REG-Genel Energy PLC Genel Energy PLC: Half-Year Results
03/08/2021 07:05
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Genel Energy PLC (GENL)
Genel Energy PLC: Half-Year Results
03-Aug-2021 / 07:00 GMT/BST
Dissemination of a Regulatory Announcement that contains inside
information according to REGULATION (EU) No 596/2014 (MAR), transmitted by
EQS Group.
The issuer is solely responsible for the content of this announcement.
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3 August 2021
Genel Energy plc
Unaudited results for the period ended 30 June 2021
Genel Energy plc ('Genel' or 'the Company') announces its unaudited
results for the six months ended 30 June 2021.
Bill Higgs, Chief Executive of Genel, said:
"Genel continues to deliver on its strategy and demonstrate the merits of
its business model. Capital investment made last year, despite the low oil
price and over $150 million of deferred payments, has meant this period
has benefitted from the addition of oil from Sarta and increased
production from Peshkabir, with production having increased in line with
guidance. This high-margin production will generate sufficient cash flow
in 2021 to more than cover investment in growth and the increased
dividend, and we are set to end the year in a net cash position.
Our appraisal campaign at our exciting growth assets Sarta and Qara Dagh
is now well underway, and we look forward to the results of three of these
high-potential wells later this year. Given the cash generation of the
business, our strong balance sheet, and the resilience of our business
model, we are fulfilling our aim of paying a progressive dividend by
increasing the interim payment."
Results summary ($ million unless stated)
H1 2021 H1 2020 FY 2020
Average Brent oil price ($/bbl) 65 40 42
Production (bopd, working interest) 32,760 32,100 31,980
Revenue 151.5 88.4 159.7
EBITDAX1 123.1 65.1 114.6
Depreciation and amortisation (81.8) (82.6) (153.7)
Exploration expense - (1.3) (2.2)
Impairment of oil and gas assets - (286.3) (286.3)
Impairment of receivables - (34.9) (36.9)
Operating profit / (loss) 41.3 (340.0) (364.5)
Cash flow from operating activities 91.1 85.5 129.4
Capital expenditure 58.2 58.5 109.7
Free cash flow2 22.2 6.5 (4.4)
Cash 266.4 355.3 354.5
Total debt 280.0 300.0 280.0
Net (debt) / cash3 (2.2) 57.2 6.2
Basic EPS (¢ per share) 9.3 (128.9) (152.0)
Dividends declared for the period (¢ per share) 6 5 15
1. EBITDAX is operating profit / (loss) adjusted for the add back of
depreciation and amortisation, exploration expense, impairment of
property, plant and equipment, impairment of intangible assets and
impairment of receivables
2. Free cash flow is reconciled on page 10
3. Reported cash less IFRS debt (page 11)
Highlights
• Strong cash generation from low-cost oil production:
◦ Net production averaged 32,760 bopd in H1 2021, slightly above
the average in the prior year and in line with guidance (H1 2020:
32,100 bopd)
◦ Low production cost of $3.7/bbl, oil price increase, and restart
of the override helped deliver an overall margin from our
production assets of $111 million
◦ Free cash flow for the period was $22 million, despite the
Kurdistan Regional Government ('KRG') changing its payment
schedule from one to two months in arrears, moving c.$30 million
that was due in H1 into July
◦ $123 million of cash proceeds were received in H1 2021 (H1 2020:
$110 million)
• Investing in growth:
◦ Our high-potential drilling campaign is well underway, with the
QD-2 well at Qara Dagh having spud in April, and the Sarta-5 well
in June
◦ $58 million of capital expenditure in H1 2021, with activity
accelerating in H2
• Financial strength to underpin a material and progressive dividend:
◦ Cash of $266 million, with net debt of $2.2 million
◦ Due to the rise in the oil price boosting expected cash
generation, and Management's confidence in Genel's future
prospects, interim dividend increased to 6¢ per share (H1 2020:
5¢ per share)
• A socially responsible contributor to the global energy mix:
◦ Zero lost time injuries ('LTI') and zero tier one loss of primary
containment ('LOPC') events at Genel and TTOPCO operations. Now
no LTIs since 2015, with over 14 million work hours since the
last incident, and no LOPCs since 2017
◦ Second GRI compliant Sustainability Report issued today
Outlook
• Production guidance for 2021 of slightly above the 2020 average of
31,980 bopd maintained
• 2021 capital expenditure guidance maintained at $150 million to $200
million, with the expectation that expenditure will now be around the
middle of this range, following delays in approvals from the KRG and
ongoing challenges relating to COVID-19 causing some planned activity
to move to Q1 2022
• High-impact appraisal results to come in 2021:
◦ Results from the QD-2 and Sarta-5 wells are expected around the
end of Q3 2021
◦ The Sarta-1D well is set to spud in coming days
◦ Sarta-6 well is scheduled to get underway immediately following
the completion of drilling at Sarta-5
• Genel expects to generate free cash flow in 2021 and end the year in a
net cash position, despite material investment in growth
Enquiries:
Genel Energy
+44 20 7659 5100
Andrew Benbow, Head of Communications
Vigo Communications
+44 20 7390 0230
Patrick d'Ancona
There will be a presentation for analysts and investors today at 0900 BST,
with an associated webcast available on the Company's
website, 1 www.genelenergy.com.
Genel is pleased to announce the appointment of Jefferies as Joint
Corporate Broker to the Company, effective immediately. Jefferies will
work alongside J.P. Morgan Cazenove, Genel's current Joint Corporate
Broker.
This announcement includes inside information.
Disclaimer
This announcement contains certain forward-looking statements that are
subject to the usual risk factors and uncertainties associated with the
oil & gas exploration and production business. Whilst the Company believes
the expectations reflected herein to be reasonable in light of the
information available to them at this time, the actual outcome may be
materially different owing to factors beyond the Company's control or
within the Company's control where, for example, the Company decides on a
change of plan or strategy. Accordingly, no reliance may be placed on the
figures contained in such forward looking statements. The information
contained herein has not been audited and may be subject to further
review.
CEO STATEMENT
We have a business model that is designed to be resilient in tough times,
and to thrive when times are good. 2020 was a challenging year, but our
resilience allowed us to continue strategic execution that paved the way
for an exciting year in 2021. While the increase in the oil price has
therefore been very welcome, boosting our revenues and cash generation, it
does not change our strategy. This remains simple - increase low-cost
production, invest in growth, and pay a material and progressive dividend.
We continue to deliver on this strategy.
Executing our strategy
In line with guidance, our production has increased slightly year-on-year.
This has been driven by the addition of a fourth producing field at Sarta,
as we further strengthen our position as the most diversified producer in
the Kurdistan Region of Iraq ('KRI'). Production at the Tawke PSC also
remains robust, with Peshkabir in particular continuing to perform very
well.
Our commitment to rigorously controlling our costs, coupled with the
material recovery in the oil price, helped us to generate free cash flow
of over $20 million in the first half of 2021. Our low-cost production is
highly cash-generative, providing the financial strength to then invest in
exciting growth areas, as we seek to fulfil our goal of creating material
shareholder value.
Our strong financial performance would have been stronger still without
the KRG changing its payment schedule in May, which resulted in only five
monthly payments being received. While this amendment, and the change to
the receivable recovery payment method, is frustrating, it marks a
deferral of payment rather than a removal, and we are in discussions with
the KRG regarding the pace of Genel's receivable recovery payments. At
present, the KRG sees the IOC debts as interest free, and we are working
to determine if there is a more equitable solution. In May, the KRG
committed to reviewing the payment mechanism, and we look forward to
hearing from them in this regard.
We are also attempting to work with the KRG to drive forward the
development of Bina Bawi. This remains a potentially valuable project to
Genel, and of national significance to the KRI, where we want to develop
our existing licence to the benefit of local and national stakeholders.
The resources in place are such that its development is of strategic
importance, and we continue to attempt to drive forward this project, and
explore all avenues to create shareholder value.
Investing in growth
Sarta and Qara Dagh have the potential to create significant value and are
priority projects for Genel. The strength of our balance sheet and
confidence in consistent payments mean that we are able to invest
significantly in these projects this year.
At Sarta, while pilot production has not reached the levels that we had
hoped in H1, it is providing valuable information regarding the future
development of the field while generating meaningful cash to support the
funding of the appraisal campaign. The three well programme is a key focus
this year, and we look forward to the results of the campaign, which is
now underway following the spudding of Sarta-5. The wells will help give
us an understanding of the potential of the field, as we work with Chevron
to ascertain the optimal field development plan.
Good progress is also being made with the QD-2 well, which has been
drilling since April, and we eagerly await results in around two months'
time.
A socially responsible contributor to the global energy mix
COVID-19 has, in many ways, heightened our sustainability ambitions, and
as we expand our operations we continue to support the communities in
which we operate through investment in social projects, providing direct
local employment and fostering wider economic opportunities for companies
in the KRI. 28 local companies are currently providing services to our
operations.
Our 2020 equity-based carbon intensity figure of 13 kg CO2e/bbl was well
below the industry average of c.20 kg CO2e/bbl, and while new production
at Sarta will increase this in 2021, our focus on an asset life-cycle
approach helps us deliver a carbon footprint that aligns with the Paris
Agreement 1.5 degree pathway and leads to net zero by 2050. The
reinjection of gas from Peshkabir into the Tawke field has already
materially reduced our emissions, and Ministerial approval has been
granted for the Sarta field development plan including dispensation for
flaring during early development, with plans in place to invest in a
longer-term GHG emission reduction project at the field.
