Genel Energy PLC (GENL)
Genel Energy PLC: Full-Year Results
18-March-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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18 March 2021
Genel Energy plc
Audited results for the year ended 31 December 2020
Genel Energy plc ('Genel' or 'the Company') announces its audited results for the year ended 31 December 2020.
Bill Higgs, Chief Executive of Genel, said:
"2020 was a uniquely challenging year for everyone. As for Genel, our continued progress and strong performance in 2020
has laid the foundation for a year of growth and operational catalysts in 2021. We continued investment in Sarta, which
entered production in November, and the field is generating cash as we now move to rapidly appraise its exciting
potential. Three appraisal wells will be drilled at the licence in 2021. The QD-2 well at Qara Dagh is also set to spud
shortly, as we look to evaluate the potential to add a fifth producing field.
As we make this investment in growth, the low-cost and high-margin nature of our growing oil production means that we
expect to generate significant free cash flow at the prevailing oil price. In turn, this gives us the confidence in our
material and sustainable dividend distribution, including a final dividend of 10 cents per share announced today, as we
continue to offer investors a compelling mix of growth and returns."
Results summary (USD million unless stated)
2020 2019
Average Brent oil price (USD/bbl) 42 64
Production (bopd, working interest) 31,980 36,250
Revenue 159.7 377.2
EBITDAX1 114.6 321.8
Depreciation and amortisation (153.7) (158.5)
Exploration expense (2.2) (1.2)
Impairment of oil and gas assets2 (286.3) (29.8)
Impairment of receivables (36.9) -
Operating (loss) / profit (364.5) 132.3
Cash flow from operating activities 129.4 272.9
Capital expenditure 109.7 158.1
Free cash flow4 (4.4) 99.0
Dividends declared (¢ per share) 15 15
Cash 354.5 390.7
Cash after post-year end payments5 273.5 377.1
Total debt after settlement of called bonds5 280.0 300.0
Net cash6 6.2 92.8
Basic EPS (¢ per share) (152.0) 37.8
Underlying EPS (¢ per share)3 41.8 116.9
1. EBITDAX is operating loss / (profit) adjusted for the add back of depreciation and amortisation (USD153.7 million),
exploration expense (USD2.2 million), impairment of property,
plant and equipment (USD242.0 million), impairment of
intangible assets (USD44.3 million) and impairment of
receivables (USD36.9 million) 2. Despite production in line with
expectations, the low oil price in June 2020 resulted in an
impairment of
production assets at the half-year results, which under IFRS
cannot be reversed despite the improved oil price
outlook 3. Underlying EPS is EBITDAX divided by weighted average
number of ordinary shares 4. Free cash flow is reconciled on page
13 5. On 8 January 2021, shortly after the balance sheet date, the
Company paid USD81.0 million to settle USD77.1 million of
old bonds reducing its gross debt balance to USD280.0 million,
with USD267.7 million reported under IFRS in the balance
sheet (2019: Cash reported at 31 December 2019 less interim
dividend paid (USD13.6 million) on 8 January 2020) 6. Reported cash
less IFRS debt (page 13)
Highlights ? Zero lost time injuries ('LTI') and zero tier one
loss of primary containment events in 2020 at Genel and TTOPCO
operations
? No LTIs since 2015, with over 13 million work hours since the
last incident as of end-2020 ? Net production averaged 31,980 bopd
in 2020 (2019: 36,250 bopd), following the pause in the drilling
programme at
Tawke, appropriate to the external environment
? First oil from Sarta achieved in November 2020, with asset now
producing over 10,000 bopd ? USD173 million of cash proceeds were
received in 2020 (2019: USD317 million) ? The low-production cost
per barrel of USD2.8/bbl in 2020 helped deliver cash generation of
USD85 million in the year
from producing assets
? Free cash outflow of USD4 million following material capital
expenditure on growth assets ? Dividends of 15¢ per share announced
in 2020 (2019: 15¢ per share) ? Net cash of USD6 million at 31
December 2021 following the call of the old 2022 bond, with cash of
USD274 million and
reported IFRS debt of USD268 million ? Carbon intensity of 13
kgCO2e/bbl for scope 1 and 2 emissions in 2020, significantly below
the global oil and gas
industry average of 20 kgCO2e/boe
Outlook ? Production guidance for 2021 maintained as slightly
above the 2020 average of 31,980 bopd, with the potential for a
higher exit rate and further growth in 2022 depending on success
of the Sarta appraisal programme
? Margin of USD15 per working interest barrel expected in 2021
at average Brent oil price USD60/bbl, with receivable
recovery payments increasing that to USD20/bbl ? 2021 capital
expenditure guidance maintained at USD150 million to USD200
million, with the current macro environment
and outlook supporting investment at the top end of this
range
? c.USD100 million expenditure is forecast to be spent on growth
assets, with three appraisal wells at Sarta
targeting a material 2C resource and the QD-2 well, set to spud
shortly, aiming to open up a new producing
field ? Operating costs still expected to be c.USD50 million
(2020: USD33 million), equating to c.USD4/bbl in 2021 (USD2.8/bbl
in
2020), retaining our advantageous low operating cost position,
with the increase from 2020 due to the addition of
Sarta early production costs ? Given the increase in Brent oil
price and confidence in ongoing payments from the Kurdistan
Regional Government
('KRG'), including override and receivable recovery payments,
Genel expects to generate cash in 2021 post-dividend
payments
? Receivable recovery payments expected to generate c.USD50
million in 2021 at an oil price of USD60/bbl
? A USD5/bbl change in Brent impacts cash generation by c.USD35
million in 2021 ? Due to Genel's robust financial position and
confidence in the Company's future prospects, the Board is
accordingly
recommending a final dividend of 10¢ per share (2020: 10¢ per
share), a distribution of USD27.9 million
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 GMT, with an associated webcast available on the Company's
website, www.genelenergy.com.
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.
CHAIRMAN'S STATEMENT
I am pleased to welcome you to Genel Energy's ninth annual
results statement. 2020 was a difficult year for everybody, with
COVID-19 impacting the global business environment in a way that
was unexpected and unforeseeable. The challenges that it presented
were unique, but the low-oil price environment that it created was
a powerful reminder of the need to have a business model that is
both robust and adaptable to rapidly changing external
conditions.
Genel has worked to put in place a business model that is
appropriate for fluctuating market conditions, allowing the Company
to continue strategic delivery when times are tough and lay the
foundations to thrive in better times ahead. 2020 was a strong
indicator that our strategy is the right one as we not merely
survived but had the financial strength to invest in our key growth
projects, and maintain our material dividend, delivering on our
promises to investors with a reliability for which we are striving
to be well known.
Focusing on key areas
As the impact of COVID-19 became clear and the oil price
collapsed in the first quarter of the year, the flexibility and
elasticity of our business model was demonstrated. Swift decisions
were made to focus on key areas and fit our investment programme to
the external environment. We reshaped our capital expenditure
programme to live within our means, removing c.USD80 million from
our original guidance, while still investing in growth and
maintaining the dividend.
The low oil price helped to reinforce our capital investment
priorities, which as you would expect support our strategic
priorities. Investment at Tawke was delayed appropriately by the
operator DNO, with whom we are closely aligned, and the decision
was made to continue investing in the delivery of first oil at
Sarta. This was achieved in November, only 21 months after
completing the acquisition of the stake in the field. This rapid
delivery, despite the challenges of COVID-19, was an exceptional
achievement and a testimony to our workforce and field
partners.
Already the only multi-licence oil producer in the Kurdistan
Region of Iraq ('KRI'), the addition of Sarta provides us with a
material growth opportunity going forward, as we work with Chevron
to develop what could potentially be the largest field in the
KRI.
Our final capital allocation priority is the dividend, and we
are proud of our ability to retain this at such a significant level
despite the external upheaval, a testament to the resilience of our
strategy and business model.
A strategy resilient by design
Our strategy remains very simple. We aim to increase our
low-cost production, invest in growth, and retain surplus cash to
pay a material and sustainable dividend.
Central to this strategy is prudent financial planning, as your
Board and management team look to minimise risk and create
sustainable shareholder value. The successful bond refinancing in
September allowed us to extend the tenor of our debt while reducing
the interest cost. Genel remains committed to retaining a robust
balance sheet and strong liquidity, providing the foundation for
our flexible capital investment programme.
It is this financial strength and focus on the balance sheet,
together with a positive business outlook, that underpins our
confidence in the sustainability of our dividend, which we are once
again pleased to maintain in 2021.
With the worst of the pandemic hopefully now behind us and a
recovery in the oil price further boosting our finances as we enter
a year of exciting investment in the portfolio, Genel is confident
that we can continue delivering on our strategy and create material
value for our stakeholders.
The ramp up of work at Sarta promises to increase our low-cost
production in 2021, with the possibility for much more to come in
2022 and the years ahead. Work at Qara Dagh also offers the
potential to unlock value from a fifth field in the KRI, and we
will of course remain prudent in our expenditure as we aim to
provide a compelling mix of growth and returns.
A socially responsible contributor
Last year I discussed the period of significant and necessary
change into which the energy industry is entering. Despite the
pressures and challenges of 2020, we retained our focus on ensuring
that Genel is at the forefront of this process.
As we grow, we continue to focus on our social and environmental
responsibilities as we look to live up to our mantra of having the
right assets, in the right location, with the right emissions, in
the hands of the right people. The frequency and intensity of Board
discussions on ESG signify how seriously we take the issue, and we
firmly believe that responsible producers have a key part to play
in the energy transition and delivering the goals of the Paris
Agreement.
We will be measured against the promises that we make, and we
issued our first GRI compliant Sustainability Report in 2020
setting out where we are on our sustainability journey. The report
illustrates our commitment to support the communities in which we
operate and solidify our place in the energy transition, minimising
emissions as we look to play our part through delivering some of
the fewer and better natural resources projects that the world
needs as it moves towards clean energy.
Given our low-cost and low-carbon barrels, and the positive
social impact our operations have on the Kurdistan Region of Iraq,
it is our belief that Genel has the right portfolio to continue
powering the energy transition and deliver value to our
shareholders as a socially responsible contributor to the global
energy mix.
CEO STATEMENT
It would be an understatement to say that 2020 was not the year
that anyone expected. In spite of the challenges that resulted, we
continued to do what we say and delivered on our strategy.
Executing our strategy
Our first strategic priority remains the maximisation of the
value of our low-cost production. Despite the reduction of
investment at Tawke, production at the licence remained over
100,000 bopd again in 2020, and this continues to form the bedrock
of our production, which averaged just under 32,000 bopd in the
year. We see this as being a platform for Genel going forward, as
we expect year-on-year production growth in both 2021 and 2022.
This robust and predictable production, and the low production
cost, meant that we continued to generate material cash at an asset
level. Taken in isolation, our producing assets generated USD85
million of cash, even allowing for the low oil price, delayed KRG
payments and suspended override proceeds. Despite the suspension of
the override payments, and USD159 million of unpaid KRG debts in
2020, our free cash outflow in the year was only USD4 million.
Given the fact that we also continued to invest in the priority
growth projects that provide us with exciting value creation
potential, this is a creditable performance powered by a cost base
that is amongst the lowest in the sector.
Further diversifying production
The key project that formed the bulk of our investment in growth
in 2020 was Sarta, and first oil was successfully delivered in
November. This was an important strategic and operational milestone
for Genel, not least given the challenges presented by COVID-19.
This operational delivery, brought in on budget, was a tribute to
the quality and professionalism of our workforce, and the close
cooperation we enjoy with partners and contractors.
Production began with the Sarta-3 well, which has produced in
line with expectations. Sarta-2 then entered production in Q1 this
year, and the Sarta-1 well will hopefully add to production around
the end of this year. Should we have appraisal success in 2021,
then material further production can be added in 2022.
