DJ Genel Energy PLC: Full-Year Results
Genel Energy PLC (GENL)
Genel Energy PLC: Full-Year Results
19-March-2020 / 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.
19 March 2020
Genel Energy plc
Audited results for the year ended 31 December 2019
Genel Energy plc ('Genel' or 'the Company') announces its audited results
for the year ended 31 December 2019.
Bill Higgs, Chief Executive of Genel, said:
"The industry is currently facing headwinds that challenge companies to
demonstrate their resilience and flexibility. Genel has a business model and
strategy designed to shelter us from such extreme circumstances, with
low-cost oil production, robust finances, and flexibility in our expenditure
allowing us to pay a material dividend while retaining sufficient liquidity
to capitalise on opportunities and take advantage of future upside. Our
strong balance sheet with limited capital commitments allows us to invest in
the most value accretive areas and pay this dividend at the prevailing oil
price, even in a scenario with a temporary delay in payments from the KRG.
We are a business that can generate excess cash at a sustained oil price of
$40/bbl.
Given the resilience of the business, our strong performance in 2019, and
our view of future prospects, we have retained our dividend of 10¢ per
share, deferring an increase until external conditions improve. This is a
yield of over 20% on our current share price, offering investors the
compelling combination of a significant yield from a sustainable dividend
and funded growth. Our portfolio positions us well for a future of fewer and
better natural resources projects. It is low-cost and low-carbon - the right
assets, in the right location, with the right footprint."
Results summary ($ million unless stated)
2019 2018
Production (bopd, working interest) 36,250 33,700
Revenue 377.2 355.1
EBITDAX1 321.8 304.1
Depreciation and amortisation (158.5) (136.2)
Exploration (expense) / credit (1.2) 1.5
Impairment of oil and gas assets (29.8) (424.0)
Operating profit / (loss) 132.3 (254.6)
Underlying profit2 134.9 138.9
Cash flow from operating activities 272.9 299.2
Capital expenditure 158.1 95.5
Free cash flow3 99.0 172.7
Dividends declared 40.8 -
Cash4 390.7 334.3
Cash after dividend5 377.1 334.3
Total debt 300.0 300.0
Net cash6 92.8 37.0
Dividend (declared and proposed) per share (¢ 15.0 -
per share)
Basic EPS (¢ per share) 37.8 (101.6)
Underlying EPS (¢ per share)2 49.0 49.8
1) EBITDAX is operating profit / (loss) adjusted for the add back of
depreciation and amortisation ($158.5 million), exploration expense ($1.2
million) and impairment of property, plant and equipment ($29.8 million).
2) Underlying profit is reconciled on page 13
3) Free cash flow is reconciled on page 14
4) Cash reported at 31 December 2019 excludes $3.0 million of restricted
cash
5) Cash reported at 31 December 2019 less interim dividend paid ($13.6
million) on 8 January 2020
6) Reported cash less IFRS debt
Highlights
· Ongoing strategic delivery from a strong financial platform, as highly
cash-generative oil production increased to 36,250 bopd, up 8%
year-on-year
· Free cash flow ('FCF') of $99 million in 2019, pre dividend payment
· This increases to $153 million (2018: $173 million), or $0.55 per
share, taking into account the receipt of $54 million in payments from
the Kurdistan Regional Government, due in 2019 and subsequently received
in January 2020
· Maiden dividend declared and $41 million distributed to shareholders
· Cash of $391 million at 31 December 2019 ($334 million at 31 December
2018)
· Net cash of $93 million at 31 December 2019 (net cash of $37 million at
31 December 2018)
· Production cost of $2.9/bbl in 2019
· Continued focus on safety: zero lost time incidents and zero losses of
primary containment in 2019
Outlook
· Genel is resilient to an oil price of $30/bbl, as low-cost production, a
flexible capital structure, and robust balance sheet allows the payment of
a material dividend, and the retention of a material net cash position at
year-end 2020
· Genel has significant capital allocation flexibility with limited
commitments, is committed to retaining a strong balance sheet, and will
ensure expenditure matches the external environment
· Capital expenditure can be reduced to as little as $60 million in
2020, with an expectation that it will be around $100 million at the
prevailing oil price, covering maintenance expenditure across our
producing licences and investment at Sarta
· Genel will sanction activity relating to the expenditure covered in
the original $160 million to $200 million guidance range, as and when
the external environment improves
· COVID-19 is impacting the ease of operating in the Kurdistan Region of
Iraq. Our producing operations are currently continuing with a reduced
staff, but further activity is under review
· Given the current market conditions, coupled with the delay in
payments from the KRG, drilling activity at the Tawke PSC has been
scaled back
· Due to the delayed expenditure, 2020 net production guidance of close
to Q4 2019 levels of 35,410 bopd is expected to be impacted, with the
reduced producing asset work programme increasing cash flow generation
in 2020 at the prevailing oil price, although a lower exit rate
production will impact 2021
· The Qara Dagh-2 well, which was set to spud in Q2 2020, is now likely
to be delayed