We strongly believe that fulfilling our purpose requires that Genel not
only be measured by what we achieve, but also by the way in which we
achieve it. As part of our efforts to further strengthen our ESG
performance, Genel continues its commitment to the UN Sustainable
Development Goals and UN Global Compact's 10 Principles on human rights,
labour standards, the environment, and anti-corruption. More about all
aspects of our ESG performance can be read in our comprehensive 2020
Sustainability Report, which has been issued today and is available on our
website.
Outlook and dividend
Given the level of activity expected in H2, with increased drilling also
expected at the Tawke field pending approval from the MNR, capital
expenditure is heavily biased towards the second half of the year. Despite
this increase in spending and the ongoing expansion of our operating
capability, and with the one month deferral in payments meaning we expect
11 monthly payments this year, we are forecasting ending the year in a net
cash position at the expected forward oil price. The strength of this
financial platform remains central to our strategy.
With the oil price currently remaining robust, and our confidence in our
portfolio and ability to grow the company, we have increased the interim
dividend by 1¢ to 6¢ per share.
OPERATING REVIEW
The first half of 2021 has seen Genel operations in the KRI expand
significantly. Genel has a long history of working in the KRI, although
the QD-2 well is the first sole operated well that Genel has undertaken.
With Genel also transitioning to the operatorship at Sarta, there has been
a step-change in our operational capability on the ground. It is a
testament to the team in place, and the positive working culture that has
been created, that we have continued to work efficiently and without any
lost time injuries or Tier 1 containment losses in the period.
Production
Production in H1 2021 has increased by 2% on the prior year period, in
line with guidance, following the addition of production at Sarta and the
robust performance of Peshkabir.
Gross production Net production Gross production Net production
(bopd)
H1 2021 H1 2021 H1 2020 H1 2020
Tawke 48,970 12,240 59,790 14,950
Peshkabir 62,170 15,540 48,790 12,200
Taq Taq 6,490 2,860 11,260 4,950
Sarta 7,080 2,120 - -
Total 124,710 32,760 119,840 32,100
PRODUCING ASSETS
Tawke PSC (25% working interest)
Gross operated Tawke licence production averaged 110,300 bopd in Q2 2021,
of which the Peshkabir field contributed 63,000 bopd and the Tawke field
47,300 bopd.
Five new wells are scheduled at Peshkabir in 2021. The first is in
production, two more are being completed and are expected in service soon
and two more will be drilled in the remainder of the year, contributing to
the field's 2021 production.
With no new wells having come on production at the Tawke field in more
than a year, the natural production decline has been partially offset by
pressure support from reinjection of over 20 million cubic feet of gas per
day from the Peshkabir field in addition to workovers and interventions of
existing wells.
Subject to final contract approval from the Ministry of Natural Resources,
Genel expects five Tawke wells, three of which will be side tracks, to be
drilled before year end.
Sarta (30% working interest)
The Sarta licence has significant potential, and work done in 2021 will
help us understand the extent of this potential. Our estimation of
reserves and resources at year-end 2021 will be updated following the
assessment of three key inputs - ongoing analysis of existing data, pilot
production, and the three high-impact appraisal wells being drilled.
A detailed re-evaluation of the seismic depth conversion and associated
reinterpretation by Chevron, adopted by the joint venture for well
planning purposes, has resulted in a significant upwards revision to the
gross rock volume associated with the field. This will form the basis for
future reserves and resources audit work.
Production from the Sarta pilot project continues to provide invaluable
dynamic data from which we can plan future activities, and averaged over
7,000 bopd in H1 2021. June saw the highest average monthly production in
the year to date, 8,400 bopd, following the maximisation of uptime in the
month. Of this production, the Sarta-2 well produced c.6,400 bopd, and the
Sarta-3 well c.2,000 bopd, with the latter having been partially plugged
back to manage water ingress from the Adaiyah production stream, the
origin of which is yet to be determined. With production temporarily
limited to the thinner, less volumetrically significant Mus reservoir, a
fall in pressure in June across both wells resulted in Genel and the
operator, Chevron, reassessing the optimal way to produce these wells
ahead of the addition of production from Sarta-1D, a well set to access
production from the entire Adaiyah reservoir section for the first time
and via a smart completion. Reservoir surveillance work at the start of
the year had already proved strong communication between the Mus reservoir
in Sarta-2 and the Mus reservoir in Sarta 3 over a short distance of c.3
km, together representing a portion of the container more limited than our
expected extent of the Mus reservoir.
In order to analyse Mus pressure data and provide valuable learnings for
longer-term field production, the Sarta-3 well was taken off line at the
end of June for data gathering purposes. Since then, Mus pressure decline
at the Sarta-2 well has in response slowed considerably, potentially
indicative of secondary pressure support and associated oil influx.
To prudently manage the reservoir and associated production from the Pilot
facility until Sarta-1D comes online around the end of the year, the joint
venture partners plan to continue to manage the offtake from the Mus. This
period offers multiple invaluable pilot data gathering opportunities to
inform the longer term Sarta development plans.
The 2021 appraisal drilling campaign, which is targeting a material
portion of the 250 MMbbls of contingent resources in the Jurassic, is now
underway and is not impacted by the early results from the pilot
production.
Preparations for Sarta-1D and the construction of a flowline linking it to
the facility are well underway. The Viking Rig is mobilising to the
location ahead of spud in the coming days, and clearing for the flowline
is nearing completion. The Sarta-5 well spud in June, with results
expected in late Q3/early Q4. This will be followed immediately by Sarta-6
with the same rig, with results now expected by late Q1 2022. In a success
case, Sarta-6 will be bought onto production in short order via a flowline
back to the facility, while Sarta-5 will be produced via a standalone
temporary facility given its distance from the existing facility.
Taq Taq (44% working interest, joint operator)
Production at Taq Taq averaged 6,490 bopd in H1, in line with
expectations. Activity at Taq Taq is focused on maximising cash generation
and no further work is scheduled at the field prior to 2022.
PRE-PRODUCTION ASSETS
Qara Dagh (40% working interest, operator)
Genel's high-potential drilling campaign began with the spud of the QD-2
well in April 2021. This well is appraising the crest of a 50 km long
structure at Qara Dagh, around 10 km from the location of the QD-1 well,
which flowed light oil in 2011. The well is currently at a depth of
c.2,300 metres. Results are anticipated around the end of Q3 2021.
Our social investment programme is continuing, working with local
companies to deliver projects that respond to the requirements of local
communities. To date a local primary school has been renovated and
secondary school refurbished, a football pitch constructed, a road
restored, and clean water provided to local villages. There are also over
300 local people employed at Qara Dagh, and contracts awarded to 24 local
companies.
Bina Bawi and Miran (100% working interest, operator)
Genel continues to drive engagement with the KRG at the highest level, as
we seek a resolution that will allow progress to be made towards the
development of Bina Bawi.
The Company remains excited by the potential that Bina Bawi presents, with
development of the asset having the ability to create material value for
both Genel and the KRG. The size of the resource base makes it a
strategically important project that could make a significant difference
to the region and its energy mix. It has, however, proved difficult to
engage the KRG under the PSC in order to obtain the necessary approvals to
proceed and every effort has been, and is being, made to obtain these
approvals so that the project can be progressed in the near-term.
Genel continues to maintain capex discipline, and will only commence
investment upon certainty of alignment with the KRG and a clear path to
monetisation.
African exploration
A farm-out process relating to the highly prospective SL10B13 block (100%
working interest and operator) in Somaliland is ongoing, and there remains
active engagement with potential partners with respect to the opportunity.
Genel continues to work towards a farm-out campaign aimed at bringing a
partner onto the Lagzira licence offshore Morocco (75% working interest
and operator).
FINANCIAL REVIEW
Overview
The rapid recovery in the oil price so far this year has been quicker and
greater than expected, which has had a material positive impact on the
revenue and cash generation of our production business. Whereas through
much of 2020 we were flexing our business model to protect the business in
a downside environment, the past six months have seen us use our
flexibility to capitalise on the material improvement in the external
environment.
If as expected this oil price strength is sustained through the year, it
will reward our determination in the second half of 2021 to return to
drilling activity as quickly as possible on the Tawke PSC and to take
Sarta to first oil, despite the challenging operating conditions and
uncertain oil price outlook at the time.
Peshkabir is currently producing over 10,000 bopd more than its average
production in 2020, and although Sarta production is currently relatively
low, because of its early stage in PSC economics its barrels are valuable.
Sarta revenue per barrel of $39/bbl in the period is higher than Tawke and
Peshkabir, which both benefit from the override payment that broadly
doubles profitability.
Revenue at the half year of $152 million is close to full year revenue
last year, with margin per barrel increasing from $6/bbl in 2020 to
$19/bbl, benefitting from the resumption of the override, which
contributed $9/bbl.
EBITDAX of $123 million is greater than the full year EBITDAX last year.
Production asset margin of $111 million reflects the high cash generation
of our production and results in free cash flow before investment in
growth of $62 million. On an annualised basis this represents over 20% of
our current market capitalisation. Production asset margin is provided to
show the performance of our production assets. Free cash flow before
investment in growth is provided to show the cash generated by the
business in the period that is consequently available for allocation to
where it best serves the business.
The KRG has commenced payment of the $159 million owed for unpaid sales
made from November 2019 to February 2020. Although only $14 million has
been received to date and we have not yet had any dialogue relating to the
amended payment mechanism that the KRG committed to in June, consistent
payments of amounts due is encouraging.
Unfortunately, the benefit of the receipt of amounts owed for deferred
receivable has been offset by the KRG unilaterally moving payment terms
from one month in arrears to two months in arrears, which has impacted our
free cash flow in the period by $30 million.