It is not just the geological potential of Sarta that excites
us, but the low-cost of the field and impressive margins that
promise material value creation. The unrecovered back costs support
PSC economics that mean field production achieves a margin of
c.USD21/bbl at a Brent oil price of USD60/bbl, which to put it into
context is more than equal to that of Tawke with the override. This
cash generation makes Sarta a perfect fit for our low-cost and
high-margin portfolio, and a key growth and value driver for Genel,
and hopefully the KRI oil industry as a whole going forward.
Strengthening the foundations
Given the lower oil price and overdue payments, the fact that we
still ended 2020 in a net cash position - even after dividend
distributions and making the investment to bring Sarta to
production this year - was a testament to our resilience.
This resilience comes in part due to our focus on the
minimisation of risk and the retention of a strong balance sheet,
combining to provide us with the ability to invest in areas that
have the potential to provide the highest returns to shareholders.
Our production is robust, and assets generate cash flows even at a
low oil price. Our financial strength was bolstered by our decision
to refinance our bond early, which gives us the certainty about our
near-term liquidity position to invest confidently in future
growth.
Following the refinancing, we have liquidity of over USD270
million, no debt maturity until 2025, a flexible capital programme,
and the financial foundations from which to grow. Investment
programmes at the Tawke licence resumed as conditions improved
through the second half of 2020, and the operator expects another
year of production over 100,000 bopd. With the external environment
looking far brighter, 2021 is now about delivering the growth that
we spent 2020 gearing up for.
Delivering growth and returns
The key focus of our near-term growth investment remains Sarta
and Qara Dagh.
At Sarta, our appraisal campaign is targeting a material
reserves addition, with net 79 MMbbls currently designated as 2C
resources. This is only scratching the surface of the field's
potential. Appraisal activity is scheduled to begin early in the
second quarter, with the drilling of the Sarta-5 well. This will
immediately be followed by Sarta-6, with results from the first
well expected in Q3, and both will be completed by end-Q4. We very
much look forward to the results of these wells, which could
provide a roadmap for significant and long-term growth.
The second area of focus of our growth investment is Qara Dagh
where the QD-2 well is set to be spud around the end of Q1. This
well will test the commerciality of a potentially very large
resource, estimated by Genel at gross mean c.400 MMbbls. We are
already the only multi licence oil producer in the KRI and the
potential to add a fifth field is very exciting, especially one
that could possibly be so material and with light oil.
As we invest in these growth projects and significantly increase
our capital expenditure year-on-year, increased payments from the
KRG will help us retain our strong financial position. From January
2021, invoices once again include our contractual override payments
and a receivable recovery mechanism tabled in December 2020 and
implemented by the KRG with respect to the January 2021
payment.
Payments in 2020 were impacted by external factors, of which the
volatile oil price was then the final straw, that temporarily
derailed the KRG's ability to make payments in the first two months
of the year. Consistent payments from March onwards once again
illustrated the KRG's willingness and ability to prioritise
payments to IOCs, and the track record over the last six years
gives us confidence that these will continue going forward.
We have a constructive relationship with the government, and we
are hopeful that the confirmation of a new oil minister will also
help provide the clarity that the industry requires as we work
together for the benefit of all stakeholders. We look forward to
working with the minister as we continue to search for a solution
that will help unlock the potential of Bina Bawi, the priority of
our gas strategy.
Supporting the energy transition
A core stakeholder group on which we continue to focus is the
local community in Kurdistan. We continue to invest in the local
community, while maximising local employment. We are committed to
utilising local people and companies wherever possible, and
currently employ around 250 Kurdish nationals directly, with just
under 30 local companies supported by Genel assets.
Providing a meaningful benefit to society while delivering the
power to increase living standards is something that we see as key
to deciding which barrels of oil should be produced as we
transition to clean energy. As activity ramps up at Sarta, and
hopefully in turn Qara Dagh, we look forward to deepening our local
community involvement and increasing our positive impact on the
local area.
Of course, the production of natural resources has a wider
impact than just that of the financial benefits to the local area,
and we recognise that as a natural resources company we have a role
to play in the energy transition. As such, we have evaluated the
best way to manage emissions in order to deliver the Paris
Agreement goals of limiting global warming to 1.5 degrees and
leading to net zero by 2050. In order to meet this goal, energy
efficiency and flaring management practices have been formalised in
a GHG Emissions Management Standard that emphasises an asset
life-cycle approach to emission mitigation. This standard applies
to all operated and non-operated assets, and provides a systematic
framework to identify an asset's carbon budget that aligns with the
Paris Agreement pathway.
The enhanced oil recovery project at the Tawke PSC was a key
step on our emission reduction journey, and the carbon intensity of
our portfolio reduced to 7kg CO2e/bbl for scope 1 and 2 emissions
in the second half of 2020 following the material reduction in
flaring at the Tawke PSC. This intensity will rise during early
production at Sarta, but we are already committed to a flares out
programme at the asset as production increases, and we will aim to
live up to our value of ingenuity by seeking innovative ways to
further reduce our footprint going forward.
As well as the local community and global environment, our
commitment to safe operations remains at the forefront of
everything that we do. We are proud of our safety record, and we
have not had a lost time incident for five years and 13 million
hours worked. This is the result of a lot of hard work and a
commitment to a culture of incident-free operations for which I
would like to pay tribute to our team. Our success in this area
does not make us complacent, and we will endeavour to repeat this
performance going forward.
A year of growth and catalysts
With the challenges of 2020 hopefully now receding, the work we
did in the year to build the foundations for growth can now be
delivered on, as we continue to execute our simple strategy. Sarta
will help us to increase our low-cost production, and investment in
growth both there and at Qara Dagh will tell us a lot more about
their value creation potential, with four appraisal wells that have
the potential to add reserves and production going forward.
Despite this material expenditure we expect to generate material
free cash flow at the prevailing oil price. Our strong financial
position, and confidence in increased payments, also supports the
maintenance of material distributions to shareholders, as we aim to
fulfil our goal of being a world-class creator of shareholder
value.
OPERATING REVIEW
Reserves and resources development
Genel's proven (1P) and proven plus probable (2P) net working
interest reserves totalled 69 MMbbls (31 December 2019: 69 MMbbls)
and 117 MMbbls (31 December 2019: 124 MMbbls) respectively at the
end of 2020.
Gross upward technical revisions of 47 MMbbls at the Tawke PSC,
relating to both the Tawke and Peshkabir fields, more than offset
the 40 MMbbls of production at the licence, and contributed to our
reserves remaining materially unchanged. The appraisal campaign
getting underway at Sarta in 2021 has the potential to convert
material 2C resources into reserves.
Remaining reserves (MMbbls) Resources (MMboe)
Contingent Prospective
1P 2P 1C 2C Best
Gross Net Gross Net Gross Net Gross Net Gross Net
31 December 2019 258 69 455 124 1,294 1,173 2,592 2,313 4,372 3,536
Production (44) (12) (44) (12) - - - - - -
Acquisitions - - - - - - - - - -
Extensions and discoveries - - - - - - - - - -
New developments - - - - - - - - - -
Revision of previous estimates 48 12 26 5 (34) (9) (38) (10) 1,335 931
31 December 2020 262 69 437 117 1,259 1,164 2,554 2,303 5,706 4,467
Production
Working interest production in 2020 averaged 31,980 bopd (2019:
36,250 bopd). This decrease was largely due to the delay in the
investment programme at the Tawke PSC, which resumed later in 2020
as the external environment stabilised and improved.
Production currently comes from 76 wells, with the addition of
Sarta meaning that we now have four producing fields, making
production yet more diverse and reliable. Production from Sarta in
2021 is expected to more than offset declines from Tawke and Taq
Taq, and full-year production is expected to be slightly above the
2020 average. Year to date production averages c.33,000 bopd.
Depending on the success of the Sarta appraisal programme and
the timing of possible production from the Sarta-1 well, there is
the clear potential for a higher 2021 exit rate and further
production growth in 2022.
PRODUCING ASSETS
Tawke PSC (25% working interest)
Gross production at the Tawke PSC averaged 110,280 bopd in 2020,
of which Peshkabir contributed 52,710 bopd.
There will be an active drilling campaign in 2021 on the Tawke
licence as we continue to work in close alignment with the
operator, DNO. Up to eight new development wells are set to be
drilled and multiple workovers on existing producing wells are due
to be undertaken in the drive to maintain production above 100,000
bopd.
Sarta (30% working interest)
Bringing Sarta to production was a key goal in 2020. As
expenditure was reduced across the portfolio, the decision was made
to continue investment in this goal, as Sarta is a key growth asset
going forward. With first oil having been achieved in November
2020, the field is now generating cash that will support the
funding of future appraisal and development, as we look to
replicate the success of the Peshkabir produce while appraise
model.
The first well on production was Sarta-3. This was joined in
February 2021 by the Sarta-2 well, and production from the field is
now over 10,000 bopd, with the ongoing optimisation of facilities
configuration expected to further increase production.
Sarta will again form the majority of our pre-production
expenditure in 2021, with c.USD60 million to be spent on the
appraisal drilling campaign and associated facilities work. The
campaign will begin at the start of Q2 and Sarta-5 and Sarta-6 will
be drilled back to back, with results from the first well expected
in Q3, and operations on both wells complete in Q4 2021. The
campaign is targeting a material portion of the 250 MMbbls of
existing contingent resources, and prospective resources, in
Jurassic formations.
Re-entry and deepening of the Sarta-1 (S-1D) well is expected
around the middle of the year. Should S-1D be successful, a
flowline will be constructed in order to enable the well to enter
production around the end of 2021.
Taq Taq (44% working interest, joint operator)
Gross production at Taq Taq averaged 9,670 bopd in 2020,
following the suspension of drilling activity in H1 2020.
Operations at Taq Taq are focused on optimising cash flow, and
no drilling is scheduled in 2021, with activity limited to
workovers that will help manage field decline. Genel continues to
explore the best way to obtain value from future production at the
licence.
PRE-PRODUCTION ASSETS
Qara Dagh (40% working interest, operator)
Preparations were well under way to spud the QD-2 well in H1
2020, prior to the uncertainty caused by COVID-19 forcing Genel to
notify the KRG of the occurrence of a force majeure event
preventing the Company from being able to perform its contractual
obligations as scheduled.
The increased certainty in the operating environment, and
Genel's ability to operate under the expected level of
restrictions, allowed the lifting of force majeure at Qara Dagh in
early Q4 2020. Genel was able to proceed with approvals for
activities necessary in order to reach a spud date for the QD-2
well, which is expected in coming weeks.
The Parker rig has now been mobilised, and the well is expected
to spud in line with this schedule, with drilling operations
anticipated to complete in Q3 2021.
Qara Dagh offers an exciting appraisal opportunity. The QD-1
well, completed in 2011, tested light oil in two zones from the
Shiranish formation. The QD-2 well location has been selected c.10
km to the northwest of QD-1, and will test a more crestal position
on the structure with a high angle well to maximise contact with
reservoir fractures. The field holds resources estimated by Genel
at gross mean c.400 MMbbls.
Bina Bawi and Miran (100% working interest, operator)
Bina Bawi and Miran are assets that have the potential to
generate significant shareholder value, and efforts have continued
to explore a commercial solution to allow the unlocking of the
material resources.
Discussions with the KRG are ongoing at the highest levels,
which would enable the Company to progress to the next stage of
activity.
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
The uncertainty created by COVID-19 delayed the search for
partners to fund and minimise Genel's spend on our potentially
high-impact exploration wells, but the farm-out process relating to
the highly prospective SL10B13 block in Somaliland (100% working
interest and operator) continues to progress, with potential
partners involved in assessing the opportunity.
A farm-out campaign is also planned relating to the Lagzira
block offshore Morocco (75% working interest and operator), with
the aim of bringing a partner onto the licence prior to considering
further commitments.