· Payments for production in October and November 2019, due in January and
February 2020, have not been received. The KRG continues to state the
importance of ongoing payments to oil companies, and we expect the
government to deliver on this promise
· Operating cash costs per barrel expected to be $3/bbl, amongst the
lowest in the industry, fitting into a world of fewer and better natural
resources projects
· Genel is yet to receive draft legal documents reflecting the commercial
understanding reached on Bina Bawi in September 2019, despite promises
from the KRG
· Emissions at Tawke and Taq Taq will reduce to 7kg CO2/bbl following
completion of the enhanced oil recovery project at Tawke PSC in H1 2020
· Given the resilience of the business and our strong performance in 2019,
the Board is accordingly recommending a final dividend of 10¢ per share
(2019: 10¢ per share), a distribution of c.$27.8 million, with a view to
increasing the 2020 interim distribution should market conditions improve
· Genel will seek to take advantage of opportunities to repurchase bonds
at a value-accretive price
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 1000 GMT,
with an associated webcast available on the Company's website,
www.genelenergy.com [1].
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 report, and my
first as Chairman.
The recent oil price fall, and the as yet unquantifiable impact of the
COVID-19 virus, provide significant headwinds, but I am confident that we
have the right mix of low-cost assets, flexible expenditure, and financial
strength to help us navigate challenges and thrive as the environment
improves.
Viewed externally, it was clear to me that Genel has a strong portfolio with
an attractive mix of assets at complementary stages of their life cycle.
High-margin producing fields provide the capital to rapidly develop assets
with material potential, which in turn will generate more cash to be quickly
recycled into the next phase of growth. It is a rare opportunity to join a
company with such a balanced and advantageous portfolio that is able to
generate cashflow that creates its own suite of opportunities. It is a
testament to my predecessor, Stephen Whyte, that the business is in such
good shape, and I would like to thank him on behalf of the Company for his
hard work in helping transform Genel's prospects.
Having now had the chance to get to know the people at Genel, I have been
impressed by the first-class management team, and I have no doubt about the
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ambition and the growth potential of the business. The quality of assets and people provide a compelling mix, we are a full cycle oil and gas company with expertise across the value chain above and beyond what you would typically see at a similar sized business, and I look forward to working with management as the Board seeks to oversee a period of significant growth, and the creation of material value for shareholders. Clear strategy Our focus is firmly on ensuring our ongoing resilience, enhancing cash flows, and creating optionality. Growing high-margin production, investing in growth, and returning cash to shareholders through a material and progressive dividend is a simple and appealing strategy, with the goal of creating long-term shareholder value. Genel delivered on this strategy in 2019, with almost $100 million of free cash flow generated, even while boosting investment in new growth assets. The Company paid its first dividend in the year, and we hope to grow the total distribution in 2020. We continue to focus on delivery, and Sarta is set to enter production in the coming months, further diversifying our producing asset base. Investment in growth assets is set to continue. Qara Dagh offers exciting potential, and we look forward to drilling the QD-2 well as soon as the situation with COVID-19 improves. With success and a positive operating environment, our organic portfolio has the potential to double our oil production in the coming years, and we also continue to seek cash-generative growth through acquisitions. Given the potential in our existing portfolio though, we are not compelled to make acquisitions, and will only do so should we find an opportunity that fulfils our strict criteria. Overseeing growth Genel has a strong and experienced Board, with a deep understanding of the oil and gas business, and a highly detailed working knowledge of the Kurdistan Region of Iraq and surrounding areas that allows us the best possible opportunity to understand and mitigate risk. As you would expect, managing risk is a key focus for the Board. The first priority is of course the safety of our employees and contractors, and we will continue to support management as we strive to continue our excellent performance in this area. As well as safety, employee wellbeing is also important, as a content workforce is a motivated one. The recent introduction of the Genel values emphasises the importance we place not just on the work that we do, but on the way that we do it. A key issue that natural resources companies must address relates to our role in a world facing the threat posed by a changing climate. Reducing emissions across the industry through the reduction of flaring and increased efficiency is a must, while still providing the power to fuel rising living standards. Genel