Despite the change to payment terms explained above, our resulting free
cash flow generation from production assets has more than covered our
investment in growth at Sarta and Qara Dagh and the final dividend meaning
that the only material change in cash in the period has been the $81
million repayment of bonds that was reported at year-end. The bonds were
called in December 2020 and settled in early January 2021.
Capital expenditure of $58 million in the first half of the year was split
evenly between production capex, principally at Tawke, and growth capex at
Sarta and Qara Dagh. Overall our free cash flow in the first half of 2021
was $22 million, up $16 million on the prior period despite the $30
million impact of the change in payment terms.
(all figures $ million) H1 2021 H1 2020 FY 2020
Brent average oil price $65/bbl $40/bbl $42/bbl
Revenue 151.5 88.41 159.71
Production costs (21.7) (16.8) (32.7)
Producing asset capex (19.3) (35.7) (56.5)
Production asset margin 110.5 35.9 70.51
G&A (excl. depreciation and amortisation) (6.7) (6.5) (12.4)
Net cash interest2 (13.1) (13.4) (23.8)
Working capital 1.4 7.8 (6.9)
Change in payment days3 (30.4) 11.6 21.8
Free cash flow before investment in growth 61.7 35.4 49.2
Pre-production capex (38.9) (22.8) (53.2)
Working capital and other (0.6) (6.1) (0.4)
Free cash flow 22.2 6.5 (4.4)
Deferred receivables (note 10) plus suspended 145.0 130.4 158.6
override1
1 Nominal value of deferred receivables is $107.2 million (H1 2020: $120.8
million, FY 2020: $120.8 million). FY2020 revenue does not include $37.8
million (H1 2020: $9.6 million) of invoiced override revenue where payment
was suspended from March 2020 to December 2020 (see note 1).
2 Net cash interest is bond interest payable less bank interest income
(see note 5).
3 In March 2020, KRG changed payments terms from 3 months in arrears to 1
month in arrears, improving free cash flow for H1 2020 and FY 2020. In May
2021, KRG changed payment terms from 1 month in arrears to 2 months in
arrears, adversely impacting free cash flow in H1 2021.
The focus of our business model remains unchanged:
• Progress value creative, high priority growth projects in a
challenging environment with a focus on near term cash generation;
• Demonstrate material flexibility in capital allocation, supporting the
generation of free cash flow
• Pay a sustainable and progressive dividend.
Our resilience and financial strength positions us well to take advantage
of an unpredictable environment. Company liquidity at the half year was
$266 million, with the resilience of our business model and proactive
management action protecting the balance sheet through the low oil price
of last year and through a period of material investment in growth this
year. This leaves the Company well-funded to progress and develop Sarta
and Qara Dagh if there is drilling success this year, as well as
progressing Bina Bawi gas and oil if there is commercial success in
discussions with the KRG.
Capital expenditure
We guided capital expenditure of $150-200 million. At the half year,
capital expenditure of $58 million has been spent principally on wells at
Peshkabir and preparation for the four appraisal wells at Sarta and Qara
Dagh. The appraisal campaign targets conversion of resources to reserves
and has potential for material value delivery. The second half will
therefore see a material increase in capital expenditure, which we expect
to be covered by free cash flow.
Dividend
The material improvement in oil price, resumption of the override, and
commencement of payment of amounts owed for deferred receivables provides
the Company with a strong cash flow generation outlook.
The Company has generated $62 million of free cash flow before investment
in growth in the period, despite the $30 million adverse impact of the
change in payment terms. This demonstrates a highly cash generative
business with material upside even before consideration of incremental
production that may come from that investment in growth in the second half
of the year.
Against this backdrop the Board has approved an increase in the interim
dividend from 5 cents to 6 cents, representing just under $3 million per
annum, and reaffirms its commitment to the dividend being sustainable and
progressive.
Financial priorities
The table below summarises our progress against the 2021 financial
priorities of the Company as set out at our 2020 results.
FY2021 financial priorities Progress
• Maintain our financial strength Strong liquidity balance, broadly
and continue protecting the liquidity neutral for the period
balance sheet after settlement of debt, broadly
net debt neutral position at
half-year expected to return to net
cash by the end of the year
• Tawke PSC drilling well
underway, with the Operator
seeking to expand the 2021 work
programme
• Maximise NPV by prioritising • Sarta and Qara Dagh appraisal
highest value investment in assets programme underway and, despite
with ongoing or near-term cash and delays in obtaining approvals
value generation from the MNR, expected to
deliver meaningful results in
the year
• We continue to seek to progress
Bina Bawi in the right way
under the right conditions
• 2021 activity broadly in line,
• Deliver 2021 work programme on although some delays on
time and on budget obtaining approvals may mean
some activity happens a little
later than planned
• Continue to focus on growing our • c.$100 million of investment in
income streams and cash growth in 2021 demonstrates our
generation, bringing greater commitment to improving on
resilience and diversity to the these objectives and building a
business and supporting our diverse, resilient reserves
sustainable and progressive base with longevity
dividend programme
Financial results for the year
Income statement
(all figures $ million) H1 2021 H1 2020 FY 2020
Production (bopd, working interest) 32,760 32,100 31,980
Profit oil 57.6 24.0 55.4
Cost oil 43.3 47.6 84.9
Override royalty 50.6 16.8 19.4
Revenue 151.5 88.4 159.7
Production costs (21.7) (16.8) (32.7)
G&A (excl. depreciation and amortisation) (6.7) (6.5) (12.4)
EBITDAX 123.1 65.1 114.6
Depreciation and amortisation (81.8) (82.6) (153.7)
Impairment - (321.2) (323.2)
Exploration expense - (1.3) (2.2)
Net finance expense (15.7) (14.7) (52.2)
Income tax expense - - (0.2)
Profit / (Loss) 25.6 (354.7) (416.9)
Working interest production of 32,760 bopd increased (H1 2020: 32,100
bopd), with revenue rising from $88 million to $152 million, principally
caused by the higher Brent oil price and resumed override from January
onwards.
Production costs of $22 million increased from the prior year (H1 2020:
$17 million), with cost per barrel $3.7/bbl in H1 2021 (H1 2020:
$2.9/bbl). Both increases have been caused by the addition of Sarta, which
commenced production in December 2020. We expect that the overall
operating cost per barrel at the Sarta field will reduce to around $5/bbl
once production has increased to around the facility capacity - the Sarta
plant is currently operating at less than 50%. This compares favourably to
revenue per barrel of $38/bbl.
General and administration costs were $7 million (H1 2020: $7 million), of
which corporate cash costs were $6 million (H1 2020: $5 million).
The increase in revenue resulted in a similar increase to EBITDAX, which
was $123 million (H1 2020: $65 million). EBITDAX is presented in order for
the users of the financial statements to understand the cash profitability
of the Company, which excludes the impact of costs attributable to
exploration activity, which tend to be one-off in nature, and the non-cash
costs relating to depreciation, amortisation and impairments.
Depreciation of $59 million (H1 2020: $52 million) and Tawke intangibles
amortisation of $23 million (H1 2020: $31 million) were broadly in line
with last period in total.
Bond interest expense of $13 million (H1 2020: $15 million) decreased due
to lower debt and lower coupon rate.
In relation to taxation, under the terms of the KRI production sharing
contracts, corporate income tax due is paid on behalf of the Company by
the KRG from the KRG's own share of revenues, resulting in no corporate
income tax payment required or expected to be made by the Company. Tax
presented in the income statement was related to taxation of the service
companies (H1 2021: nil, H1 2020: nil).
Capital expenditure
Capital expenditure is the aggregation of spend on production assets ($19
million) and pre-production assets ($39 million) and is reported to
provide investors with an understanding of the quantum and nature of
capital investment. Capital expenditure for the period was $58 million,
predominantly focused on production assets and the Sarta PSC ($15 million)
and Qara Dagh ($21 million):
(all figures $ million) H1 2021 H1 2020 FY 2020
Cost recovered production capex 19.3 35.7 56.5
Pre-production capex - oil 15.3 11.5 30.0
Pre-production capex - gas 1.3 5.9 10.0
Other exploration and appraisal capex 22.3 5.4 13.2
Capital expenditure 58.2 58.5 109.7
Cash flow, cash, net cash and debt
Gross proceeds received totalled $123 million (H1 2020: $110 million), of
which $29 million (H1 2020: $23 million) was received for the override
royalty and $14 million for receivable recovery.
(all figures $ million) H1 2021 H1 2020 FY 2020
Brent average oil price $65/bbl $40/bbl $42/bbl
EBITDAX 123.1 65.1 114.6
Working capital (32.0) 20.4 14.8
Operating cash flow 91.1 85.5 129.4
Producing asset cost recovered capex (21.1) (38.1) (60.2)
Development capex (16.0) (11.6) (25.3)
Exploration and appraisal capex (16.8) (13.7) (24.2)
Restricted cash - (0.1) 3.0
Interest and other (15.0) (15.5) (27.1)
Free cash flow 22.2 6.5 (4.4)
Free cash flow is presented in order to show the reader the free cash
generated for equity. Free cash flow was $22 million (H1 2020: $7
million), with an overall decrease in cash of $88 million in the year (H1
2020: $35 million decrease) after payment of the FY2020 final dividend and
$81 million settlement of the remaining 2022 bond debt, which was called
in December 2020.