FINANCIAL REVIEW
Overview
Our now well-established and proven business model enabled us to
successfully navigate the extremely challenging conditions faced in
2020, with COVID-19's adverse impact on oil price and operating
conditions severely testing our ability to deliver against our
priorities. Our success in doing so has positioned us well to
maximise the benefit from the recent oil price improvement with a
stronger and more diverse portfolio.
Resilient operating model and assets
2020 demonstrated the resilience of our operating model and
assets in three principal ways. Firstly, through the speed at which
we were able to reduce capital activity and spend. Secondly, by the
ability of our production assets to be profitable even at low oil
prices. That profitability meant that we generated sufficient
income to cover our outgoings. Thirdly, our success at Sarta proved
the benefits of bringing assets onto production quickly and at low
cost, meaning that the cost to first oil was affordable even in
stressed conditions.
Strong balance sheet with no near-term debt maturity
Maintaining a strong balance sheet remains one of our key
priorities. We reported net cash at the end of the year, despite
not being paid USD159 million owed to us by the KRG for oil
sales.
The resilient business, strong balance sheet and significant
liquidity enabled the Company to take an important and proactive
step forward and derisk the balance sheet and the funding of our
capital activity programme by refinancing our debt, thereby moving
the maturity date from December 2022 to October 2025.
The old bonds of USD300 million were settled at an average
redemption price of 106.5, a small premium over the 103 that we
would have paid if we had waited until the final year of the bond
to redeem, or 102 if we waited as late as the last 6 months.
New bonds, maturing in 2025, were issued in October at a 3%
discount. The issue discount of 3% results in an implied coupon of
9.85%. The Company has taken the opportunity to purchase USD20
million of its own bonds, in order to reduce interest cost but
retain optionality.
Our current debt level of USD280 million reduced materially
after year-end following settlement of the remaining USD77 million
2022 bonds at the call price of 105, resulting in net cash of USD6
million.
FY2020 financial priorities and financial performance
The table below summarises our progress against the 2020
financial priorities of the Company as set out at our 2019
results.
FY2020 financial priorities Progress
? Maintaining our financial strength through existing market ? Net cash position maintained at YE2020, with the
conditions expectation of the same in 2021 at the prevailing
oil price
? Despite COVID-19 bringing material challenges: we
? Continued focus on capital allocation, with prioritisation of invested to bring Sarta to first oil in 2020 and
highest value investment in assets with ongoing or near-term prepared for the drilling of the Qara Dagh-2 well
cash and value generation in 2021
? Delivery of a 2020 work programme on time and on budget, that ? A recut 2020 work programme and budget,
is appropriate to the external environment appropriate to the external environment, was
delivered on time and within budget
? Continued focus on identifying and developing additional
assets that offer potential for significant value to the ? With a specific reference to progressing Sarta
Company with near to mid-term cash generation, primarily to and Qara Dagh, management continues to seek to
further build the Company's cash generation options when the mature further growth opportunities that fit the
override royalty agreement ends in Q3 2022 and provide the Company's capital structure and business model
basis for increasing the dividend in the future both within and outside the existing portfolio
The table below summarises our financial performance in the year
(all figures USD million unless stated) reporting a free cash
outflow of only USD4.4 million despite the non-payment of USD159
million that was due in the period:
FY2020 FY2019
Brent average oil price USD42/bbl USD64/bbl
Revenue 159.71 377.2
Production costs (32.7) (37.7)
Producing asset capex (56.5) (115.1)
Working capital 14.9 (59.7)
Cash generated from producing assets 85.41 164.7
G&A (excl. depreciation and amortisation) (12.4) (17.7)
Net cash interest2 (23.8) (23.4)
Free cash flow before investment in growth 49.2 123.6
Pre-production capex (53.2) (43.0)
Working capital and other (0.4) 18.4
Free cash flow (4.4) 99.0
Sales receipts due but not received (see note 10) plus suspended override1 158.6 54.1
1 Revenue does not include USD37.8 million of invoiced override
revenue where payment was suspended from March 2020 to December
2020 because it did not meet criteria for recognition (see note
1)
2 Net cash interest is bond interest payable less bank interest
income (see note 5) ? Our producing assets have delivered
predictable production, and liquidity has been preserved by taking
quick steps
to materially reduce capex to a level appropriate to the oil
price ? General and administration costs have been optimised
Fully funded appraisal and development programme for Sarta; Qara
Dagh funded in success case
The combination of our resilient assets, strong balance sheet,
and extended debt maturity puts us in a position where we are not
dependent on oil price or recovery of monies owed by the KRG to
execute Sarta and Qara Dagh appraisal and, in the success case,
subsequent expansion of both.
We are pleased to note the recent oil price improvement and are
encouraged at the progress regarding payment of the monies owed to
us by the KRG. The KRG has announced incremental repayments based
on 50% of the surplus of average monthly Brent price above
USD50/bbl multiplied by production. The first payment on this basis
was received in March.
The combination of oil price, payment for overdue receivables,
and the resumption of override payments, significantly increases
the cash generation of our production business. Our production
covers costs and investment in production maintenance and growth at
lower oil prices and is significantly cash generative based on the
current oil price and outlook.
Dividend
In 2019, our confidence in our business plan to replace and grow
producing asset cash generation at value accretive cost was
demonstrated by the commencement of a material and sustainable
dividend, and USD41 million was distributed to shareholders in the
year.
The Company was committed to and able to maintain our dividend
unchanged through the challenges of 2020, illustrating a resilience
that we believe sets us apart from many of our peers. The dividend
is an important part of our investment story and the hard work done
in 2020 has put us in a good position to benefit from oil price
improvement and continue that story. Our dividend capacity is
solid, despite having Sarta, Qara Dagh and Bina Bawi that all have
potential to require near-term capital in the success case. The
Board has approved the final dividend unchanged at 10c per share,
resulting in a final dividend payment of around USD28 million.
Including the earlier distributed interim dividend, this brings our
total dividends for the financial year to 15c per share, a total
payment of USD42 million. We continue to look to increase the
dividend, with confidence in a growing reserve base and outlook
cash being key to that decision.
Outlook and financial priorities for 2021
With cash of USD274 million after settlement of bonds, producing
asset cash flows that cover corporate and bond interest costs and
fund pre-production investment, and Sarta now contributing
meaningfully to our cash generation, the Company is well positioned
for 2021.
The Company has a portfolio that contains discovered resource
with potential for creation of material shareholder value.
We will continue to focus our capital allocation where we see it
delivering most value and the most rapid returns. For 2021, capital
expenditure guidance is USD150-200 million, which at the upper end
of the range is nearly double our spend in 2020 as we appraise
Sarta and drill Qara Dagh-2. Although the objective of these wells
is primarily to deliver incremental reserves and resources, they
have the potential to add significantly to production already in
2022.
For 2021, our financial priorities are the following: ? Maintain
our financial strength and continue protecting the balance sheet ?
Maximise NPV by prioritising highest value investment in assets
with ongoing or near-term cash and value generation ? Deliver 2021
work programme on time and on budget ? Continue to focus on growing
our income streams and cash generation, bringing greater resilience
and diversity to
the business and supporting our sustainable and progressive
dividend programme
Financial results for the year
Income statement
(all figures USD million) FY 2020 FY 2019
Production (bopd, working interest) 31,980 36,250
Profit oil 55.4 117.2
Cost oil 84.9 147.2
Override royalty 19.4 112.8
Revenue 159.7 377.2
Production costs (32.7) (37.7)
G&A (excl. depreciation and amortisation) (12.4) (17.7)
EBITDAX 114.6 321.8
Depreciation and amortisation (153.7) (158.5)
Impairment (323.2) (29.8)
Exploration expense (2.2) (1.2)
Net finance expense (52.2) (27.7)
Income tax expense (0.2) (0.7)
(Loss) / Profit (416.9) 103.9
Working interest production of 31,980 bopd decreased
year-on-year (2019: 36,250 bopd), with the decrease in revenue from
USD377.2 million to USD159.7 million, principally caused by: ?
lower Brent oil price USD108 million ? lower capex resulting in
lower cost oil USD62 million ? override unpaid from March onwards
USD38 million
Production costs of USD32.7 million decreased from last year
(2019: USD37.7 million) as a result of scaled back activity on
producing assets. Production cost per barrel was USD2.8/bbl in 2020
(2019: USD2.9/bbl).
General and administration costs were USD12.8 million (2019:
USD19.1 million), of which corporate cash costs were USD9.6 million
(2019: USD13.3 million). The reduction from the prior period is a
result of optimisation of costs and increased capital activity,
principally at Sarta and Qara Dagh.
The decrease in revenue resulted in a similar reduction to
EBITDAX of USD114.6 million (2019: USD321.8 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 USD98.7 million (2019: USD88.8 million) and
Tawke intangibles amortisation of USD54.6 million (2019: USD68.3
million) slightly decreased in total as a net result of decrease in
production and impairments at half year lowering the deprecation
rate per barrel.
At the half year, an impairment expense of USD254.7 million for
Tawke CGU, USD31.6 million for Taq Taq and USD34.9 million for
trade receivables was booked which is explained further in note 1
(2019: USD29.8 million). There was no further impairment at
year-end.
Bond interest expense of USD31.5 million was slightly increased
due to higher bond payable at year end. Call option for remaining
part of existing bond was settled in January 2021. Finance income
of USD2.0 million (2019: USD6.6 million) was bank interest income.
Other finance expense of USD22.7 million (2019: USD4.3 million)
included premium on bond buyback and non-cash discount unwind
expense on liabilities.
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 (2020: USD0.2
million, 2019: USD0.7 million).
Capital expenditure
Capital expenditure is the aggregation of spend on production
assets (USD56.5 million) and pre-production assets (USD53.2
million) and is reported to provide investors with an understanding
of the quantum and nature of investment that is being made in the
business. Capital expenditure for the period was USD109.7 million,
predominantly focused on production assets and the Sarta PSC
(USD30.0 million) and Qara Dagh (USD10.6 million):
(all figures USD million) FY 2020 FY 2019
Cost recovered production capex 56.5 115.1
Pre-production capex - oil 30.0 22.1
Pre-production capex - gas 10.0 11.9
Other exploration and appraisal capex 13.2 9.0
Capital expenditure 109.7 158.1
Cash flow, cash, net cash and debt
Gross proceeds received totalled USD173.4 million (2019:
USD317.4 million), of which USD22.9 million (2019: USD91.5 million)
was received for the override royalty.
(all figures USD million) FY 2020 FY 2019
Brent average oil price USD42/bbl USD64/bbl
Operating cash flow 129.4 272.9
Producing asset cost recovered capex (60.2) (105.1)
Development capex (25.3) (18.7)
Exploration and appraisal capex (24.2) (26.5)
Restricted cash release 3.0 7.0
Interest and other (27.1) (30.6)
Free cash flow (4.4) 99.0
Free cash flow is presented in order to show the free cash
generated that is available for the Board to invest in the
business. The measure provides the reader a better understanding of
the underlying business cash flows. Free cash out flow before
dividend was USD4.4 million (2019: positive USD99.0 million), with
an overall decrease in cash of USD36.2 million in the year (2019:
USD56.4 million increase).
(all figures USD million) FY 2020 FY 2019
Free cash flow (4.4) 99.0
Dividend paid (incl. expenses) (55.3) (29.0)
Purchase of own shares (3.4) (13.5)
Bond refinancing 28.9 -
Other (2.0) (0.1)
Net change in cash (36.2) 56.4
Opening cash 390.7 334.3
Closing cash 354.5 390.7
Debt reported under IFRS (348.3) (297.9)
Net cash 6.2 92.8
The bonds maturing 2025 have two financial covenant maintenance
tests:
Financial covenant Test YE 2020
Equity ratio (Total equity/Total assets) > 40% 60%
Minimum liquidity > USD30m USD355m
Net assets
Net assets at 31 December 2020 were USD929.8 million (2019:
USD1,386.1 million) and consist primarily of oil and gas assets of
USD1,095.1 million (2019: USD1,412.5 million), trade receivables of
USD94.0 million (2019: USD150.2 million) and net cash of USD6.2
million (2019: USD92.8 million).
