels of oil equivalent
MMscfd Millions of standard cubic feet per day
NBP National balancing point - a virtual trading location for
the sale and purchase and exchange of UK natural gas
OIIP Oil initially in place
PEDL United Kingdom petroleum exploration and development
licence.
PL Production licenceSoS Secretary of State
RoSPA Royal Society for the Prevention of Accidents
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.
END
FR KKFBKDBKBNQK
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