has an important role to play in the forthcoming energy transition and as well as being the right thing to do, positioning Genel appropriately will boost our attractiveness to potential employees and shareholders, and is something that the Board will increasingly focus on going forward. Sustainability As someone who has spent several decades working in the energy industry, it is obvious to me that we are in a period of significant and necessary change, and Genel can and should be at the forefront of that process. When I joined the oil and gas business forty years ago it was an exciting world technically, commercially, and politically. The industry has always been a leader of technological innovation, and the energy that it provides through the production of oil and gas remains vital in order to reduce energy poverty and drive global development - not least by increasing the living standards of people in the developing world. Given the forward-thinking nature of people in the business, and its history of rapid evolution and innovation with the highest regard to HSE standards, the industry is well placed to evolve and support the delivery of the world's power needs during the energy transition. Sustainability is certainly at the forefront of the minds of the management of Genel, and ESG metrics are now incorporated into the remuneration evaluations of senior management for 2020. We recognise our need to provide the world with high-margin, low-carbon barrels that fit into a world of fewer and more efficient natural resources projects, as we continue to build on our aim of creating shareholder value over the long-term as a socially responsible contributor to the global energy mix. CEO STATEMENT Delivering on our strategy Genel remains focused on delivery, in the firm belief that ongoing delivery of our strategy will see the Company grow and prosper, and in turn provide a compelling offering to investors that will deliver significant shareholder value. External factors are currently providing a very challenging backdrop, but we have a strategy fit for this environment, as we have long been focused on reducing costs, retaining a strong balance sheet, and maximising our flexibility to use this balance sheet in whichever ways can create most shareholder value. In 2019 we delivered on our promises. Production of 36,250 bopd represents a year-on-year increase of 8%, and once again was in line with our guidance. This production, coupled with our focus on cost and cash generation, delivered just under $100 million of free cash flow, even after a notable increase in investment that sets us up to deliver further growth going forward. The level of our cash generation also allowed us to initiate a material and sustainable dividend, a dividend that our resilience allows us to maintain at the same level at the prevailing oil price. Given the external conditions, we have deferred an increase in the dividend until our interim distribution, pending an improvement in the external environment. As well as this organic success, in Sarta and Qara Dagh we added high-quality assets with near-term cash flow. We are already the only multi-licence producer in the Kurdistan Region of Iraq, and production at Sarta will further diversify our producing base when it comes onstream this summer. Sarta has the potential to be one of the biggest fields in the KRI and is at exactly the stage in the asset life cycle that complements our existing portfolio. We now have a portfolio with mature and low-cost production, a field set to start producing that benefits from a large pool of past costs, and appraisal of another high-impact opportunity at Qara Dagh. Progress on Bina Bawi has been frustrating, as despite positive progress in discussions leading to an understanding on commercial terms being reached last year, we have not yet received drafts of the legal agreements that will allow us to progress the development of this asset. Genel has geared up for the increased activity ahead, adding strength in depth to our team in 2019. This has boosted internal capabilities in order to have the workforce in place to continue to deliver operational excellence, and this readiness to work to the very highest international standards positions us well to grow as the only multi-licence producing operator in the KRI. A business fit for a low oil price environment Genel's portfolio is advantageously positioned in a low oil price environment. Our cost of producing a barrel of oil in 2020 is expected to be around $3, which is amongst the lowest in the world. We have a net cash position of almost $100 million and flexibility on capital expenditure, allowing us to spend appropriately to the external environment and balance the maximisation of our cash flows with investment in growth. Of course, this investment in the KRI can only continue with confidence in regular payments, which the KRG understands. Should payments continue, despite the low oil price, given our cost base and financial firepower, there are opportunities out there that Genel is well positioned to capitalise on. As Genel grows, we will not lose sight of our focus on acting in the right way as a responsible natural resources company that is committed to ensuring that our actions have a wider benefit. We recently formalised the Genel values, and it is my firm belief that acting