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
Total dividends declared in 2020 amounted to USD41.5 million
(2019: USD40.8 million), representing 15¢ per share (2019: 15¢ per
share).
The Board is recommending no change in the final dividend of 10¢
per share (2019: 10¢ per share), a total distribution of c.USD27.9
million.
The payment timetable for the final dividend is below: ? Annual
General Meeting: 6 May 2021 ? Ex-dividend date: 13 May 2021 ?
Record Date: 14 May 2021 ? Payment Date: 14 June 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 annual report for the
period ended 31 December 2020 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.
Consolidated statement of comprehensive income
For the year ended 31 December 2020
Note 2020 2019
USDm USDm
Revenue 2 159.7 377.2
Production costs 3 (32.7) (37.7)
Depreciation and amortisation of oil assets 3 (153.3) (157.1)
Gross (loss) / profit (26.3) 182.4
Exploration expense 3 (2.2) (1.2)
Impairment of intangible assets 3-8 (44.3) -
Impairment of property, plant and equipment 3-9 (242.0) (29.8)
Impairment of receivables 10 (36.9) -
General and administrative costs 3 (12.8) (19.1)
Operating (loss) / profit (364.5) 132.3
Operating (loss) / profit is comprised of:
EBITDAX 114.6 321.8
Depreciation and amortisation 3 (153.7) (158.5)
Exploration expense 3 (2.2) (1.2)
Impairment of intangible assets 3-8 (44.3) -
Impairment of property, plant and equipment 3-9 (242.0) (29.8)
Impairment of receivables
10 (36.9) -
Finance income 5 2.0 6.6
Bond interest expense 5 (31.5) (30.0)
Other finance expense 5 (22.7) (4.3)
(Loss) / Profit before income tax (416.7) 104.6
Income tax expense 6 (0.2) (0.7)
(Loss) / Profit and total comprehensive (expense) / income (416.9) 103.9
Attributable to:
Owners of the parent (416.9) 103.9
(416.9) 103.9
(Loss) / earnings per ordinary share ¢ ¢
Basic 7 (152.0) 37.8
Diluted 7 (152.0) 37.0
Underlying1 41.8 116.9
1 Underlying EPS is EBITDAX divided by weighted average number
of ordinary shares
Consolidated balance sheet
At 31 December 2020
Note 2020 2019
USDm USDm
Assets
Non-current assets
Intangible assets 8 699.4 775.6
Property, plant and equipment 9,19 395.7 636.9
Trade and other receivables 10 52.1 -
1,147.2 1,412.5
Current assets
Trade and other receivables 10 48.9 157.4
Restricted cash 11 - 3.0
Cash and cash equivalents 11 354.5 390.7
403.4 551.1
Total assets 1,550.6 1,963.6
Liabilities
Non-current liabilities
Trade and other payables 12-19 (100.4) (118.8)
Deferred income 13 (19.7) (26.7)
Provisions 14 (45.9) (37.4)
Interest bearing loans 15 (267.7) (297.9)
(433.7) (480.8)
Current liabilities
Trade and other payables 12-19 (99.0) (91.7)
Deferred income 13 (7.5) (5.0)
Interest bearing loans 15 (80.6) -
(187.1) (96.7)
Total liabilities (620.8) (577.5)
Net assets 929.8 1,386.1
Owners of the parent
Share capital 17 43.8 43.8
Share premium account 3,991.9 4,033.4
Accumulated losses (3,105.9) (2,691.1)
Total equity 929.8 1,386.1
Consolidated statement of changes in equity
For the year ended 31 December 2020
Share capital Share premium Accumulated losses Total equity
Note
USDm USDm USDm USDm
At 1 January 2019 43.8 4,074.2 (2,786.6) 1,331.4
Profit and total comprehensive income - - 103.9 103.9
Share-based payments 20 - - 5.1 5.1
Purchase of shares to satisfy share awards - - (8.2) (8.2)
Purchase of treasury shares - - (5.3) (5.3)
Dividends provided for or paid1 18 - (40.8) - (40.8)
At 31 December 2019 and 1 January 2020 43.8 4,033.4 (2,691.1) 1,386.1
Loss and total comprehensive expense - - (416.9) (416.9)
Share-based payments 20 - - 5.5 5.5
Purchase of shares for employee share awards - - (3.4) (3.4)
Dividends provided for or paid1 18 - (41.5) - (41.5)
At 31 December 2020 43.8 3,991.9 (3,105.9) 929.8
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).
Consolidated cash flow statement
For the year ended 31 December 2020
Note 2020 2019
USDm USDm
Cash flows from operating activities
(Loss) / Profit for the year (416.9) 103.9
Adjustments for:
Net finance expense 5 52.2 27.7
Taxation 6 0.2 0.7
Depreciation and amortisation 3 153.7 158.5
Exploration expense 3 2.2 1.2
Impairments 3 323.2 29.8
Other non-cash items 3 (3.7) (2.4)
Changes in working capital:
Decrease / (Increase) in trade receivables 15.8 (55.4)
Decrease / (Increase) in other receivables 0.6 (0.2)
Increase in trade and other payables 0.4 3.3
Cash generated from operations 127.7 267.1
Interest received 5 2.0 6.6
Taxation paid (0.3) (0.8)
Net cash generated from operating activities 129.4 272.9
Cash flows from investing activities
Purchase of intangible assets (24.2) (26.5)
Purchase of property, plant and equipment (85.5) (123.8)
Movement in restricted cash 11 3.0 7.0
Net cash used in investing activities (106.7) (143.3)
Cash flows from financing activities
Dividends paid to company's shareholders, including expenses 18 (55.3) (29.0)
Purchase of own shares (3.4) (13.5)
Bond refinancing: part-settlement and new issuance 15 28.9 -
Other (3.3) (0.6)
Interest paid (25.8) (30.0)
Net cash used in financing activities (58.9) (73.1)
Net (decrease) / increase in cash and cash equivalents (36.2) 56.5
Foreign exchange loss on cash and cash equivalents - (0.1)
Cash and cash equivalents at 1 January 11 390.7 334.3
Cash and cash equivalents at 31 December 11 354.5 390.7
Post-year end payments1 15 (81.0) (13.6)
Cash and cash equivalents after post-year end payments 273.5 377.1
1 On 8 January 2021, shortly after the balance sheet date, the
Company paid USD81.0 million to settle USD77.1 million of old bonds
reducing its gross debt balance to USD280 million, with USD267.7
million reported under IFRS in the balance sheet. In the prior
year, an interim dividend payment of USD13.6 million was made on 8
January 2020, which has been shown as a comparative.
Notes to the consolidated financial statements
1. Summary of significant accounting policies 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 consolidated financial statements of the Company have been
prepared in accordance with International Financial Reporting
Standards as adopted by the European Union and interpretations
issued by the IFRS Interpretations Committee (together 'IFRS'); are
prepared under the historical cost convention except as where
stated; and comply with Company (Jersey) Law 1991. The significant
accounting policies are set out below and have been applied
consistently throughout the period.
The Company prepares its financial statements on a historical
cost basis, unless accounting standards require an alternate
measurement basis. Where there are assets and liabilities
calculated on a different basis, this fact is disclosed either in
the relevant accounting policy or in the notes to the financial
statements.
Items included in the financial information of each of the
Company's entities are measured using the currency of the primary
economic environment in which the entity operates (the functional
currency). The consolidated financial statements are presented in
US dollars to the nearest million (USDm) rounded to one decimal
place, except where otherwise indicated.
For explanation of the key judgements and estimates made by the
Company in applying the Company's accounting policies, refer to
significant accounting judgements and estimates on pages 20 and
23.
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 after settlement of
bonds post year-end of USD273.5 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 and 4
months of payments with a value of USD120.8 million that were due
in the year were not received, by delivering a small free cash out
flow after investing significantly in bringing Sarta to first
production. The strength of the balance sheet is expected to be
maintained through 2021, with Sarta adding a new income stream and
diversifying production risk, and capital activity in the year
focused on expanding the sources of income of the business further.
Our low-cost assets with flexibility on commitment of capital means
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. 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 annual report for
the period ended 31 December 2020 and consequently that the Company
is considered a going concern.
Foreign currency
Foreign currency transactions are translated into the functional
currency of the relevant entity using the exchange rates prevailing
at the dates of the transactions or at the balance sheet date where
items are re-measured. Foreign exchange gains and losses resulting
from the settlement of such transactions and from the translation
at period-end exchange rates of monetary assets and liabilities
denominated in foreign currencies are recognised in the statement
of comprehensive income within finance income or finance costs.
Consolidation
The consolidated financial statements consolidate the Company
and its subsidiaries. These accounting policies have been adopted
by all companies.
Subsidiaries
Subsidiaries are all entities over which the Company has
control. The Company controls an entity when it is exposed to, or
has rights to, variable returns from its involvement with the
entity and has the ability to affect those returns through its
power over the entity. Subsidiaries are fully consolidated from the
date on which control is transferred to the Company. They are
deconsolidated from the date that control ceases. Transactions,
balances and unrealised gains on transactions between companies are
eliminated.
Joint arrangements and associates
Arrangements under which the Company has contractually agreed to
share control with another party, or parties, are joint ventures
where the parties have rights to the net assets of the arrangement,
or joint operations where the parties have rights to the assets and
obligations for the liabilities relating to the arrangement.
Investments in entities over which the Company has the right to
exercise significant influence but has neither control nor joint
control are classified as associates and accounted for under the
equity method.
The Company recognises its assets and liabilities relating to
its interests in joint operations, including its share of assets
held jointly and liabilities incurred jointly with other
partners.
Acquisitions
The Company uses the acquisition method of accounting to account
for business combinations. Identifiable assets acquired and
liabilities and contingent liabilities assumed in a business
combination are measured at their fair values at the acquisition
date. The Company recognises any non-controlling interest in the
acquiree at fair value at time of recognition or at the
non-controlling interest's proportionate share of net assets.
Acquisition-related costs are expensed as incurred.
Farm-in/farm-out
Farm-out transactions relate to the relinquishment of an
interest in oil and gas assets in return for services rendered by a
third party or where a third party agrees to pay a portion of the
Company's share of the development costs (cost carry). Farm-in
transactions relate to the acquisition by the Company of an
interest in oil and gas assets in return for services rendered or
cost-carry provided by the Company.
Farm-in/farm-out transactions undertaken in the development or
production phase of an oil and gas asset are accounted for as an
acquisition or disposal of oil and gas assets. The consideration
given is measured as the fair value of the services rendered or
cost-carry provided and any gain or loss arising on the
farm-in/farm-out is recognised in the statement of comprehensive
income. A profit is recognised for any consideration received in
the form of cash to the extent that the cash receipt exceeds the
carrying value of the associated asset.
Farm-in/farm-out transactions undertaken in the exploration
phase of an oil and gas asset are accounted for on a no gain/no
loss basis due to inherent uncertainties in the exploration phase
and associated difficulties in determining fair values reliably
prior to the determination of commercially recoverable proved
reserves. The resulting exploration and evaluation asset is then
assessed for impairment indicators under IFRS 6. 2. Significant
accounting judgements and estimates
The preparation of the financial statements in accordance with
IFRS requires the Company to make judgements and estimates 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 override revenue; ii) the Bina Bawi and Miran projects will
progress which 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.
Change in accounting estimate
The Company has updated its estimated reserves and resources
with the accounting impact summarised below under estimation of oil
and gas asset values. 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 the project is outside of 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.
Change in accounting estimate - Discount rate for assessing
recoverable amount of producing assets
Following the significant change in the macro geo-political,
economic and industry environment, for the period ended 30 June
2020 the Company has updated the discount rate used for assessing
the recoverable amount of its producing assets from 12.5% to 13.0%.