(all figures $ million) H1 2021 H1 2020 FY 2020
Free cash flow 22.2 6.5 (4.4)
Dividend paid (incl. expenses) (29.0) (41.3) (55.3)
Purchase of own shares (0.3) (0.7) (3.4)
Bond refinancing (81.0) - 28.9
Other - 0.1 (2.0)
Net change in cash (88.1) (35.4) (36.2)
Opening cash 354.5 390.7 390.7
Closing cash 266.4 355.3 354.5
Debt reported under IFRS (268.6) (298.1) (348.3)
Net (debt) / cash (2.2) 57.2 6.2
The 2025 bonds have two financial covenant maintenance tests:
Financial covenant Test H1 2021
Equity ratio (Total equity/Total assets) > 40% 63%
Minimum liquidity > $30m $266 million
Net assets
Net assets at 30 June 2021 were $929 million (31 December 2020: $930
million) and consist primarily of oil and gas assets of $1,073 million (31
December 2020: $1,095 million), trade receivables of $120 million (31
December 2020: $94 million) and net debt of $2 million (31 December 2020:
$6 million net cash).
Liquidity / cash counterparty risk management
The Company monitors its cash position, cash forecasts and liquidity on a
regular basis. The Company holds surplus cash in treasury bills or on time
deposits with a number of major financial institutions. Suitability of
banks is assessed using a combination of sovereign risk, credit default
swap pricing and credit rating.
Dividend
A final dividend distribution of $29 million was made in June 2021 (June
2020: $28 million).
The interim dividend is increasing to 6¢ per share (2020: 5¢ per share), a
total distribution of $17 million. Total dividends declared in 2021 amount
to $46 million (2020: $41 million), representing 16¢ per share (2020:
15¢ per share). The payment timetable for the interim dividend is below:
The payment timetable for the interim dividend is below:
• Ex-dividend date: 11 November 2021
• Record Date: 12 November 2021
• Payment Date: 10 December 2021
Going concern
The Directors have assessed that the Company's forecast liquidity provides
adequate headroom over forecast expenditure for the 12 months following
the signing of the half-year condensed consolidated financial statements
for the period ended 30 June 2021 and consequently that the Company is
considered a going concern. In assessing going concern, the Directors have
assessed that prolonged prevalence of COVID-19 may have a further negative
impact on the oil price and in turn revenues, operational activity and
receipt of amounts owed. The Company's low run rate costs, flexible
capital programme, and strong cash position provide appropriate mitigation
of the reduction of cash inflows that COVID-19 may cause for the going
concern basis to remain appropriate.
Principal risks and uncertainties
The Company is exposed to a number of risks and uncertainties that may
seriously affect its performance, future prospects or reputation and may
threaten its business model, future performance, solvency or liquidity.
The following risks are the principal risks and uncertainties of the
Company, which are not all of the risks and uncertainties faced by the
Company: the development and recovery of oil reserves; reserve
replacement; commercialisation of the KRI gas business; M&A activity; the
KRI natural resources industry and regional risk; a deterioration in the
external environment caused by COVID-19; corporate governance failure;
capital structure and financing; local community support; the
environmental impact of oil and gas extraction; and health and safety
risks. Further detail on many of these risks was provided in the 2020
Annual Report. Since year-end, the environmental impact of oil and gas
extraction has been added to the risk register, reflecting the increased
focus on ESG issues, along with the impact of COVID-19.
Statement of directors' responsibilities
The directors confirm that these condensed interim financial statements
have been prepared in accordance with International Accounting Standard
34, 'Interim Financial Reporting', as adopted by the European Union and
that the interim management report includes a true and fair review of the
information required by DTR 4.2.7 and DTR 4.2.8, namely:
• an indication of important events that have occurred during the first
six months and their impact on the condensed set of financial
statements, and a description of the principal risks and uncertainties
for the remaining six months of the financial year; and
• material related-party transactions in the first six months and any
material changes in the related-party transactions described in the
last annual report.
The directors of Genel Energy plc are listed in the Genel Energy plc
Annual Report for 31 December 2020. A list of current directors is
maintained on the Genel Energy plc website: 2 www.genelenergy.com
By order of the Board
Bill Higgs
CEO
3 August 2021
Esa Ikaheimonen
CFO
3 August 2021
Disclaimer
This announcement contains certain forward-looking statements that are
subject to the usual risk factors and uncertainties associated with the
oil & gas exploration and production business. Whilst the Company believes
the expectations reflected herein to be reasonable in light of the
information available to them at this time, the actual outcome may be
materially different owing to factors beyond the Company's control or
within the Company's control where, for example, the Company decides on a
change of plan or strategy. Accordingly, no reliance may be placed on the
figures contained in such forward looking statements.
Condensed consolidated statement of comprehensive income
For the period ended 30 June 2021
Year
6 months to 30 6 months to
June 2021 30 June 2020 to 31 Dec
2020
Note $m $m $m
Revenue 3 151.5 88.4 159.7
Production costs 4 (21.7) (16.8) (32.7)
Depreciation and amortisation 4 (81.7) (82.5) (153.3)
of oil assets
Gross profit / (loss) 48.1 (10.9) (26.3)
Exploration expense 4 - (1.3) (2.2)
Impairment of intangible assets 4-8 - (44.3) (44.3)
Impairment of property, plant 4-9 - (242.0) (242.0)
and equipment
Impairment of receivables 10 - (34.9) (36.9)
General and administrative 4 (6.8) (6.6) (12.8)
costs
Operating profit / (loss) 41.3 (340.0) (364.5)
Operating profit / (loss) is
comprised of:
EBITDAX 123.1 65.1 114.6
Depreciation and amortisation 4 (81.8) (82.6) (153.7)
Exploration expense 4 - (1.3) (2.2)
Impairment of intangible assets 4-8 - (44.3) (44.3)
Impairment of property, plant 4-9 - (242.0) (242.0)
and equipment
Impairment of receivables
10 - (34.9) (36.9)
Finance income 5 0.1 1.6 2.0
Bond interest expense 5 (13.2) (15.0) (31.5)
Other finance expense 5 (2.6) (1.3) (22.7)
Profit / (Loss) before income 25.6 (354.7) (416.7)
tax
Income tax expense 6 - - (0.2)
Profit / (Loss) and total
comprehensive income / 25.6 (354.7) (416.9)
(expense)
Attributable to:
Owners of the parent 25.6 (354.7) (416.9)
25.6 (354.7) (416.9)
Earnings / (Loss) per ordinary ¢ ¢ ¢
share
Basic 7 9.3 (128.9) (152.0)
Diluted 7 9.2 (128.9) (152.0)
Condensed consolidated balance sheet
At 30 June 2021
30 June 2021 30 June 2020 31 Dec 2020
Note $m $m $m
Assets
Non-current assets
Intangible assets 8 704.9 716.0 699.4
Property, plant and equipment 9 367.6 391.5 395.7
Trade and other receivables 10 31.4 68.3 52.1
1,103.9 1,175.8 1,147.2
Current assets
Trade and other receivables 10 95.9 30.0 48.9
Restricted cash - 3.1 -
Cash and cash equivalents 266.4 355.3 354.5
362.3 388.4 403.4
Total assets 1,466.2 1,564.2 1,550.6
Liabilities
Non-current liabilities
Trade and other payables (103.7) (124.7) (100.4)
Deferred income (16.5) (26.8) (19.7)
Provisions (47.6) (39.0) (45.9)
Interest bearing loans 11 (268.6) (298.1) (267.7)
(436.4) (488.6) (433.7)
Current liabilities
Trade and other payables (93.2) (66.9) (99.0)
Deferred income (7.5) (3.0) (7.5)
Interest bearing loans 11 - - (80.6)
(100.7) (69.9) (187.1)
Total liabilities (537.1) (558.5) (620.8)
Net assets 929.1 1,005.7 929.8
Owners of the parent
Share capital 43.8 43.8 43.8
Share premium account 3,962.9 4,005.4 3,991.9
Accumulated losses (3,077.6) (3,043.5) (3,105.9)
Total equity 929.1 1,005.7 929.8
Condensed consolidated statement of changes in equity
For the period ended 30 June 2021
Share Share Accumulated Total
capital premium losses equity
$m $m $m $m
At 1 January 2020 43.8 4,033.4 (2,691.1) 1,386.1
Loss and total comprehensive - - (354.7) (354.7)
expense
Share-based payments - - 3.0 3.0
Purchase of shares for employee - - (0.7) (0.7)
share awards
Dividends provided for or paid1 - (28.0) - (28.0)
At 30 June 2020 43.8 4,005.4 (3,043.5) 1,005.7
At 1 January 2020 43.8 4,033.4 (2,691.1) 1,386.1
Loss and total comprehensive - - (416.9) (416.9)
expense
Share-based payments - - 5.5 5.5
Purchase of shares for employee - - (3.4) (3.4)
share awards
Dividends provided for or paid1 - (41.5) - (41.5)
At 31 December 2020 and 1 43.8 3,991.9 (3,105.9) 929.8
January 2021
Profit and total comprehensive - - 25.6 25.6
income
Share-based payments - - 3.0 3.0
Purchase of shares for employee - - (0.3) (0.3)
share awards
Dividends provided for or paid1 - (29.0) - (29.0)
At 30 June 2021 43.8 3,962.9 (3,077.6) 929.1
1 The Companies (Jersey) Law 1991 does not define the expression
"dividend" but refers instead to "distributions". Distributions may be
debited to any account or reserve of the Company (including share premium
account).