according to our values will create a virtuous circle, seeing us deliver our strategy and in turn value for our stakeholders. A business fit for the future An approach combining thorough risk assessment and management, best in class operational execution and a hard-wired awareness of our ESG responsibilities, is of paramount importance at a time when the world is facing unprecedented challenges in balancing the provision of energy where it is needed with a changing climate. As we transition to a future of fewer and more efficient natural resources projects there will be winners and losers in the energy sector. This provides an exciting opportunity to position Genel as a winner in meeting the challenges that mankind faces in relation to energy. Natural resources companies that have a role to play during the energy transition, those that will be seen as the winners, are the ones that can provide low-cost, low-carbon energy, in the right locations - jurisdictions where the economic development of their resources provides a clear and compelling benefit to the communities in which the resources are found and produced. Some regions also need the economic boost from power generation in order to fund basic development, and need the power itself to keep the lights on in hospitals and schools. People need energy, and we are proud to provide it in a socially responsible way. The onshore nature of our operations helps reduce our carbon footprint,
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something that we are focused on at each field we participate in. Following
the completion of the enhanced oil recovery project at the Tawke licence in
the first half of this year, for which currently flared gas at Peshkabir
will instead be reinjected to increase long-term recovery rates at Tawke,
CO2 equivalent emissions from our producing assets will fall to c.7
kilograms per barrel. While this figure will increase as Sarta enters
production, plans are already in place to mitigate and eventually eliminate
the routine flaring that will initially occur at this field as production
expands in the coming years.
We are also proud of the significant social impact that our operations have
had and continue to have in the KRI and the prosperity that has been created
through direct employment and the building of a wide-reaching supply chain.
Extensive social projects throughout the years, from the building of
infrastructure, libraries, and schools, to ongoing community work, including
the successful engagement of our local communities in our recycling
programme, has also had a direct impact and will be continued going forward.
Material organic growth potential
Genel has a low-cost and highly cash-generative oil business, with the
potential for material organic growth. The engine room of our cash
generation in 2020 remains our oil production, which generates asset level
free cash flow even at an oil price of $30/bbl. The bulk of our investment
this year is expected to again be on our producing assets, as the speed of
returns is compelling, and allows us to rapidly recycle capital into our
growth opportunities.
Sarta is the first cab off the rank in terms of new cash-generative
production, and the addition of production from the field is expected in the
summer of 2020. Our near-term focus is on delivering this production, but it
is hard not to get excited by the opportunity of converting over 250 MMbbls
of the gross 2C resources into reserves as we progress work on the field and
meet the contingent milestones. Given the production potential of the field,
our oil business has the possibility of doubling production in coming years.
Prior to the impact of COVID-19 being felt in the KRI, the drilling of the
Qara Dagh-2 well was on track to begin in Q2, and was set to appraise the
licence c.10 km north of the QD-1 well. This well, drilled by a previous
operator, flowed light oil despite being drilled in a sub-optimal way, and
without the benefit of the sub-surface work that has subsequently been done
by Chevron and ourselves. We look forward to drilling this well as soon as
practicable, as a positive well result that demonstrates commercial flow
rates would provide another growth vehicle for Genel, with production that
could be expedited, and once again funded from operational cash flow should
the oil price improve.
Such is the cash flow that our oil business is set to generate in the
long-term, providing payments are regular and the oil price improves, should
a commercial agreement on Bina Bawi be reached we would be able to fund the
upstream development in full and work on developing the gas project while
still retaining surplus cash to grow our dividend. Genel has sought to
progress to such an agreement in good faith and as quickly as possible.
Genel continues to wait to receive the promised draft legal agreements
reflecting the commercial understanding reached last year, which appear to
be delayed due to ongoing transition in the Ministry of Natural Resources
('MNR').
Outlook and catalysts
Our focus in 2020 is again on delivery, and providing catalysts for the
creation of shareholder value. We will continue to mitigate the headwinds
that we are facing, investing flexibly in the business in line with the
external environment, bringing Sarta to production on time, and hopefully
having the opportunity to spud Qara Dagh-2.