At the half year this had a negative impact on the recoverable
amount of the Tawke CGU and the Taq Taq CGU. The results of the
assessments combining with other factors are explained below. The
Company disclosed the sensitivities on net present values in note
9. At the year-end the discount rate is unchanged from the half
year at 13.0%.
Change in accounting estimate - Tawke asset and Tawke RSA
(receivable settlement agreement) carrying value; Taq Taq carrying
value
At the half year, as a result of lower oil prices and lower
levels of investment than were forecasted in the preparation of the
financial statements for the year-ended 31 December 2019 were
finalised, together with the higher discount rate explained above,
management assessed that there were impairment indicators for both
Tawke and Taq Taq. Management performed impairment assessments and
assessed their recoverable values on a fair value less cost to sell
basis, resulting in an impairment of USD210.4 million for the
Tawke; USD44.3 million for the Tawke RSA; and USD31.6 million for
the Taq Taq asset respectively. There were no impairment indicators
at the end of the year, and in particular, the oil price outlook
has improved since the half year as disclosed below.
Change in accounting estimate - Taq Taq and Tawke
depreciation
Management has reassessed the depreciation rate per barrel
during the second half, principally as a result of lower estimate
of future production and costs for Taq Taq, increased future cost
estimate for Tawke and the impact of HY impairments on both assets.
Change in future cost estimates do not materially impact NPV as a
result of cost recovery which is explained further in the
sensitivity to capital expenditure disclosure in note 9. The
adjusted depreciation rate results in a depreciation expense that
is USD6 million higher for Taq Taq and USD4 million higher for
Tawke than if the previous depreciation rate per barrel was
used.
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.
USD/bbl 2020 2021 2022 2023 2024
Actual / Forecast 42 55 55 60 60
HY 2020 forecast 40 43 50 55 60
Prior year forecast 65 67 68 72 73
The 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 trade 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
USD120.8 million.
For the period ended 30 June 2020, the Company estimated
recovery of these overdue amounts, which resulted in an impairment
of USD34.9 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 USD50/bbl,
50 cents per working interest barrel shall be paid towards monies
owed.
In order to assess the recoverable amount of overdue trade
receivables at 31 December 2020, 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 USD34.9 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, 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 USD37.8 million.
1.3 Accounting policies
The accounting policies adopted in preparation of these
financial statements are consistent with those used in preparation
of the annual financial statements for the year ended 31 December
2019, adjusted for transitional requirements where necessary,
further explained under revenue and changes in accounting policies
headings.
Revenue
Revenue for oil sales is recognised when the control of the
product is deemed to have passed to the customer, in exchange for
the consideration amount determined by the terms of the contract.
For exports the control passes to the customer when the oil enters
the export pipe, for domestic sales this is when oil is collected
by truck by the customer.
Revenue is earned based on the entitlement mechanism under the
terms of the relevant PSC; overriding royalty income ('ORRI'),
which is earned on 4.5% of gross field revenue from the Tawke
licence until July 2022; and royalty income. Entitlement has two
components: cost oil, which is the mechanism by which the Company
recovers its costs incurred on an asset, and profit oil, which is
the mechanism through which profits are shared between the Company,
its partners and the KRG. The Company pays capacity building
payments on profit oil entitlement earned on the Sarta and Taq Taq
licences, which becomes due for payment once the Company has
received the relevant proceeds. Profit oil revenue is always
reported net of any capacity building payments that will become
due. On the Tawke licence, the Company also receives override
revenue ("ORRI"), which is calculated as 4.5% of Tawke PSC field
revenue. The override began in August 2017 and is due to end in
July 2022.
The Company's oil sales are made to the KRG which is the
counterparty of the PSCs and are valued at a netback price, which
is calculated from the estimated realised sales price for each
barrel of oil sold, less selling, transportation and handling costs
and estimates to cover additional costs. A netback adjustment is
used to estimate the price per barrel that is used in the
calculation of entitlement and is explained further in significant
accounting estimates and judgements.
The payment terms for the Company's sales are due within 30
days. The Company does not expect to have any contracts where the
period between the transfer of oil to the customer and the payment
exceeds one year. Therefore, the transaction price is not adjusted
for the time value of money.
The Company is not able to measure the tax that has been paid on
its behalf and consequently revenue is not reported gross of income
tax paid.
Intangible assets
Exploration and evaluation assets
Oil and gas assets classified as exploration and evaluation
assets are explained under Oil and Gas assets below.
Tawke RSA
Intangible assets include the Receivable Settlement Agreement
('RSA') effective from 1 August 2017, which was entered into in
exchange for trade receivables due from KRG for Taq Taq and Tawke
past sales. The RSA was recognised at cost and is amortised on a
units of production basis in line with the economic lives of the
rights acquired.
Other intangible assets
Other intangible assets that are acquired by the Company are
stated at cost less accumulated amortisation and less accumulated
impairment losses. Amortisation is expensed on a straight-line
basis over the estimated useful lives of the assets of between 3
and 5 years from the date that they are available for use.
Property, plant and equipment
Producing and Development assets
Oil and gas assets classified as producing and development
assets are explained under Oil and Gas assets below.
Other property, plant and equipment
Other property, plant and equipment are principally the
Company's leasehold improvements and other assets and are carried
at cost, less any accumulated depreciation and accumulated
impairment losses. Costs include purchase price and construction
cost. Depreciation of these assets is expensed on a straight-line
basis over their estimated useful lives of between 3 and 5 years
from the date they are available for use.
Oil and gas assets
Costs incurred prior to obtaining legal rights to explore are
expensed to the statement of comprehensive income.
Exploration, appraisal and development expenditure is accounted
for under the successful efforts method. Under the successful
efforts method only costs that relate directly to the discovery and
development of specific oil and gas reserves are capitalised as
exploration and evaluation assets within intangible assets so long
as the activity is assessed to be de-risking the asset and the
Company expects continued activity on the asset into the
foreseeable future. Costs of activity that do not identify oil and
gas reserves are expensed.
All licence acquisition costs, geological and geophysical costs
and other direct costs of exploration, evaluation and development
are capitalised as intangible assets or property, plant and
equipment according to their nature. Intangible assets comprise
costs relating to the exploration and evaluation of properties
which the directors consider to be unevaluated until assessed as
being 2P reserves and commercially viable.
Once assessed as being 2P reserves they are tested for
impairment and transferred to property, plant and equipment as
development assets. Where properties are appraised to have no
commercial value, the associated costs are expensed as an
impairment loss in the period in which the determination is made.
Development assets are classified under producing assets following
the commercial production commencement.
Development expenditure is accounted for in accordance with IAS
16 - Property, plant and equipment. Producing assets are
depreciated once they are available for use and are depleted on a
field-by-field basis using the unit of production method. The sum
of carrying value and the estimated future development costs are
divided by total barrels to provide a USD/barrel unit depreciation
cost. Changes to depreciation rates as a result of changes in
forecast production and estimates of future development expenditure
are reflected prospectively.
The estimated useful lives of property, plant and equipment and
their residual values are reviewed on an annual basis and changes
in useful lives are accounted for prospectively. The gain or loss
arising on the disposal or retirement of an asset is determined as
the difference between the sales proceeds and the carrying amount
of the asset and is recognised in the statement of comprehensive
income for the relevant period.
Where exploration licences are relinquished or exited for no
consideration or costs incurred are neither de-risking nor adding
value to the asset, the associated costs are expensed to the income
statement.
Impairment testing of oil and gas assets is considered in the
context of each cash generating unit. A cash generating unit is
generally a licence, with the discounted value of the future cash
flows of the CGU compared to the book value of the relevant assets
and liabilities. As an example, the Tawke CGU is comprised of the
Tawke RSA intangible asset, property, plant and equipment (relating
to both the Tawke field and the Peshkabir field) and the associated
decommissioning provision.
Subsequent costs
The cost of replacing part of an item of property and equipment
is recognised in the carrying amount of the item if it is probable
that the future economic benefits embodied within the part will
flow to the Company, and its cost can be measured reliably. The net
book value of the replaced part is expensed. The costs of the
day-to-day servicing and maintenance of property, plant and
equipment are recognised in the statement of comprehensive income.
Business combinations
The recognition of business combinations requires the allocation
of the excess of the purchase price of acquisitions over the net
book value of assets acquired to the assets and liabilities of the
acquired entity. The Company makes judgements and estimates in
relation to the fair value allocation of the purchase price.
The fair value exercise is performed at the date of acquisition.
Owing to the nature of fair value assessments in the oil and gas
industry, the purchase price allocation exercise and acquisition
date fair value determinations require subjective judgements based
on a wide range of complex variables at a point in time. The
Company uses all available information to make the fair value
determinations.
In determining fair value for acquisitions, the Company utilises
valuation methodologies including discounted cash flow analysis.
The assumptions made in performing these valuations include
assumptions as to discount rates, foreign exchange rates, commodity
prices, the timing of development, capital costs, and future
operating costs. Any significant change in key assumptions may
cause the acquisition accounting to be revised.
Financial assets and liabilities
Classification
The Company assesses the classification of its financial assets
on initial recognition at amortised cost, fair value through other
comprehensive income or fair value through profit and loss. The
Company assesses the classification of its financial liabilities on
initial recognition at either fair value through profit and loss or
amortised cost.
Recognition and measurement
Regular purchases and sales of financial assets are recognised
at fair value on the trade-date - the date on which the Company
commits to purchase or sell the asset. Trade and other receivables,
trade and other payables, borrowings and deferred contingent
consideration are subsequently carried at amortised cost using the
effective interest method.
Trade and other receivables
Trade receivables are amounts due from crude oil sales, sales of
gas or services performed in the ordinary course of business. If
payment is expected within one year or less, trade receivables are
classified as current assets otherwise they are presented as
non-current assets. Trade receivables are recognised initially at
fair value and subsequently measured at amortised cost using the
effective interest method, less provision for impairment.
Under the Tawke, Taq Taq and Sarta PSCs, payment for entitlement
is due within 30 days. The Company's assessment of impairment model
based on expected credit loss is explained below under financial
assets.
Cash and cash equivalents
In the consolidated balance sheet and consolidated statement of
cash flows, cash and cash equivalents includes cash in hand,
deposits held on call with banks, other short-term highly liquid
investments and includes the Company's share of cash held in joint
operations.
Interest-bearing borrowings
Borrowings are recognised initially at fair value, net of any
discount in issuance and transaction costs incurred. Borrowings are
subsequently carried at amortised cost; any difference between the
proceeds (net of transaction costs) and the redemption value is
recognised in the statement of comprehensive income over the period
of the borrowings using the effective interest method.
Fees paid on the establishment of loan facilities are recognised
as transaction costs of the loan to the extent that it is probable
that some or all of the facility will be drawn down. In this case,
the fee is deferred until the draw-down occurs. To the extent there
is no evidence that it is probable that some or all of the facility
will be drawn down, the fee is capitalised as a pre-payment for
liquidity services and amortised over the period of the facility to
which it relates.
Borrowings are presented as long or short-term based on the
maturity of the respective borrowings in accordance with the loan
or other agreement. Borrowings with maturities of less than twelve
months are classified as short-term. Amounts are classified as
long-term where maturity is greater than twelve months. Where no
objective evidence of maturity exists, related amounts are
classified as short-term.
Trade and other payables
Trade and other payables are recognised initially at fair value.
Subsequent to initial recognition they are measured at amortised
cost using the effective interest method.
Offsetting
Financial assets and liabilities are offset and the net amount
reported in the balance sheet when there is a legally enforceable
right to offset the recognised amounts and there is an intention to
settle on a net basis or realise the asset and settle the liability
simultaneously.
Provisions
Provisions are recognised when the Company has a present
obligation as a result of a past event, and it is probable that the
Company will be required to settle that obligation. Provisions are
measured at the Company's best estimate of the expenditure required
to settle the obligation at the balance sheet date, and are
discounted to present value where the effect is material. The
unwinding of any discount is recognised as finance costs in the
statement of comprehensive income.