Condensed consolidated cash flow statement
For the period ended 30 June 2021
31 Dec
30 June 2021 30 June 2020
2020
Note $m $m $m
Cash flows from operating
activities
Profit / (Loss) for the year 25.6 (354.7) (416.9)
Adjustments for:
Net finance expense 5 15.7 14.7 52.2
Taxation 6 - - 0.2
Depreciation and amortisation 83.0 82.6 153.7
Exploration expense 4 - 1.3 2.2
Impairments 4 - 321.2 323.2
Other non-cash items (2.9) (0.3) (3.7)
Changes in working capital:
(Increase) / Decrease in trade (25.9) 22.0 15.8
receivables
Decrease in other receivables - 0.1 0.6
(Decrease) in trade and other (4.3) (2.7) 0.4
payables
Cash generated from operations 91.2 84.2 127.7
Interest received 5 - 1.6 2.0
Taxation paid (0.1) (0.3) (0.3)
Net cash generated from operating 91.1 85.5 129.4
activities
Cash flows from investing
activities
Purchase of intangible assets (16.8) (13.7) (24.2)
Purchase of property, plant and (37.1) (49.7) (85.5)
equipment
Movement in restricted cash - (0.1) 3.0
Net cash used in investing (53.9) (63.5) (106.7)
activities
Cash flows from financing
activities
Dividends paid to company's (29.0) (41.3) (55.3)
shareholders, including expenses
Purchase of own shares (0.3) (0.7) (3.4)
Bond refinancing: part-settlement 11 (81.0) - 28.9
and new issuance
Other (1.7) (0.5) (3.3)
Interest paid (13.3) (15.0) (25.8)
Net cash used in financing (125.3) (57.5) (58.9)
activities
Net decrease in cash and cash (88.1) (35.5) (36.2)
equivalents
Foreign exchange loss on cash and - 0.1 -
cash equivalents
Cash and cash equivalents at the 354.5 390.7 390.7
beginning of the period
Cash and cash equivalents at the 266.4 355.3 354.5
end of the period
Notes to the consolidated financial statements
1. Basis of preparation
Genel Energy Plc - registration number: 107897 (the Company) is a public
limited company incorporated and domiciled in Jersey with a listing on the
London Stock Exchange. The address of its registered office is 12 Castle
Street, St Helier, Jersey, JE2 3RT.
The half-year condensed consolidated financial statements for the six
months ended 30 June 2021 and six months ended 30 June 2020 are unaudited
and have been prepared in accordance with the Disclosure and Transparency
Rules of the Financial Conduct Authority, with Article of 106 of the
Companies (Jersey) Law 1991 and with IAS 34 'Interim Financial Reporting'
as adopted by the European Union and were approved for issue on 3 August
2021. They do not comprise statutory accounts within the meaning of
Article 105 of the Companies (Jersey) Law 1991. The half-year condensed
consolidated financial statements should be read in conjunction with the
annual financial statements for the year ended 31 December 2020, which
have been prepared in accordance with IFRS as adopted by the European
Union. The annual financial statements for the period ended 31 December
2020 were approved by the board of directors on 17 March 2021. The report
of the auditors was unqualified, did not contain an emphasis of matter
paragraph and did not contain any statement under the Article 113A of
Companies (Jersey) Law 1991. The financial information for the year to 31
December 2020 has been extracted from the audited accounts.
There have been no changes in related parties since year-end and no
related party transactions that had a material effect on financial
position or performance in the period. There are not significant seasonal
or cyclical variations in the Company's total revenues.
Going concern
The Company regularly evaluates its financial position, cash flow
forecasts and its compliance with financial covenants by considering
multiple combination of oil price, discount rates, production volumes,
payments, capital and operational spend scenarios. The Company has
reported liquidity of $266.4 million, with no debt maturing until the
second half of 2025 and significant headroom on both the equity ratio and
minimum liquidity covenant. Our business model has demonstrated its
resilience in 2020, when oil price was low, 4 months of payments with a
value of $120.8 million that were due were not received, and override
income of $38 million was not paid, by delivering a small free cash out
flow after investing significantly in growth, principally bringing Sarta
to first production.
The strength of the balance sheet is expected to be maintained through
2021 and 2022, with Sarta adding a new income stream and diversifying
production risk, and capital activity in the year focused on expanding the
reserves and sources of income of the business further.
Our low-cost assets with flexibility on commitment of capital mean that we
are resilient to oil prices as low as the levels reached last year, with
the KRG also demonstrating its ability to pay consistently in times of
financial stress. In addition, specifically for the purposes of the going
concern, management have modelled a downside scenario, recognising the
impact of the COVID19 pandemic, which includes a significant reduction in
oil price from current levels combined with a reduction in production.
Even with these downsides there is considered to be sufficient cash in the
business and still more room for flexibility if needed given nature of the
discretionary capex planned.
Longer term, our low-cost, low-carbon assets, located in a region where
oil revenues provide a material proportion of funding to the government
and its people means that we are well positioned to address the
appropriate challenges and demands that climate change initiatives are
bringing to the sector. Given the footprint and the benefit to society
generated, we see our portfolio as being well-positioned for a future of
fewer and better natural resources projects, while the global energy mix
continues to require hydrocarbons.
As a result, the Directors have assessed that the Company's forecast
liquidity provides adequate headroom over its forecast expenditure for the
12 months following the signing of the half-year condensed consolidated
financial statements for the period ended 30 June 2021 and consequently
that the Company is considered a going concern.
2. Summary of significant accounting policies
The accounting policies adopted in preparation of these half-year
condensed consolidated financial statements are consistent with those used
in preparation of the annual financial statements for the year ended 31
December 2020.
The preparation of these half-year condensed consolidated financial
statements in accordance with IFRS requires the Company to make judgements
and assumptions that affect the reported results, assets and liabilities.
Where judgements and estimates are made, there is a risk that the actual
outcome could differ from the judgement or estimate made. The Company has
assessed the following as being areas where changes in judgements or
estimates could have a significant impact on the financial statements.
Significant judgements
The significant judgements that the directors have made in the process of
applying the Company's accounting policies and that have the most
significant effect on the amounts recognised in the financial statements
include; i) IFRS 15 criteria have not been met for the suspended override
revenue belonging to the period between 1 March 2020 to 31 December 2020;
ii) the Bina Bawi and Miran projects will progress. These are explained in
the context of the significant estimates below.
Significant estimates
The following are the critical estimates that the directors have made in
the process of applying the Company's accounting policies and that have
the most significant effect on the amounts recognised in the financial
statements.
Estimation of hydrocarbon reserves and resources and associated production
profiles and costs
Estimates of hydrocarbon reserves and resources are inherently imprecise
and are subject to future revision. The Company's estimation of the
quantum of oil and gas reserves and resources and the timing of its
production, cost and monetisation impact the Company's financial
statements in a number of ways, including: testing recoverable values for
impairment; the calculation of depreciation, amortisation and assessing
the cost and likely timing of decommissioning activity and associated
costs. This estimation also impacts the assessment of going concern and
the viability statement.
Proved and probable reserves are estimates of the amount of hydrocarbons
that can be economically extracted from the Company's assets. The Company
estimates its reserves using standard recognised evaluation techniques.
Assets assessed as having proven and probable reserves are generally
classified as property, plant and equipment as development or producing
assets and depreciated using the units of production methodology. The
Company considers its best estimate for future production and quantity of
oil within an asset based on a combination of internal and external
evaluations and uses this as the basis of calculating depreciation and
amortisation of oil and gas assets and testing for impairment.
Hydrocarbons that are not assessed as reserves are considered to be
resources and the related assets are classified as exploration and
evaluation assets. These assets are expenditures incurred before technical
feasibility and commercial viability is demonstrable. Estimates of
resources for undeveloped or partially developed fields are subject to
greater uncertainty over their future life than estimates of reserves for
fields that are substantially developed and being depleted and are likely
to contain estimates and judgements with a wide range of possibilities.
These assets are considered for impairment under IFRS 6.
Once a field commences production, the amount of proved reserves will be
subject to future revision once additional information becomes available
through, for example, the drilling of additional wells or the observation
of long-term reservoir performance under producing conditions. As those
fields are further developed, new information may lead to revisions.
Assessment of reserves and resources are determined using estimates of oil
and gas in place, recovery factors and future commodity prices, the latter
having an impact on the total amount of recoverable reserves.
Estimation of oil and gas asset values
Estimation of the asset value of oil and gas assets is calculated from a
number of inputs that require varying degrees of estimation. Principally
oil and gas assets are valued by estimating the future cash flows based on
a combination of reserves and resources, costs of appraisal, development
and production, production profile and future sales price and discounting
those cash flows at an appropriate discount rate.
Future costs of appraisal, development and production are estimated taking
into account the level of development required to produce those reserves
and are based on past costs, experience and data from similar assets in
the region, future petroleum prices and the planned development of the
asset. However, actual costs may be different from those estimated.
Discount rate is assessed by the Company using various inputs from market
data, external advisers and internal calculations. A post tax nominal
discount rate of 13% derived from the Company's weighted average cost of
capital (WACC) is used when assessing the impairment testing of the
Company's oil assets at year-end. Risking factors are also used alongside
the discount rate when the Company is assessing exploration and appraisal
assets.
In addition, estimation of the recoverable amounts of the Bina Bawi and
Miran cash generating units ('CGU's), which are classified under IFRS as
exploration and evaluation intangible assets and consequently carry the
inherent uncertainty explained above, include the key assessment that the
projects will progress. Progression of these projects is outside the
control of management and is dependent on the progress of government
discussions regarding supply of gas and sanctioning of development of both
of the midstream for gas and the upstream for oil. The KRG and the Company
have been focusing on progressing the Bina Bawi asset first, with success
on Bina Bawi likely to inform both of the likely structure, midstream and
downstream solution for Miran. Lack of progress on Bina Bawi could result
in significant delays in value realisation and consequently a materially
lower asset value for both assets. Under the existing production sharing
contracts ('PSC') for both Bina Bawi and Miran, the KRG had a right (not
an obligation) effective from 30 April 2020 and 31 May 2020 respectively
to take steps to terminate the PSCs if no new Gas Lifting Agreement(s) was
in place. Whilst the Company does not accept that any such right arose, or
could now be exercised, the Company has in any event been informed by the
KRG that, while negotiations are ongoing, it will not seek to serve notice
of an intention to terminate the Bina Bawi PSC. Discussions are ongoing.