Given the breadth of opportunities available within the organic portfolio we
do not need to add assets through acquisition, but we would like to if the
right opportunities of sufficient standard arise - and this oil price may
offer opportunities for a company in our robust financial position. Genel is
aiming to add assets that boost our cash generation and opportunity set,
bringing in further catalysts for the creation of shareholder value as we
look to build a bigger and better company, fit for the future and a
compelling investment proposition.
Genel is well set to navigate a low oil price environment, and ready to
thrive as this environment improves. We are a low-cost business with the
right assets, in the right area, with the right footprint to be a natural
winner as headwinds recede, positioned to benefit all stakeholders, and our
shareholders specifically.
OPERATING REVIEW
Reserves and resources development
Genel's proven (1P) and proven plus probable (2P) net working interest
reserves totalled 69 MMbbls (31 December 2018: 99 MMbbls) and 124 MMbbls (31
December 2018: 155 MMbbls) respectively at the end of 2019.
The majority of this decline related to the Tawke field. The decline in
reserves does not impact short-term production expectations, with the
majority of the decline being later field life barrels.
Net contingent resources (2C) have more than doubled to 152 MMbbls,
following an external audit conducted by ERCE that estimated a mid-case
total recoverable oil resource at Sarta of 593 MMbbls, of which 264 MMbbls
is classified as 2C resource.
Remaining reserves Resources (MMboe)
(MMbbls)
Contingent Prospective
1P 2P 1C 2C Best
Gross Net Gross Net Gross Net Gross Net Gross Net
31 December 379 99 574 155 1,274 1,23 2,826 2,761 4,267 2,73
2018 0 1
Production (50) (13) (50) (13) - - - - - -
Acquisitions - - - - - - - - - 250
Extensions - - - - - - - - - -
and
discoveries
New - - - - - - - - - -
developments
Revision of (71) (17) (70) (18) 19 (58) (234) (447) 105 555
previous
estimates
31 December 258 69 455 124 1,294 1,17 2,592 2,313 4,372 3,53
2019 3 6
Production
Working interest production in 2019 was 36,250 bopd (2018: 33,690 bopd), in
line with guidance and an increase of 8% on the prior year. This increase
was driven by the performance of Peshkabir, where gross production doubled
to 55,190 bopd. In total, 19 new wells added to production in 2019, with
drilling split across the Tawke, Peshkabir and Taq Taq fields.
These new wells have continued to diversify our producing well stock, and
our production now comes from over 80 wells at three fields. The portfolio
will be yet more diverse and reliable for production and cash flow with the
addition of production at Sarta later this year. While average production in
2020 to date is 34,400 bopd, in line with guidance, the delayed expenditure
at Tawke means that 2020 net production guidance of close to Q4 2019 levels
of 35,410 bopd is expected to be impacted. The reduced producing asset work
programme, which could potentially save up to $50 million, will result in
increasing cash flow generation in 2020 at the prevailing oil price,
although lower exit rate production will impact 2021.
PRODUCING ASSETS
Tawke PSC (25% working interest)
Gross production on the Tawke PSC, operated by DNO, averaged 123,940 bopd,
of which Peshkabir contributed 55,190 bopd.
Peshkabir's impressive performance was driven by the successful addition of
production from all four wells completed in 2019. Ten wells are currently
producing at the Peshkabir field. At the Tawke field, the existing well
stock at the Tawke field produced in line with expectations. Further
development drilling activity helped to offset natural field decline in the
field, and 12 wells came onto production in 2019.
The Peshkabir-12 exploration well has been drilled and testing is ongoing,
and a further four firm, and two contingent, producing wells had been
scheduled for 2020. 13 firm and two contingent producers were planned to be
drilled at the Tawke field in 2020, 10 in the Cretaceous and others in the
Jeribe, as the Operator aimed to minimise decline rates. Given the fact that
staff movements and rotations have been impacted by border closings,
quarantines and other coronavirus travel restrictions, and the current delay
in payments from the KRG, this investment has been scaled back. Of the four
rigs at the Tawke site, one rig is set to be released following the
completion of T-69, while two other rigs are set to complete the current
wells at Peshkabir and Tawke and then remain on site, allowing for a prompt
resumption of activity once the external environment allows. One rig will
continue activity at Tawke, focused on workovers and well interventions.