Decommissioning
Provision is made for the cost of decommissioning assets at the
time when the obligation to decommission arises. Such provision
represents the estimated discounted liability for costs which are
expected to be incurred in removing production facilities and site
restoration at the end of the producing life of each field. A
corresponding cost is capitalised to property, plant and equipment
and subsequently depreciated as part of the capital costs of the
production facilities. Any change in the present value of the
estimated expenditure attributable to changes in the estimates of
the cash flow or the current estimate of the discount rate used are
reflected as an adjustment to the provision.
Impairment
Oil and gas assets
The carrying amounts of the Company's oil and gas assets are
reviewed at each reporting date to determine whether there is any
indication of impairment. If any such indication exists then the
asset's recoverable amount is estimated. The recoverable amount of
an asset or cash generating unit is the greater of its value in use
and its fair value less costs of disposal. For value in use, the
estimated future cash flows arising from the Company's future plans
for the asset are discounted to their present value using a nominal
post tax discount rate that reflects market assessments of the time
value of money and the risks specific to the asset. For fair value
less costs of disposal, an estimation is made of the fair value of
consideration that would be received to sell an asset less
associated selling costs (which are assumed to be immaterial).
Assets are grouped together into the smallest group of assets that
generates cash inflows from continuing use that are largely
independent of the cash inflows of other assets or groups of assets
(cash generating unit).
The estimated recoverable amount is then compared to the
carrying value of the asset. Where the estimated recoverable amount
is materially lower than the carrying value of the asset an
impairment loss is recognised. Non-financial assets that suffered
impairment are reviewed for possible reversal of the impairment at
each reporting date.
Property, plant and equipment and intangible assets
Impairment testing of oil and gas assets is explained above.
When impairment indicators exist for other non-financial assets,
impairment testing is performed based on the higher of value in use
and fair value less costs of disposal. The Company assets'
recoverable amount is determined by fair value less costs of
disposal.
Financial assets
Impairment of financial assets is assessed under IFRS 9 with a
forward-looking impairment model based on expected credit losses
(ECLs). The standard requires the Company to book an allowance for
ECLs for its financial assets. The Company has assessed its trade
receivables as at 31 December 2020 for ECLs. Further explanation is
provided in significant accounting judgements and estimates.
A financial asset is assessed at each reporting date to
determine whether there is any objective evidence that it is
impaired. A financial asset is considered to be impaired if
objective evidence indicates that one or more events have had a
negative effect on the estimate of future cash flows of that asset.
An impairment loss in respect of a financial asset measured at
amortised cost is calculated as the difference between its carrying
amount, and the present value of the estimated future cash flows
discounted at the original effective interest rate. All impairment
losses are recognised as an expense in the statement of
comprehensive income. An impairment loss is reversed if the
reversal can be related objectively to an event occurring after the
impairment loss was recognised.
Share capital
Ordinary shares are classified as equity.
When share capital recognised as equity is repurchased, the
amount of the consideration paid, which includes directly
attributable costs, is net of any tax effects and is recognised as
a deduction in equity. Repurchased shares are classified as
treasury shares and are presented as a deduction from total equity.
When treasury shares are subsequently sold or reissued, the amount
received is recognised as an increase in equity and the resulting
surplus or deficit of the transaction is transferred to/from
retained earnings.
Employee benefits
Short-term benefits
Short-term employee benefit obligations are expensed to the
statement of comprehensive income as the related service is
provided. A liability is recognised for the amount expected to be
paid under short-term cash bonus or profit-sharing plans if the
Company has a present legal or constructive obligation to pay this
amount as a result of past service provided by the employee and the
obligation can be estimated reliably.
Share-based payments
The Company operates equity-settled share-based compensation
plans. The expense required in accordance with IFRS2 is recognised
in the statement of comprehensive income over the vesting period of
the award. The expense is determined by reference to option pricing
models, principally Monte Carlo and adjusted Black-Scholes
models.
At each balance sheet date, the Company revises its estimate of
the number of options that are expected to become exercisable. Any
revision to the original estimates is reflected in the statement of
comprehensive income with a corresponding adjustment to equity
immediately to the extent it relates to past service and the
remainder over the rest of the vesting period.
Finance income and finance costs
Finance income comprises interest income on cash invested,
foreign currency gains and the unwind of discount on any assets
held at amortised cost. Interest income is recognised as it
accrues, using the effective interest method.
Finance expense comprises interest expense on borrowings,
foreign currency losses and discount unwind on any liabilities held
at amortised cost. Borrowing costs directly attributable to the
acquisition of a qualifying asset as part of the cost of that asset
are capitalised over the respective assets.
Taxation
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 would 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. Current tax expense is
incurred on profits of service companies.
Segmental reporting
IFRS 8 requires the Company to disclose information about its
business segments and the geographic areas in which it operates. It
requires identification of business segments on the basis of
internal reports that are regularly reviewed by the CEO, the chief
operating decision maker, in order to allocate resources to the
segment and assess its performance.
Related parties
Parties are related if one party has the ability, directly or
indirectly, to control the other party or exercise significant
influence over the party in making financial or operational
decisions. Parties are also related if they are subject to common
control. Transactions between related parties are transfers of
resources, services or obligations, regardless of whether a price
is charged and are disclosed separately within the notes to the
consolidated financial information.
New standards
The following new accounting standards, amendments to existing
standards and interpretations are effective on 1 January 2020.
Amendments to References to the Conceptual Framework in IFRS
Standards, Amendments to IAS 1 and IAS 8: Definition of Material,
Amendments to IFRS 9, IAS 39 and IFRS17: Interest Rate Benchmark
Reform, Amendments to IFRS 3 Business Combinations, Amendment to
IFRS 16 Leases Covid-19-Related Rent Concessions (1 Jun 2020).
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 2022), 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 IFRS 4 Insurance
Contracts - deferral of IFRS19 (1 Jan 2021), Amendments to IFRS 9,
IAS 39, IFRS 7, IFRS 4 and IFRS 16 Interest Rate Benchmark Reform -
Phase 2 (1 Jan 2021). 2. Segmental information
The Company has two reportable business segments: Production 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 the end of the year, 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 period ended 31 December 2020
Total
Production Pre-production Other
USDm USDm USDm USDm
Revenue from contracts with customers 155.0 - - 155.0
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 and equipment (242.0) - - (242.0)
Impairment of receivables (34.9) - (2.0) (36.9)
General and administrative costs - - (12.8) (12.8)
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 assets (44.3) - - (44.3)
Impairment of property, plant and equipment (242.0) - - (242.0)
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)
Revenue from contracts with customers includes USD14.7 million
(2019: USD104.3 million) arising from the ORRI, which is explained
further in note 1. The ORRI was suspended from March 2020 to
December 2020 and consequently no revenue has been recognised
relating to this period.
Total assets and liabilities in the other segment are
predominantly cash and debt balances.
For the period ended 31 December 2019
Pre-production Total
Production Other
USDm USDm USDm USDm
Revenue from contracts with customers 368.7 - - 368.7
Revenue from other sources 8.5 - - 8.5
Cost of sales (194.8) - - (194.8)
Gross profit 182.4 - - 182.4
Exploration expense - (1.2) - (1.2)
Impairment of property, plant and equipment (29.8) - - (29.8)
General and administrative costs - - (19.1) (19.1)
Operating profit / (loss) 152.6 (1.2) (19.1) 132.3
Operating profit / (loss) is comprised of
EBITDAX 339.5 - (17.7) 321.8
Depreciation and amortisation (157.1) - (1.4) (158.5)
Exploration expense - (1.2) - (1.2)
Impairment of property, plant and equipment (29.8) - - (29.8)
Finance income - - 6.6 6.6
Bond interest expense - - (30.0) (30.0)
Other finance expense (1.8) (0.3) (2.2) (4.3)
Profit / (Loss) before income tax 150.8 (1.5) (44.7) 104.6
Capital expenditure 115.1 43.0 - 158.1
Total assets 998.1 595.2 370.3 1,963.6
Total liabilities (99.4) (149.9) (328.2) (577.5)
Total assets and liabilities in the other segment are
predominantly cash and debt balances. 3. Cost of sales
2020 2019
USDm USDm
Operating costs (32.6) (37.7)
Trucking costs (0.1) -
Production cost (32.7) (37.7)
Depreciation of oil and gas property, plant and equipment (98.7) (88.8)
Amortisation of oil and gas intangible assets (54.6) (68.3)
Cost of sales (186.0) (194.8)
Exploration expense (2.2) (1.2)
Impairment of intangible assets (note 8) (44.3) -
Impairment of property, plant and equipment (note 9) (242.0) (29.8)
Impairment of receivables (note 10) (36.9) -
Corporate cash costs (9.6) (13.3)
Other operating expenses (1.8) (0.8)
Corporate share-based payment expense (1.0) (3.6)
Depreciation and amortisation of corporate assets (0.4) (1.4)
General and administrative expenses (12.8) (19.1)
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.
Fees payable to the Company's auditors:
2020 2019
USDm USDm
Audit of consolidated and subsidiary financial statements (0.6) (0.7)
Tax and advisory services (0.6) (0.2)
Total fees (1.2) (0.9)
4. Staff costs and headcount
2020 2019
USDm USDm
Wages and salaries (21.9) (18.6)
Contractors costs (7.7) (1.6)
Social security costs (2.0) (1.6)
Share based payments (5.8) (5.8)
(37.4) (27.6)
Staff costs include cost of contractors.
Average headcount was:
2020 number 2019 number
Turkey 56 62
KRI 21 18
UK 33 24
Somaliland 17 17
Contractors 38 28
165 149
5. Finance expense and income
2020 2019
USDm USDm
Bond interest paid (25.8) (30.0)
Bond interest accrued (5.7) -
Accelerated cost of bond settlement (see note 15) (19.4) -
Other finance expense (non-cash) (3.3) (4.3)
Finance expense (54.2) (34.3)
Bank interest income 2.0 6.6
Finance income 2.0 6.6
Net finance expense (52.2) (27.7)
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 profits of service companies.
Under the terms of the KRI PSCs, the Company is not required to pay
any cash corporate income taxes as explained in note 1. 7. (Loss) /
earnings per share
Basic
Basic (loss) / earnings per share is calculated by dividing the
(loss) / profit attributable to owners of the parent by the
weighted average number of shares in issue during the period.
2020 2019
(Loss) / Profit attributable to owners of the parent (USDm) (416.9) 103.9
Weighted average number of ordinary shares - number 1 274,202,853 275,197,007
Basic (loss) / earnings per share - cents per share (152.0) 37.8
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 year ended 31 December 2020,
diluted EPS is anti-dilutive and therefore diluted EPS is the same
as basic EPS:
2020 2019
(Loss) / Profit attributable to owners of the parent (USDm) (416.9) 103.9
Weighted average number of ordinary shares - number1 274,202,853 275,197,007
Adjustment for performance shares, restricted shares and share options - 5,859,457
Weighted average number of ordinary shares and potential ordinary shares 274,202,853 281,056,464
Diluted (loss) / earnings per share - cents per share (152.0) 37.0
1 Excluding shares held as treasury shares 8. Intangible
assets
Other
Exploration and evaluation assets Tawke Total
assets
RSA
USDm USDm USDm USDm
Cost
At 1 January 2019 1,493.2 425.1 6.8 1,925.1
Additions 20.9 - 0.5 21.4
Discount unwind of contingent consideration 5.2 - - 5.2
Other (0.8) - - (0.8)
At 31 December 2019 and 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 1,541.5 425.1 7.4 1,974.0
Accumulated amortisation and impairment
At 1 January 2019 (1,005.3) (94.9) (6.5) (1,106.7)
Amortisation charge for the period - (68.3) (0.3) (68.6)
At 31 December 2019 and 1 January 2020 (1,005.3) (163.2) (6.8) (1,175.3)
Amortisation charge for the period - (54.6) (0.4) (55.0)
Impairment - (44.3) - (44.3)
At 31 December 2020 (1,005.3) (262.1) (7.2) (1,274.6)
Net book value
At 31 December 2019 513.2 261.9 0.5 775.6
At 31 December 2020 536.2 163.0 0.2 699.4
Tawke RSA asset was impaired by USD44.3 million, further
explanation is provided in note 1.