Estimation of future oil price and netback price
The estimation of future oil price has a significant impact throughout the
financial statements, primarily in relation to the estimation of the
recoverable value of property, plant and equipment and intangible assets.
It is also relevant to the assessment of going concern and the viability
statement.
The Company's forecast of average Brent oil price for future years is
based on a range of publicly available market estimates and is summarised
in the table below, with the 2025 price then inflated at 2% per annum.
Latest oil price forecast is materially higher than it was at HY2020. The
oil price at HY2020 caused material impairment to our production assets
last year.
$/bbl 2021 2022 2023 2024
HY2021 forecast 65 65 65 65
YE2020 forecast 55 55 60 60
HY2020 forecast 43 50 55 60
Netback price is used to value the Company's revenue, trade receivables
and its forecast cash flows used for impairment testing and viability. It
is the aggregation of realised oil price less transportation and handling
costs. The Company does not have direct visibility on the components of
the netback price realised for its oil because sales are managed by the
KRG, but invoices are currently raised for payments on account using a
netback price agreed with the KRG.
Estimation of the recoverable value of overdue trade receivables
("deferred receivables")
At the end of March, in line with other International Oil Companies (IOCs)
in Kurdistan, the KRG informed the Company that payments owed for sales
made in the four months from November 2019 to February 2020 would be
deferred. For Genel this amounted to $120.8 million.
For the period ended 30 June 2020, the Company estimated recovery of these
overdue amounts, which resulted in an impairment of $34.9 million.
In December 2020, the KRG announced a reconciliation model for payment of
the receivable relating to the unpaid invoices, whereby for each dollar
above a monthly dated Brent average of $50/bbl, 50 cents per paying
interest barrel shall be paid towards monies owed. In March 2021, the KRG
amended this reconciliation model so that it paid 20 cents per paying
interest barrel shall be paid towards monies owed.
In order to assess the recoverable amount of overdue trade receivables at
30 June 2021, the Company has compared the carrying value of trade
receivables with the present value of the estimated future cash flows
based on the KRG's communications, and using estimations of future oil
prices and production scenarios. Under IFRS9, the Company has used a
forward-looking impairment model based on a lifetime expected credit loss
(ECL) assessment. The model calculates the net present value of
outstanding receivables using the effective interest rate for the period
in which the revenue was recognised, which was 13%. The expected credit
loss is the weighted average of these scenarios and is recognised in the
income statement. The result of the Company's assessment was no change to
the reported receivable balance, with the impairment of $34.9 million
maintained. The accounting and valuation of the receivable will be an
output of clarity on the mechanism and that it is working effectively, oil
price and production. The Company has provided the detailed disclosures
required by IFRS 9 ECL assessment in note 10.
Recognition of revenue generated by the override royalty, arising from the
RSA
Since 2017 when the RSA was signed, the Company has received override
revenue from Tawke sales. At the end of March 2020, the KRG informed the
Company that this override income was suspended for a minimum period up to
December 2020. Because management did not have visibility on how or when
this contractual right would be received, it has assessed that the
criteria for revenue recognition under IFRS15, specifically on payment
terms and collectability, have not been met, and consequently no override
revenue has been recognised from 1 March 2020. The total amount of
override revenue for the period between 1 March 2020 to 31 December 2020
that has not been recognised is $37.8 million.
The KRG has communicated that override income owed will be paid by the
reconciliation model explained above, which effectively subordinates the
value of override income to entitlement revenue owed and would result in
no payment of the monies owed for a number of years. Discussions with the
KRG on a fair and equitable solution are ongoing.
New standards
The following new accounting standards, amendments to existing standards
and interpretations are effective on 1 January 2021. Amendments to IFRS 4
Insurance Contracts - deferral of IFRS19, Amendments to IFRS 9, IAS 39,
IFRS 7, IFRS 4 and IFRS 16 Interest Rate Benchmark Reform - Phase 2,
Amendments to IFRS 16 Leases: Covid-19-Related Rent Concessions beyond 30
June 2021. Nothing has been early adopted, and these standards are not
expected to have a material impact on the Company's results or financials
statement disclosures in the current or future reporting periods.
The following new accounting standards, amendments to existing standards
and interpretations have been issued but are not yet effective and have
not yet been endorsed by the EU: IFRS 17 Insurance contracts (effective 1
Jan 2023), Amendments to IAS 1 Presentation of Financial Statements:
Classification of Liabilities as Current or Non-current (1 Jan 2023),
Amendments to IFRS 3 Business Combinations; IAS 16 Property, Plant and
Equipment; IAS 37 Provisions, Contingent Liabilities and Contingent
Assets; Annual Improvements 2018-2020 (1 Jan 2022), Amendments to IAS 1
Presentation of Financial Statements and IFRS Practice Statement 2:
Disclosure of Accounting policies (1 Jan 2023), Amendments to IAS 8
Accounting policies, Changes in Accounting Estimates and Errors:
Definition of Accounting Estimates (1 Jan 2023), Amendments to IAS 12
Income Taxes: Deferred Tax related to Assets and Liabilities arising from
a Single Transaction (1 Jan 2023).
3. Segmental information
The Company has two reportable business segments: Production (which
includes development assets) and Pre-production. Capital allocation
decisions for the production segment are considered in the context of the
cash flows expected from the production and sale of crude oil. The
production segment is comprised of the producing fields on the Tawke PSC
(Tawke and Peshkabir), the Taq Taq PSC (Taq Taq) and the Sarta PSC (Sarta)
which are located in the KRI and make sales predominantly to the KRG. The
pre-production segment is comprised of discovered resource held under the
Qara Dagh PSC, the Bina Bawi PSC and the Miran PSC (all in the KRI) and
exploration activity, principally located in Somaliland and Morocco. Sarta
asset was transferred from pre-production to production following the
production commencement close to 31 December 2020, whereas capital
expenditure incurred for the development of the field until production
commenced is reported under pre-production segment. 'Other' includes
corporate assets, liabilities and costs, elimination of intercompany
receivables and intercompany payables, which are non-segment items.
For the 6-month period ended 30 June 2021
Pre-production Total
Production Other
$m $m $m $m
Revenue from contracts with 147.4 - - 147.4
customers
Revenue from other sources 4.1 - - 4.1
Cost of sales (103.4) - - (103.4)
Gross profit 48.1 - - 48.1
General and administrative costs - - (6.8) (6.8)
Operating profit / (loss) 48.1 - (6.8) 41.3
Operating profit / (loss) is
comprised of
EBITDAX 129.8 - (6.7) 123.1
Depreciation and amortisation (81.7) - (0.1) (81.8)
Bond interest expense - - (13.2) (13.2)
Other finance expense (0.8) (0.4) (1.3) (2.5)
Profit / (Loss) before income 47.3 (0.4) (21.3) 25.6
tax
Capital expenditure 34.6 23.6 - 58.2
Total assets 687.8 575.3 203.1 1,466.2
Total liabilities (137.1) (109.8) (290.2) (537.1)
Revenue from contracts with customers includes $46.5 million (30 June
2020: $14.7 million, 31 December 2020: $14.7 million) arising from the
4.5% royalty interest on gross Tawke PSC revenue ending at the end of July
2022 ("the ORRI"). As explained in note 2, no revenue has been recognised
regarding to the ORRI from March 2020 to December 2020.
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
For the 6-month period ended 30 June 2020
Pre-production Total
Production Other
$m $m $m $m
Revenue from contracts with 86.3 - - 86.3
customers
Revenue from other sources 2.1 - - 2.1
Cost of sales (99.3) - - (99.3)
Gross loss (10.9) - - (10.9)
Exploration expense - (1.3) - (1.3)
Impairment of intangible assets (44.3) - - (44.3)
Impairment of property, plant (242.0) - - (242.0)
and equipment
Impairment of trade receivables (34.9) - - (34.9)
General and administrative costs - - (6.6) (6.6)
Operating loss (332.1) (1.3) (6.6) (340.0)
Operating loss is comprised of
EBITDAX 71.6 - (6.5) 65.1
Depreciation and amortisation (82.5) - (0.1) (82.6)
Exploration expense - (1.3) - (1.3)
Impairment of intangible assets (44.3) - - (44.3)
Impairment of property, plant (242.0) - - (242.0)
and equipment
Impairment of trade receivables (34.9) - - (34.9)
Finance income - - 1.6 1.6
Bond interest expense - - (15.0) (15.0)
Other finance expense (0.9) (0.1) (0.3) (1.3)
Loss before income tax (333.0) (1.4) (20.3) (354.7)
Capital expenditure 35.7 22.8 - 58.5
Total assets 617.9 618.6 327.7 1,564.2
Total liabilities (95.2) (150.8) (312.5) (558.5)
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
For the 12-month period ended 31 December 2020
Total
Production Pre-production Other
$m $m $m $m
Revenue from contracts with 155.0 - - 155.0
customers
Revenue from other sources 4.7 - - 4.7
Cost of sales (186.0) - - (186.0)
Gross loss (26.3) - - (26.3)
Exploration expense - (2.2) - (2.2)
Impairment of intangible asset (44.3) - - (44.3)
Impairment of property, plant (242.0) - - (242.0)
and equipment
Impairment of receivables (34.9) - (2.0) (36.9)
General and administrative - - (12.8) (12.8)
costs
Operating loss (347.5) (2.2) (14.8) (364.5)
Operating loss is comprised of
EBITDAX 127.0 - (12.4) 114.6
Depreciation and amortisation (153.3) - (0.4) (153.7)
Exploration expense - (2.2) - (2.2)
Impairment of intangible (44.3) - - (44.3)
assets
Impairment of property, plant (242.0) - - (242.0)
and equipment
Impairment of receivables (34.9) - (2.0) (36.9)
Finance income - - 2.0 2.0
Bond interest expense - - (31.5) (31.5)
Other finance expense (1.6) (0.3) (20.8) (22.7)
Loss before income tax (349.1) (2.5) (65.1) (416.7)
Capital expenditure 56.5 53.2 - 109.7
Total assets 672.5 539.0 339.1 1,550.6
Total liabilities (146.3) (98.2) (376.3) (620.8)
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
4. Cost of sales
6 months to 30
June 6 months to 30 Year to 31
June 2020 December 2020
2021
$m $m $m
Operating costs (21.5) (16.8) (32.6)
Trucking costs (0.2) - (0.1)
Production cost (21.7) (16.8) (32.7)
Depreciation of oil and gas (58.6) (51.6) (98.7)
property, plant and equipment
Amortisation of oil and gas (23.1) (30.9) (54.6)
intangible assets
Cost of sales (103.4) (99.3) (186.0)
Exploration expense - (1.3) (2.2)
Impairment of intangible - (44.3) (44.3)
assets (note 8)
Impairment of property, plant - (242.0) (242.0)
and equipment (note 9)
Impairment of receivables - (34.9) (36.9)
(note 10)
Corporate cash costs (6.2) (4.9) (9.6)
Other operating expenses - (1.1) (1.8)
Corporate share-based payment (0.5) (0.5) (1.0)
expense
Depreciation and amortisation (0.1) (0.1) (0.4)
of corporate assets
General and administrative (6.8) (6.6) (12.8)
expenses
Exploration expense relates to spend and accruals for costs or obligations
relating to licences where there is ongoing activity or that have been, or
are in the process of being, relinquished.