Given the performance of the underlying well stock in 2019, this deferred
investment is expected to be cash flow positive in 2020, although the
increased decline will impact 2021.
The operator expects the Peshkabir-to-Tawke gas gathering and reinjection
project, designed to eliminate flaring at Peshkabir as much as practicable
while increasing oil recovery rates at Tawke, to be completed in April 2020.
Taq Taq (44% working interest, joint operator)
Production at Taq Taq was robust in the first half of 2019, averaging 13,150
bopd, as drilling on the flanks continued to be successful. The TT-32
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deviated well completed in January on the northern flank of the field, followed by the TT-20z well on the western flank, and both added production of over 2,000 bopd. These wells then saw a decline in production and were choked back to control water production. Following the testing of water from the TT-33 well, on the southern flank, production reduced in the second half of the year, and the overall average for 2019 was 11,960. The potential of the southern flank is under evaluation, and Genel has since refocused efforts on the northern flank of the field. The TT-19x well was successfully put on production in the second half of the year with a rate of 1,500 bopd, and has been on plateau for five months. The TT-34 horizontal well entered production in December at over 2,000 bopd, and field production has increased to average 12,300 bopd in 2020 to date. The latest well on the northern flank of the field, TT-35, spud on 6 January and drilling is ongoing. Further activity at Taq Taq is focused on maximising cash generation. Given the current oil price environment and capital efficiency of the asset, Taq Taq is not a current capital allocation priority, although this will be reassessed as external conditions improve. PRE-PRODUCTION ASSETS Sarta (30% working interest) Following completion of the farm-in in February 2019, the field partners have progressed the Phase 1A development towards first oil, which is on track for the summer of 2020. Civil construction work at the Sarta field is continuing on schedule, and is now 60% complete, with flowlines laid and buried and the oil storage tanks nearing completion. Following recompletion of the Sarta-2 well and commissioning of the facility, Sarta-2 and Sarta-3 will be placed on production, both of which flowed c.7,500 bopd on test. Phase 1A represents a low-cost pilot development of the Mus-Adaiyah reservoirs, designed to recover 2P gross reserves estimated by Genel at 34 MMbbls. Genel estimates gross resources at Sarta to be c.500 MMbbls. This potential has now been validated through an external audit conducted by ERCE, who have estimated a mid-case total recoverable oil resource of 593 MMbbls, of which 264 MMbbls is classified as 2C resource. 86 MMbbls of this 2C resource is assigned to the Mus-Adaiyah reservoir, giving a 2P/2C sum for the Mus-Adaiyah of 120 MMbbls. ERCE's summed prospective oil resource estimate across the four proven reservoir intervals at Sarta is 295 MMbbls. 133 MMbbls is assigned to the Butmah reservoir, directly underlying the Mus-Adaiyah and the same zone as the oil resource at Bina Bawi, of which it is geologically on trend. Taken as a whole, the Mus-Adaiyah-Butmah reservoirs at Sarta have a summed mid case total recoverable resource estimate of 253 MMbbls. Conversion of these resources into reserves is a key objective of the three well campaign scheduled for 2021, and part of the phase 1A pilot development, with appraisal focused on the resource hosted in Jurassic reservoirs a secondary objective for the 2021 wells. With first oil Sarta in sight, preparations are already underway for this campaign. Construction work on the new well pads is due to start in H2 2020 and the field partners are investigating a range of options to fast-track oil production from these wells should they be successful. Qara Dagh (40% working interest, operator) Genel acquired 40% equity in the Qara Dagh appraisal licence in February 2019, and became the operator through a carry arrangement, covering activity for the QD-2 well. 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. Civil construction works have made good progress in preparation for the upcoming drilling operations, and the well pad and camp have now been completed, and the QD-2 well was on track to spud in Q2. The well will test the crestal portion of the prospect which, based on a rigorous re-mapping exercise, has a mean prospective resource estimated by Genel at c.400 MMbbls. Genel estimates that the downdip segment tested by the QD-1 well defines a 2C resource of 47 MMbbls. The impact of COVID-19 on the operating environment in the KRI means that it is now increasingly likely that the spudding of the QD-2 well will be delayed. It is hoped that this impact will be short lived and the well, which will take around six months to complete, will be drilled as soon as the outlook allows. 