2020 2019
Book value USDm USDm
Bina Bawi PSC Discovered gas and oil, appraisal 360.5 352.9
Miran PSC Discovered gas and oil, appraisal 123.2 120.3
Somaliland PSC Exploration 34.7 33.8
Qara Dagh PSC Exploration / Appraisal 17.8 6.2
Exploration and evaluation assets 536.2 513.2
Tawke overriding royalty 73.3 160.2
Tawke capacity building payment waiver 89.7 101.7
Tawke RSA assets 163.0 261.9
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.
USDm
Long term Brent +/- USD5/bbl +/- 13
Discount rate +/-2.5% +/- 101
Production and reserves +/- 10% +/- 32
9. Property, plant and equipment
Other
Producing assets Development assets
assets Total
USDm USDm USDm USDm
Cost
At 1 January 2019 2,757.2 - 9.6 2,766.8
Asset acquisitions - 49.4 - 49.4
Additions 115.1 22.1 0.3 137.5
Right-of-use assets - - 3.6 3.6
Net change in payable - (3.6) - (3.6)
Non-cash additions for ARO/SBP1 3.8 0.1 - 3.9
At 31 December 2019 and 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 (note 19) - - 8.1 8.1
Net change in payable - (5.4) - (5.4)
Non-cash additions for ARO/SBP/Production bonus 2.3 8.8 - 11.1
Transfer to producing assets 101.4 (101.4) - -
At 31 December 2020 3,036.3 - 22.6 3,058.9
Accumulated depreciation and impairment
At 1 January 2019 (2,192.1) - (8.9) (2,201.0)
Depreciation charge for the period (88.8) - (1.1) (89.9)
Impairment (29.8) - - (29.8)
At 31 December 2019 and 1 January 2020 (2,310.7) - (10.0) (2,320.7)
Depreciation charge for the period (98.7) - (1.8) (100.5)
Impairment (242.0) - - (242.0)
At 31 December 2020 (2,651.4) - (11.8) (2,663.2)
Net book value
At 31 December 2019 565.4 68.0 3.5 636.9
At 31 December 2020 384.9 - 10.8 395.7
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.
2020 2019
Book value USDm USDm
Tawke PSC Oil production 228.2 474.9
Taq Taq PSC Oil production 56.2 90.5
Sarta PSC Oil production/development 100.5 68.0
Producing assets 384.9 633.4
The sensitivities below provide an indicative impact on net
asset value of a change in long term Brent, discount rate or
production and reserves, assuming no change to any other
inputs.
Taq Taq
Tawke CGU
CGU
USDm
USDm
Long term Brent +/- USD5/bbl +/- 2 +/- 16
Discount rate +/- 2.5% +/- 3 +/- 37
Production and reserves +/- 10% +/- 4 +/- 39
10. Trade and other receivables
2020 2019
USDm USDm
Trade receivables - current 41.9 150.2
Trade receivables - non-current 52.1 -
Other receivables and prepayments 7.0 7.2
101.0 157.4
Under the Tawke, Taq Taq and Sarta PSCs, payment for entitlement
is due within 30 days. Since February 2016, there was a track
record of payments being received three months after invoicing,
which was previously assessed as the operating cycle under IAS1.
Since April 2020 the KRG has been settling invoices within one
month of invoicing, which is now assessed as the operating cycle
under IAS1.
Year of sale of
amounts overdue
Not due 2020 2019 Total overdue
USDm USDm USDm USDm
Trade receivables at 31 December 2019 (nominal) 98.8 n/a 54.1 54.1
Trade receivables at 31 December 2020 (nominal) 14.8 55.4 65.4 120.8
At 31 December 2020, USD120.8 million relating to invoices from
November 2019 to February 2020 was overdue and at the half year
required impairment of USD34.9 million as explained in note 1.
2020 2019
Movement on trade receivables in the period
USDm USDm
Carrying value at 1 January 150.2 94.8
Revenue from contracts with customers 155.0 368.7
Cash proceeds (173.4) (317.4)
Offset of payables due to the KRG (5.5) -
Expected credit loss (34.9) (0.5)
Capacity building payments 2.6 4.6
Carrying value at 31 December 94.0 150.2
Recovery of the carrying value of the receivable
The Company expects to recover the full nominal value of
USD120.8 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 1.
Total
USDm
Nominal balance to be recovered 120.8
Estimated net present value of total cash flows 85.9
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 December 2020.
Timing of repayment
Nominal receivables (USDm) Total NPV13.0
Year 1 Year 2 Year 3 Year 4
USD55/bbl 30.0 30.0 30.0 30.8 120.8 89.6
USD60/bbl 60.0 60.8 - - 120.8 100.6
Brent
USD65/bbl 90.0 30.8 - - 120.8 103.8
USD70/bbl 120.8 - - - 120.8 106.8
11. Cash and cash equivalents and restricted cash
2020 2019
USDm USDm
Cash and cash equivalents 354.5 390.7
Restricted cash - 3.0
354.5 393.7
Cash is primarily held on time deposit with major international
financial institutions or in US Treasury bills. 12. Trade and other
payables
2020 2019
USDm USDm
Trade payables 16.7 10.3
Other payables 128.1 144.4
Accruals 54.6 55.8
199.4 210.5
Non-current 100.4 118.8
Current 99.0 91.7
199.4 210.5
Current payables are predominantly short-term in nature or are
repayable on demand and, as such, for these payables there is
minimal difference between contractual cash flows related to the
financial liabilities and their carrying amount. For non-current
payables, liabilities are recognised at discounted fair value using
the effective interest rate, with the unwind either expensed as
finance cost or capitalised against the relevant asset. Other
payables include a balance of USD73.7 million (2019: USD73.7
million) recognised at its discounted fair value using the
effective interest rate, which has been added to the book value of
Bina Bawi intangible asset. The nominal value of this balance is
USD145.0 million and its payment is contingent on gas production at
the Bina Bawi and Miran assets meeting a certain volume threshold.
The unwind of the discount is capitalised against the relevant
intangible assets. Additionally, other payables include contingent
consideration relating to the acquisition of the Sarta asset. It
has been recognised at its discounted fair value using the
effective interest rate, which has been added to the book value of
the Sarta asset. Lease liabilities are included in other payables,
further explanation is provided in note 19. 13. Deferred income
2020 2019
USDm USDm
Non-current 19.7 26.7
Current 7.5 5.0
27.2 31.7
14. Provisions
2020 2019
USDm USDm
Balance at 1 January 37.4 32.9
Interest unwind 1.5 1.3
Additions 7.0 3.2
Balance at 31 December 45.9 37.4
Provisions cover expected decommissioning and abandonment costs
arising from the Company's assets. The decommissioning and
abandonment provision are based on the Company's best estimate of
the expenditure required to settle the present obligation at the
end of the period inflated at 2% (2019: 2%) and discounted at 4%
(2019: 4%). The cash flows relating to the decommissioning and
abandonment provisions are expected to occur between 2028 and
2038.
15. Interest bearing loans and net cash
Purchase of own
1 Jan Discount Buyback / bonds Net other 31 Dec
2020 unwind Issuance changes 2020
USDm USDm USDm USDm USDm USDm
2022 Bond 10.0% (current) (297.9) (0.5) 221.7 - (3.9) (80.6)
2025 Bond 9.25% - (0.3) (286.8) - - (287.1)
(non-current)
Own bonds held - - - 19.4 - 19.4
(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 USD300 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 USD222.9 million of its existing USD300.0
million senior unsecured bond issue with maturity date in December
2022 at a price of 107. On 22 December 2020, the Company wrote to
the Trustees confirming that they were exercising the right to call
the remaining USD77.1 million of the 2022 bond at the call price of
105. This settlement completed on 8 January 2021.
At 31 December 2020, the fair value of the nominal USD77.1
million of 2022 bonds is USD81.0 million and of the nominal
USD280.0 million of 2025 bonds held by third parties is USD291.0
million (2019: USD316.5 million).
Net change
1 Jan 2019 Discount unwind 31 Dec 2019
in cash
USDm USDm USDm USDm
2022 Bond 10.0% (297.3) (0.6) - (297.9)
Cash 334.3 - 56.4 390.7
Net Cash 37.0 (0.6) 83.8 92.8 16. Financial Risk Management
Credit risk
Credit risk arises from cash and cash equivalents, trade and
other receivables and other assets. The carrying amount of
financial assets represents the maximum credit exposure. The
maximum credit exposure to credit risk at 31 December was:
2020 2019
USDm USDm
Trade and other receivables 98.3 155.3
Cash and cash equivalents 354.5 390.7
452.8 546.0
All trade receivables are owed by the KRG. Cash is deposited
with the US treasury or term deposits with banks that are assessed
as appropriate based on, among other things, sovereign risk, CDS
pricing and credit rating.
Liquidity risk
The Company is committed to ensuring it has sufficient liquidity
to meet its payables as they fall due. At 31 December 2020 the
Company had cash and cash equivalents of USD273.5 million (2019:
USD390.7 million) adjusted for settlement of bond debt post-year
end.
Oil price risk
The Company's revenues are calculated from Dated Brent oil
price, and a USD5/bbl change in average Dated Brent would result in
a (loss) / profit before tax change of circa USD15 million.
Sensitivity of the carrying value of its assets to oil price risk
is provided in notes 8 and 9.
Currency risk
Other than head office costs, substantially all of the Company's
transactions are denominated and/or reported in US dollars. The
exposure to currency risk is therefore immaterial and accordingly
no sensitivity analysis has been presented.
Interest rate risk
The Company reported borrowings of USD348.3 million (2019:
USD297.9 million) in the form of a bond maturing in December 2022,
with fixed coupon interest payable of 10% on the nominal value of
USD77.1 million and a bond maturing in October 2025, with fixed
coupon interest payable of 9.25% on the nominal value of USD280.0
million. Although interest is fixed on existing debts, whenever the
Company wishes to borrow new debt or refinance existing debt, it
will be exposed to interest rate risk. A 1% increase in interest
rate payable on a balance similar to the existing debts of the
Company would result in an additional cost of circa USD3 million
per annum.
Capital management
The Company manages its capital to ensure that it remains
sufficiently funded to support its business strategy and maximise
shareholder value. The Company's short-term funding needs are met
principally from the cash flows generated from its operations and
available cash of USD354.5 million (2019: USD390.7 million).
17. Share capital
Total
Ordinary Shares
At 1 January 2019 - fully paid1 280,248,198
At 31 December 2019, 1 January 2020 and 31 December 2020 - fully paid1 280,248,198
1 Ordinary shares include 2,577,720 (2019: 2,577,720) treasury
shares. Share capital includes 3,236,109 (2019: 4,303,249) of trust
shares.
There have been no changes to the authorised share capital since
it was determined to be 10,000,000,000 ordinary shares of GBP0.10
per share.
18. Dividends
2020 2019
USDm USDm
Ordinary shares
Final dividend of 10¢ per share 28.0 27.6
Interim dividend of 5¢ per share 13.5 13.2
Total dividends provided for or paid 41.5 40.8
Paid in cash 55.3 27.4
Movement in payable (13.2) 13.2
Foreign exchange (expense) / income on dividend paid (0.6) 0.2
Total dividends provided for or paid 41.5 40.8
19. Right-of-use assets / Lease liabilities
The Company's right-of-use assets are related to the Sarta early
production facility, office, car, warehouse leases and included
within property, plant and equipment. The Company has elected to
apply the exemptions for short-term and low-value leases.