Trucking costs are not cost-recoverable and relate to the Sarta licence
only, where production is in its early stages.
5. Finance expense and income
6 months to 30 6 months to 30
June June Year to 31
December 2020
2021 2020
$m $m $m
Bond interest paid (13.2) (15.0) (25.8)
Bond interest accrued - - (5.7)
Accelerated cost of bond - - (19.4)
settlement (see note 15)
Other finance expense (2.6) (1.3) (3.3)
(non-cash)
Finance expense (15.8) (16.3) (54.2)
Bank interest income 0.1 1.6 2.0
Finance income 0.1 1.6 2.0
Net finance expense (15.7) (14.7) (52.2)
Bond interest payable is the cash interest cost of the Company bond debt.
Other finance expense (non-cash) primarily relates to the discount unwind
on the bond and the asset retirement obligation provision.
6. Income tax expense
Current tax expense is incurred on the profits of the Turkish and UK
services companies. Under the terms of KRI PSC's, corporate income tax due
is paid on behalf of the Company by the KRG from the KRG's own share of
revenues, resulting in no corporate income tax payment required or
expected to be made by the Company. It is not known at what rate tax is
paid, but it is estimated that the current tax rate would be between 15%
and 40%. If this was known it may result in a gross up of revenue with a
corresponding debit entry to taxation expense with no net impact on the
income statement or on cash. In addition, it would be necessary to assess
whether any deferred tax asset or liability was required to be recognised.
7. Earnings / (Loss) per share
Basic
Basic earnings / (loss) per share is calculated by dividing the profit /
(loss) attributable to owners of the parent by the weighted average number
of shares in issue during the period.
6 months to 30
June 6 months to 30 Year to 31
June 2020 December 2020
2021
Profit / (Loss) attributable 25.6 (354.7) (416.9)
to owners of the parent ($m)
Weighted average number of 275,446,155 275,197,007 274,202,853
ordinary shares - number 1
Basic earnings / (loss) per 9.3 (128.9) (152.0)
share - cents per share
1 Excluding shares held as treasury shares
Diluted
The Company purchases shares in the market to satisfy share plan
requirements so diluted earnings per share is adjusted for performance
shares, restricted shares and share options not included in the
calculation of basic earnings per share. Because the Company reported a
loss for the six month period ended 30 June 2020 and year ended 31
December 2020, diluted EPS is anti-dilutive and therefore diluted EPS is
the same as basic EPS:
6 months to 30
June 6 months to 30 Year to 31
June 2020 December 2020
2021
Profit / (Loss) attributable 25.6 (354.7) (416.9)
to owners of the parent ($m)
Weighted average number of 275,446,155 275,197,007 274,202,853
ordinary shares - number1
Adjustment for performance
shares, restricted shares and 3,067,145 - -
share options
Weighted average number of
ordinary shares and potential 278,513,300 275,197,007 274,202,853
ordinary shares
Diluted earnings / (loss) per 9.2 (128.9) (152.0)
share - cents per share
1 Excluding shares held as treasury shares
8. Intangible assets
Exploration and Tawke Other
evaluation assets Total
RSA assets
Cost $m $m $m $m
At 1 January 2020 1,518.5 425.1 7.3 1,950.9
Additions 11.3 - 0.1 11.4
Discount unwind of contingent 4.7 - - 4.7
consideration
Other (0.3) - - (0.3)
At 30 June 2020 1,534.2 425.1 7.4 1,966.7
At 1 January 2020 1,518.5 425.1 7.3 1,950.9
Additions 23.2 - 0.1 23.3
Other (0.2) - - (0.2)
At 31 December 2020 and 1 1,541.5 425.1 7.4 1,974.0
January 2021
Additions 23.6 - 0.1 23.7
Discount unwind of contingent 4.7 - - 4.7
consideration
Other 0.3 - - 0.3
At 30 June 2021 1,570.1 425.1 7.5 2,002.7
Accumulated amortisation and
impairment
At 1 January 2020 (1,005.3) (163.2) (6.8) (1,175.3)
Amortisation charge for the - (30.9) (0.2) (31.1)
period
Impairment - (44.3) - (44.3)
At 30 June 2020 (1,005.3) (238.4) (7.0) (1,250.7)
At 1 January 2020 (1,005.3) (163.2) (6.8) (1,175.3)
Amortisation charge for the - (54.6) (0.4) (55.0)
period
Impairment - (44.3) - (44.3)
At 31 December 2020 and 1 (1,005.3) (262.1) (7.2) (1,274.6)
January 2021
Amortisation charge for the - (23.1) (0.1) (23.2)
period
At 30 June 2021 (1,005.3) (285.2) (7.3) (1,297.8)
Net book value
At 30 June 2020 528.9 186.7 0.4 716.0
At 31 December 2020 536.2 163.0 0.2 699.4
At 30 June 2021 564.8 139.9 0.2 704.9
30 June 30 June 31 Dec
2021 2020 2020
Book value $m $m $m
Bina Bawi PSC Discovered gas and 367.4 362.5 360.5
oil, appraisal
Miran PSC Discovered gas and 122.6 121.6 123.2
oil, appraisal
Somaliland PSC Exploration 35.2 34.1 34.7
Qara Dagh PSC Exploration / 39.6 10.7 17.8
Appraisal
Exploration and evaluation 564.8 528.9 536.2
assets
Tawke overriding royalty 56.2 90.9 73.3
Tawke capacity building payment waiver 83.7 95.8 89.7
Tawke RSA assets 139.9 186.7 163.0
Sensitivity of the Tawke CGU is provided in note 9. The Miran intangible
asset is most sensitive to timing of its commercialisation. The table
below shows the indicative sensitivity of the Bina Bawi CGU net present
value to changes to long term Brent, discount rate or production and
reserves, assuming no change to other inputs. None of these would result
in impairment.
$m
Long term Brent +/- $5/bbl +/- 13
Discount rate +/-2.5% +/- 101
Production and reserves +/- 10% +/- 32
9. Property, plant and equipment
Producing Development Other
assets assets
Assets Total
Cost $m $m $m $m
At 1 January 2020 2,876.1 68.0 13.5 2,957.6
Additions 35.7 11.5 1.0 48.2
Right-of-use assets - - 1.0 1.0
Net change in payable - (1.8) - (1.8)
Non-cash additions for ARO/SBP1 1.2 0.3 - 1.5
At 30 June 2020 2,913.0 78.0 15.5 3,006.5
At 1 January 2020 2,876.1 68.0 13.5 2,957.6
Additions 56.5 30.0 1.0 87.5
Right-of-use assets - - 8.1 8.1
Net change in payable - (5.4) - (5.4)
Non-cash additions for 2.3 8.8 - 11.1
ARO/SBP/Production bonus
Transfer to producing assets 101.4 (101.4) - -
At 31 December 2020 and 1 January 3,036.3 - 22.6 3,058.9
2021
Additions 34.6 - 0.2 34.8
Net change in payable (5.0) - - (5.0)
Non-cash additions for ARO/SBP 2.5 - - 2.5
At 30 June 2021 3,068.4 - 22.8 3,091.2
Accumulated depreciation and
impairment
At 1 January 2020 (2,310.7) - (10.0) (2,320.7)
Depreciation charge for the (51.6) - (0.7) (52.3)
period
Impairment (242.0) - - (242.0)
At 30 June 2020 (2,604.3) - (10.7) (2,615.0)
At 1 January 2020 (2,310.7) - (10.0) (2,320.7)
Depreciation charge for the (98.7) - (1.8) (100.5)
period
Impairment (242.0) - - (242.0)
At 31 December 2020 and 1 January (2,651.4) - (11.8) (2,663.2)
2021
Depreciation charge for the (58.6) - (1.8) (60.4)
period
At 30 June 2021 (2,710.0) - (13.6) (2,723.6)
Net book value
At 30 June 2020 308.7 78.0 4.8 391.5
At 31 December 2020 384.9 - 10.8 395.7
At 30 June 2021 358.4 - 9.2 367.6
1 ARO: Asset retirement obligation, SBP: Share-based payment
Sarta asset was transferred from development assets to producing assets
following the commencement of production from the field at December 2020.