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. Negotiations between Genel and the KRG regarding a staged gas and oil development at Bina Bawi resulted in an understanding on commercial terms being reached in September 2019. Genel continues to wait to receive the promised draft legal agreements reflecting this, and the development of Bina Bawi is now on hold until tangible progress is seen from the MNR. Under the existing PSCs for both Bina Bawi and Miran, effective from 30 April 2020 and 31 May 2020 respectively, the KRG has a right (not an obligation) to terminate the PSCs in the absence of new Gas Lifting Agreement(s) being in place. The KRG is required under the PSCs to give notice of its intention to terminate and there are various consequent provisions in the PSC that provide periods for remedy by Genel and/or delay to any purported termination by the KRG. African exploration Onshore Somaliland, a farm-out process relating to this highly prospective SL-10-B/13 block (Genel 100% working interest, operator) began in Q4 2019, with Stellar Energy Advisors appointed to run the process. A number of companies are assessing the opportunity, and Genel had been aiming to conclude the farm-out process in H1 2020. The subsurface potential of the acreage has been endorsed through the process to date, while the company continues to counsel prospective partners with respect to the operating and political landscape. Offshore Morocco (Genel 75% working interest, operator) the Company recently signed an agreement with ONHYM to extend the license period for the Sidi Moussa Block under a new title, the Lagzira Block. This will allow Genel to complete the processing and interpretation of the multi-azimuth broadband 3D seismic survey completed in late 2018 and conduct a farm-out process ahead of any future decision on whether to drill a well. The duration is for a minimum of 12 months with a further six month extension option. FINANCIAL REVIEW Overview The Company has delivered a third successive year of material cash generation, with $99 million of free cash flow representing over half of our current market capitalisation. We have successfully maintained our rigorous financial discipline - adding, derisking and developing assets using a low-cost, high capital flexibility model that mitigates financial risk, optimises cash generation and expedites capital return and payback. This discipline has positioned us well in the currently challenging environment. Genel entered 2020 with a cash-generative, resilient business; a strong balance sheet; and a fully funded and balanced oil portfolio with material organic growth opportunities that offer upside from all pre-production phases of an asset lifecycle. Even with the recent fall in the oil price, Genel remains well positioned, with low-cost assets and the vast majority of our capital expenditure being discretionary, allowing us to make prudent investment choices and ensure that our expenditure matches the external environment. 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 sustainable and material dividend, with $41 million distributed to shareholders. The financial strength of our business and the flexibility in our cost base has allowed us to reaffirm this dividend despite the current challenging macro conditions, and we remain commit growing this dividend as the headwinds in the market recede. Sustainable long-term dividend yield stock, with the value upside of a growth stock The combination of a resilient business and a fully funded development portfolio offering material growth and cash generation replacement provides investors with a compelling proposition: the robust long-term dividend, currently yielding over 20%, and associated management discipline of a yield stock with the value upside of a growth company. We will continue to maintain our discipline, balance and yield focus in our assessment of capital allocation to growth, both within our own portfolio and in relation to assets that we may look to acquire. We retain the flexibility to control our pace of investment to permit allocation of capital to where it can be put to work most effectively at the time. Resilient business with fast payback Our business model is robust to challenges the sector may face in the future, where only the better projects will attract investment. The current market conditions provide an earlier test, and our business is ready for it. We focus on high-margin, low-cost projects with high capital velocity and rapid payback. In 2019, our production generated revenue of $29/bbl, with operating costs under $3/bbl. Our development assets that we will bring onto
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DJ Genel Energy PLC: Full-Year Results -5-
production have commercial terms and physical credentials that deliver
attractive economics and returns and we look for new assets that will
successfully compete with these assets for capital. This makes our business
exceptionally resilient to a downside oil price, with a corporate breakeven
in 2020 of $30/bbl, after dividend.
Growth funded from existing cash flows, cash available
In 2020, under appropriate external conditions, we expected capital
expenditure on producing assets to be flat and planned for capital
investment in growth to double to circa $80 million, bringing Sarta onto
production and drilling a high-impact exploration/appraisal well at Qara
Dagh. To illustrate the resilience of our cash flows, if $30/bbl extends for
the remainder of the year and we executed this investment plan unchanged,
the Company would end the year with a material net cash position after
dividend, provided consistent payments from the KRG. The current conditions
impact our pace of investment, but they do not change our preference for
these assets - they were identified because they fit into our resilient
business model that. This model and our financial strength position the
Company well to execute opportunistic asset acquisitions when other
companies are more distressed.