Drill rig contracts are service contracts where contractors
provide the rig together with the services and the contracted
personnel on a day-rate basis for the purpose of drilling
exploration or development wells. The Company has no right of use
of the rigs. The aggregate payments under drilling contracts are
determined by the number of days required to drill each well and
are capitalised as exploration or development assets as
appropriate.
Right-of-use assets
USDm
Cost
At 1 January 2019 1.9
Additions 1.7
At 31 December 2019 and 1 January 2020 3.6
Additions 8.4
Disposals due to terminations (0.3)
At 31 December 2020 11.7
Accumulated depreciation
At 1 January 2019 -
Depreciation charge for the period (0.9)
At 31 December 2019 and 1 January 2020 (0.9)
Depreciation charge for the period (1.3)
At 31 December 2020 (2.2)
Net book value
At 31 December 2019 2.7
At 31 December 2020 9.5
2020 2019
Book value USDm USDm
Office 2.4 2.6
Warehouse - 0.1
Production facility 7.1 -
Right-of-use assets 9.5 2.7
Lease liabilities were measured at the present value of the
remaining lease payments, discounted using the lessee's incremental
borrowing rate and included within trade and other payables. The
weighted average lessee's incremental borrowing rate applied to the
lease liabilities except Sarta early production facility was 2.5%.
4% was applied for the facility. Right-of-use assets are
depreciated over the lifetime of the related lease contract. The
lease terms vary from one to five years.
2020 2019
USDm USDm
At 1 January (3.0) (1.9)
Additions (8.4) (1.7)
Disposals due to terminations 0.4 -
Payments of lease liabilities 1.3 0.6
Interest expense on lease liabilities (0.1) -
At 31 December (note 12) (9.8) (3.0)
Included within lease liabilities of USD9.8 million (2019:
USD3.0 million) are non-current lease liabilities of USD6.8 million
(2019: USD2.2 million). The identified leases have no significant
impact on the Company's financing, bond covenants or dividend
policy. The Company does not have any residual value guarantees.
Extension options are included in the lease liability when it,
based on the management's judgement, is reasonably certain that an
extension will be exercised. The contractual maturities of the
Company's lease liabilities are as follows:
Less than Between Between Carrying
Total contractual cash flow
1 year 1 -2 years 2 - 5 years Amount
USDm USDm USDm
USDm USDm
31 December 2019 (1.0) (0.8) (1.4) (3.2) (3.0)
31 December 2020 (3.3) (3.4) (4.0) (10.7) (9.8)
20. Share based payments
The Company has three share-based payment plans: a performance
share plan, restricted share plan and a share option plan. The main
features of these share plans are set out below.
Key features PSP RSP SOP
Restricted shares.
Performance shares. The intention is to deliver Market value options.
Form of The intention is to deliver the full value of shares Exercise price is set equal
awards the full value of vested shares at no at no cost to the to the average share price
cost to the participant (e.g. as participant (e.g. as over a period of up to 30
conditional shares or nil-cost options). conditional shares days to grant.
or nil-cost options).
Performance conditions will apply. Awards Performance conditions may Performance conditions may
Performance granted from 2017 are based on relative or may not apply. For awards or may not apply. For awards
conditions and absolute TSR measured against a group granted to date, there are granted to date, there are
of industry peers over a three year no performance conditions. no performance conditions.
period.
Awards will vest when the Remuneration Awards typically vest after
Vesting Committee determine whether the Awards typically vest over three years. Options are
period performance conditions three years. exercisable until the 10th
have been met at the end anniversary of the grant
of the performance period. date.
Provision of additional cash/shares to Provision of additional cash Provision of additional cash
Dividend reflect dividends over the vesting period /shares to reflect dividends /shares to reflect dividends
equivalents may or may not apply. over the vesting period may over the vesting period may
or may not apply. or may not apply.
In 2020, awards were made under the performance share plan and
restricted share plan, no awards were made under the share option
plan, the numbers of outstanding shares under the PSP, RSP and SOP
as at 31 December 2020 are set out below:
SOP
PSP RSP Share option plan
weighted avg. exercise price
(nil cost) (nil cost)
Outstanding at 1 January 2019 10,148,551 1,511,298 132,334 803p
Granted during the year 1,930,702 850,408 - -
Dividend equivalents 592,675 84,657 - -
Forfeited during the year (2,439,495) - - -
Lapsed during the year (241,580) (18,251) (12,746) 742p
Exercised during the year - (704,568) - -
Outstanding at 31 Dec 2019 and 1 Jan 2020 9,990,853 1,723,544 119,588 810p
Granted during the year 4,041,711 598,039 - -
Dividend equivalents 641,685 120,450 - -
Forfeited during the year (1,569,870) - - -
Lapsed during the year (279,283) (2,194) (31,764) 788p
Exercised during the year (2,778,121) (280,347) - -
Outstanding at 31 December 2020 10,046,975 2,159,492 87,824 817p
The range of exercise prices for share options outstanding at
the end of the period is 742.00p to 1,046.00p.
Fair value of awards granted during the year has been measured
by use of the Monte-Carlo pricing model. The model takes into
account assumptions regarding expected volatility, expected
dividends and expected time to exercise. Expected volatility was
also analysed with the historical volatility of FTSE-listed oil and
gas producers over the three years prior to the date of grant. The
expected dividend assumption was set at 0%. The risk-free interest
rate incorporated into the model is based on the term structure of
UK Government zero coupon bonds. The inputs into the fair value
calculation for RSP and PSP awards granted in 2020 and fair values
per share using the model were as follows:
RSP PSP
22/06/2020 22/06/2020
Share price at grant date 119p 119p
Exercise price - -
Fair value on measurement date 119p 107p
Expected life (years) 1-3 3-6
Expected dividends - -
Risk-free interest rate 0.04% 0.04%
Expected volatility 64.50% 64.50%
Share price at balance sheet date 144p 144p
Change in share price between grant date and 31 December 2020 21% 21%
The weighted average fair value for RSP awards granted in 2020
is 119p and for PSP awards granted in 2020 is 107p.
The inputs into the fair value calculation for RSP and PSP
awards granted in 2019 and fair values per share using the model
were as follows:
RSP RSP PSP PSP
7/5/19 21/8/19 7/5/19 21/8/19
Share price at grant date 211p 183p 211p 183p
Exercise price - - - -
Fair value on measurement date 211p 183p 130p 109p
Expected life (years) 1-3 1-3 3-6 3-6
Expected dividends - - - -
Risk-free interest rate 0.83% 0.42% 0.83% 0.42%
Expected volatility 57.37% 55.26% 57.37% 55.26%
Share price at balance sheet date 189p 189p 189p 189p
Change in share price between grant date and 31 December 2019 (10%) 3% (10%) 3%
The weighted average fair value for PSP awards granted 2019 is
129p and for RSP awards granted in 2019 is 206p.
Total share-based payment charge for the year was USD5.8 million
(2019: USD5.8 million).
21. 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.
22. Related parties
The directors have identified related parties of the Company
under IAS 24 as being: the shareholders; members of the Board; and
members of the executive committee, together with the families and
companies, associates, investments and associates controlled by or
affiliated with each of them. The compensation of key management
personnel including the directors of the Company is as follows:
2020 2019
USDm USDm
Board remuneration 1.0 0.7
Key management emoluments and short-term benefits 7.6 5.6
Share-related awards 2.5 0.6
11.1 6.9
There have been no changes in related parties since last year
and no related party transactions that had a material effect on
financial position or performance in the year. There are not
significant seasonal or cyclical variations in the Company's total
revenues.
23. Events occurring after the reporting period
None.
24. Subsidiaries and joint arrangements
The Company has four joint arrangements in relation to its
producing assets Taq Taq, Tawke, Sarta and pre-production asset
Qara Dagh. The Company holds 44% working interest in Taq Taq PSC
and owns 55% of Taq Taq Operating Company Limited. The Company
holds 25% working interest in Tawke PSC which is operated by DNO
ASA. The Company holds 30% working interest in Sarta PSC which is
operated by Chevron. The Company holds 40% working interest in Qara
Dagh PSC which is operated by the Company.
For the period ended 31 December 2020 the principal subsidiaries
of the Company were the following:
Entity name Country of Incorporation Ownership % (ordinary shares)
Barrus Petroleum Cote D'Ivoire Sarl1 Cote d'Ivoire 100
Barrus Petroleum Limited2 Isle of Man 100
Genel Energy Africa Exploration Limited3 UK 100
Genel Energy Finance 2 Limited4 Jersey 100
Genel Energy Finance 4 plc3 UK 100
Genel Energy Finance plc (in liquidation)5 UK 100
Genel Energy Gas Company Limited4 Jersey 100
Genel Energy Holding Company Limited4 Jersey 100
Genel Energy International Limited6 Anguilla 100
Genel Energy Miran Bina Bawi Limited3 UK 100
Genel Energy Morocco Limited3 UK 100
Genel Energy No. 6 Limited3 UK 100
Genel Energy Petroleum Services Limited3 UK 100
Genel Energy Qara Dagh Limited3 UK 100
Genel Energy Sarta Limited3 UK 100
Genel Energy Somaliland Limited3 UK 100
Genel Energy UK Services Limited3 UK 100
Genel Energy Y?netim Hizmetleri A.S.7 Turkey 100
Taq Taq Drilling Company Limited8 BVI 55
Taq Taq Operating Company Limited9 BVI 55
1 Registered office is 7 Boulevard Latrille Cocody, 25 B.P. 945
Abidjan 25, Cote d'Ivoire
2 Registered office is 6 Hope Street, Castletown, IM9 1AS, Isle
of Man
3 Registered office is Fifth Floor, 36 Broadway, Victoria,
London, SW1H 0BH, United Kingdom
4 Registered office is 12 Castle Street, St Helier, JE2 3RT,
Jersey
5 Registered office is 3 Field Court, London, WC1R 5EF
6 Registered office is PO Box 1338, Maico Building, The Valley,
Anguilla
7 Registered office is Sehit Omer Haluk Sipahioglu Sokak (Eski
Noktali Sokak) No:1 Sheraton Lugal Ofisleri Daire: 21 Kavaklidere
06700, Ankara, Turkey
8 Registered office is PO Box 146, Road Town, Tortola, British
Virgin Islands
9 Registered office is 3rd Floor, Geneva Place, Waterfront
Drive, PO Box 3175, Road Town, Tortola, Virgin Islands, British
25. Annual report
Copies of the 2020 annual report will be despatched to
shareholders in April 2021 and will also be available from the
Company's registered office at 12 Castle Street, St Helier, Jersey
JE2 3RT and at the Company's website - www.genelenergy.com.
26. Statutory financial statements
The financial information for the year ended 31 December 2020
contained in this preliminary announcement has been audited and was
approved by the board on 17 March 2021. The financial information
in this statement does not constitute the Company's statutory
financial statements for the years ended 31 December 2020 or 2019.
The financial information for 2020 and 2019 is derived from the
statutory financial statements for 2019, which have been delivered
to the Registrar of Companies, and 2020, which will be delivered to
the Registrar of Companies and issued to shareholders in April
2021. The auditors have reported on the 2020 and 2019 financial
statements; their report was unqualified and did not include a
reference to any matters to which the auditors drew attention by
way of emphasis without qualifying their report. The statutory
financial statements for 2020 are prepared in accordance with
International Financial Reporting Standards (IFRS) as adopted for
use in the European Union. The accounting policies (that comply
with IFRS) used by Genel Energy plc are consistent with those set
out in the 2019 annual report.
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ISIN: JE00B55Q3P39, NO0010894330
Category Code: FR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 95778
EQS News ID: 1176494
End of Announcement EQS News Service
=------------------------------------------------------------------------------------
(END) Dow Jones Newswires
March 18, 2021 03:01 ET (07:01 GMT)
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