30 June 30 June 31 Dec
2021 2020 2020
Book value $m $m $m
Tawke PSC Oil production 206.1 247.0 228.2
Taq Taq PSC Oil production 45.6 61.7 56.2
Sarta PSC Oil production/development 106.7 78.0 100.5
Producing 358.4 386.7 384.9
assets
The sensitivities below provide an indicative impact on the net present
value of a change in long term Brent, discount rate or production and
reserves, assuming no change to any other inputs. None of these would
result in impairment.
Taq Taq CGU Tawke CGU
$m $m
Long term Brent +/- $5/bbl +/- 2 +/- 16
Discount rate +/- 2.5% +/- 3 +/- 37
Production and reserves +/- 10% +/- 4 +/- 39
10. Trade and other receivables
30 June 2021 30 June 2020 31 Dec 2020
$m $m $m
Trade receivables - current 88.5 21.9 41.9
Trade receivables - non-current 31.4 68.3 52.1
Other receivables and prepayments 7.4 8.1 7.0
127.3 98.3 101.0
Under the Tawke, Taq Taq and Sarta PSCs, payment for entitlement is due
within 30 days. Since February 2016, payments were received consistently
three months in arrears, which was assessed as the operating cycle under
IAS1. From March 2020, payments were received one month in arrears, which
was consequently used to assess receivables that were not due at 30 June
2020 and 31 December 2020. At half year 2021, the Company is owed two
months of payments, which is consequently assumed to be the operating
cycle for presentation of overdue receivables at the end of the period.
Year of sale of
amounts overdue
Not due 2020 2019 Total overdue
$m $m $m $m
Trade receivables at 30 8.3 55.4 65.4 120.8
June 2020 (nominal)
Trade receivables at 31 14.8 55.4 65.4 120.8
December 2020 (nominal)
Trade receivables at 30 55.7 55.4 51.8 107.2
June 2021 (nominal)
Movement on trade receivables in the 30 June 2021 30 June 2020 31 Dec 2020
period
$m $m $m
Carrying value at the beginning of 94.0 150.2 150.2
the period
Revenue from contracts with 147.4 86.3 155.0
customers
Cash proceeds (122.5) (110.0) (173.4)
Offset of payables due to the KRG - (3.2) (5.5)
Expected credit loss - (34.9) (34.9)
Capacity building payments 1.0 1.8 2.6
Carrying value at the end of the 119.9 90.2 94.0
period
Recovery of the carrying value of the receivable
The balance owed has reduced by $13.6 million from the opening balance of
$120.8 to $107.2 million. This reduction is the result of four payments
being received in the period: the first two under the initial mechanism
announced in December and the second two made under the revised mechanism
announced in May. The Company expects to recover the full nominal value of
$107.2 million receivables owed from the KRG, but the terms of recovery
are not finalised. Explanation of the assumptions and estimates in
assessing the net present value of the deferred receivables are provided
in note 2. Neither the nominal value nor the net present value include $38
million owed to the Company for override revenue earned but not received
for the period March 2020 to December 2020, which was not recognised as
revenue for the reasons explained in note 2.
Total
$m
Nominal balance to be recovered 107.2
Book value of overdue receivables 72.3
Sensitivities
The table below shows the sensitivity of the net present value of the
overdue trade receivables to oil price, assuming flat production and
payment is received in line with the mechanism proposed by the KRG in
March 2021, which is explained in note 2.
Nominal receivables ($m) Timing of repayment Total NPV13.0
2H 2021 2022 2023 2024 2025 2026
$60/bbl 11.5 23.0 23.0 23.0 23.0 3.7 107.2 77.0
Brent $65/bbl 17.3 34.6 34.6 20.7 - - 107.2 84.0
$70/bbl 23.1 46.2 37.9 - - - 107.2 88.1
$75/bbl 28.8 57.6 20.8 - - - 107.2 90.3
11. Interest bearing loans and net (debt) / cash
1 Jan Discount Buyback / Dividend Net 30 June
unwind Issuance other 2021
2021 paid changes
$m $m $m $m $m $m
2022 Bond 10.0% (80.6) (0.4) 81.0 - - -
(current)
2025 Bond 9.25% (267.7) (0.9) - - - (268.6)
(non-current)
Cash 354.5 - (81.0) (29.0) 21.9 266.4
Net (debt) / cash 6.2 (1.3) - (29.0) 21.9 (2.2)
At 30 June 2021, the fair value of the $280 million of bonds held by third
parties is $274.4 million (30 June 2020: $298.5 million, 31 December 2020:
$274.4 million).
1 Jan Net other 30 June
Discount unwind Dividend paid changes
2020 2020
$m $m $m $m $m
2022 Bond (297.9) (0.2) - - (298.1)
10.0%
Cash 390.7 - (41.3) 5.9 355.3
Net Cash 92.8 (0.2) (41.3) 5.9 57.2
Purchase
1 Jan Discount Buyback / of own Net 31 Dec
2020 unwind Issuance bonds other 2020
changes
$m $m $m $m $m $m
2022 Bond 10.0% (297.9) (0.5) 221.7 - (3.9) (80.6)
(current)
2025 Bond 9.25% - (0.3) (286.8) 19.4 - (267.7)
(non-current)
Cash 390.7 - 28.9 - (65.1) 354.5
Net cash 92.8 (0.8) (36.2) 19.4 (69.0) 6.2
In October 2020, the Company issued a new $300 million senior unsecured
bond with maturity in October 2025. The new bond has a fixed coupon of
9.25% per annum. In connection with the issue, the Company repurchased
$222.9 million of its existing $300.0 million senior unsecured bond issue
with maturity date in December 2022 at a price of 107 per cent. On 22
December 2020, the Company wrote to the Trustees confirming that they were
exercising the right to call the remaining $77.1 million of the 2022 bond
at the call price of 105 per cent. This settlement completed on 8 January
2021.
12. Capital commitments
Under the terms of its production sharing contracts ('PSC's) and joint
operating agreements ('JOA's), the Company has certain commitments that
are generally defined by activity rather than spend. The Company's capital
programme for the next few years is explained in the operating review and
is in excess of the activity required by its PSCs and JOAs.
INDEPENDENT REVIEW REPORT TO GENEL ENERGY PLC
Introduction
We have been engaged by the Company to review the condensed set of
financial statements in the half-yearly financial report for the six
months ended 30 June 2021 which comprises the condensed consolidated
statement of comprehensive income, the condensed consolidated balance
sheet, the condensed consolidated statement of changes in equity, the
condensed consolidated cash flow statement and the notes to the interim
financial statements.
We have read the other information contained in the half-yearly financial
report and considered whether it contains any apparent misstatements or
material inconsistencies with the information in the condensed set of
financial statements.
Directors' responsibilities
The half-yearly financial report is the responsibility of and has been
approved by the directors. The directors are responsible for preparing
the half-yearly financial report in accordance with the Disclosure
Guidance and Transparency Rules of the United Kingdom's Financial Conduct
Authority and the Companies (Jersey) Law 1991.
As disclosed in note 1, the annual financial statements of the group are
prepared in accordance with International Financial Reporting Standards as
adopted by the European Union. The condensed set of financial statements
included in this half-yearly financial report has been prepared in
accordance with International Accounting Standard 34, ''Interim Financial
Reporting'' and the requirements of the Disclosure and Transparency Rules
of the Financial Conduct Authority.
Our responsibility
Our responsibility is to express to the Company a conclusion on the
condensed set of financial statements in the half-yearly financial report
based on our review.
Scope of review
We conducted our review in accordance with International Standard on
Review Engagements (UK and Ireland) 2410, ''Review of Interim Financial
Information Performed by the Independent Auditor of the Entity'', issued
by the Financial Reporting Council for use in the United Kingdom. A
review of interim financial information consists of making enquiries,
primarily of persons responsible for financial and accounting matters, and
applying analytical and other review procedures. A review is
substantially less in scope than an audit conducted in accordance with
International Standards on Auditing (UK) and consequently does not enable
us to obtain assurance that we would become aware of all significant
matters that might be identified in an audit. Accordingly, we do not
express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that causes us to
believe that the condensed set of financial statements in the half-yearly
financial report for the six months ended 30 June 2021 is not prepared, in
all material respects, in accordance with International Accounting
Standard 34, as adopted by the European Union, and the Disclosure Guidance
and Transparency Rules of the United Kingdom's Financial Conduct
Authority.
Use of our report
Our report has been prepared in accordance with the terms of our
engagement to assist the Company in meeting its responsibilities in
respect of half-yearly financial reporting in accordance with the
Disclosure Guidance and Transparency Rules of the United Kingdom's
Financial Conduct Authority and for no other purpose. No person is
entitled to rely on this report unless such a person is a person entitled
to rely upon this report by virtue of and for the purpose of our terms of
engagement or has been expressly authorised to do so by our prior written
consent. Save as above, we do not accept responsibility for this report to
any other person or for any other purpose and we hereby expressly disclaim
any and all such liability.
BDO LLP
Chartered Accountants
London
3 August 2021
BDO LLP is a limited liability partnership registered in England and Wales
(with registered number OC305127).
══════════════════════════════════════════════════════════════════════════
ISIN: JE00B55Q3P39, NO0010894330
Category Code: IR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 119001
EQS News ID: 1223461
End of Announcement EQS News Service
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