FY2019 financial objectives
The table below summarises our progress against the 2019 financial
priorities of the Company:
FY2019 financial priorities Progress
· Continued focus on capital · Capital expenditure was
allocation, with principally focused on
prioritisation of highest Peshkabir and Tawke, providing
value investment in assets rapid payback and thereafter
with ongoing or near-term liquidity, and providing
cash and value generation incremental production beyond
the financial year of the
spend
· Investment in lower risk · Progression towards Sarta
development opportunities first oil and Qara Dagh
with high potential appraisal well, submission of
FDP for Bina Bawi
· Continued focus on · The Company has performed
acquiring assets with the detailed analysis on a similar
potential to add significant number of external
value to the Company through opportunities as 2018, which
near to mid-term cash culminated in farm-ins to
generation Sarta and Qara Dagh, with a
watch list of preferred
targets and a cycle of adding
at least one new opportunity
per month
· Continued focus on the · Dividends of $41 million
capital structure of the (10¢ FY18 final and 5¢ FY19
Company, committing to interim) were declared in the
distributing a minimum of year, with a FY19 final
$40 million in dividends dividend retained at 10¢ per
each year share. The Company remains
committed to increasing the
dividend
Free cash flow and cash
The material cash generation of the three core producing fields continued in
2019. Investment increased production and cash generation at Peshkabir
year-on-year, resulting in a Company surplus before growth capital
expenditure and dividend of $183 million, which is flat year-on-year when
adjusted for constant Brent oil price. Management is focused on growing
surplus before growth capital expenditure and dividend.
FY2019 FY2018
(all figures $ million unless stated) Actual Constant Actual
Brent average oil price $64/bbl $64/bbl $71/bbl
Revenue 377.2 332.8 355.1
Opex (37.7) (28.7) (28.7)
G&A (excl. depreciation and (17.7) (22.3) (22.3)
amortisation)
EBITDAX 321.8 281.8 304.1
Maintenance capex (115.1) (70.4) (70.4)
Net cash interest (23.4) (25.6) (25.6)
Surplus before growth capex and 183.3 185.8 208.1
dividend
Development capex (22.1) - -
Exploration and appraisal capex (20.9) (25.1) (25.1)
Surplus 140.3 160.7 183.0
Working capital and other (41.3) (10.3) (10.3)
Free cash flow 99.0 150.4 172.7
Cash due in 2019 received post 54.1 - -
year-end
After investment in growth the Company generated $99 million of free cash
flow (increasing to $153 million if adjusted for payments due in 2019 that
were received in January). The 11% reduction from 2018 free cash flow of
$173 million to $153 million is a result of the average Brent oil price
being $7/bbl lower compared to the prior year and increased investment,
primarily at Peshkabir.
At year-end, the Company reported cash of $391 million. The strong balance
sheet and confidence in the outlook for expansion of our producing asset
portfolio supported the payment of a maiden dividend in 2019, with $41
million of dividends declared in year, equating to 15¢ per share - a
dividend yield of around 6% based on average share price in H2 2019. The
continuation of this robust position, and the durability of our cash flows,
now support the continuation of this dividend, and accordingly a dividend of
10¢ per share has today been announced.
Cash at the end of 2019 increased to $93 million, illustrating the firepower
that the Company has available for investment.
Flexible growth capital investment
As the Company has delivered free cash generation for the past three years,
it has also assembled an attractive and high potential portfolio whilst
retaining the flexibility to control the pace of investment to react to the
prevailing investment conditions and external environment.
Sarta and Qara Dagh were acquired in a combination deal; Sarta has large
scale 2C oil resources and Qara Dagh represents high unrisked resource
potential at an earlier stage in the cycle. We are working to unlock value
from both through sanctioned drilling activity and in 2019, the Company
invested $28 million, with both assets progressing in line with expectation
through the year. At time of writing, Sarta is on track for first oil from
Sarta in summer 2020. The appraisal well at Qara Dagh was set to spud in Q2
2020, but is now expected to be delayed due to COVID-19
Bina Bawi has a large scale 2C gas resource with additional 2C oil
resources, and we are working to reach commercial agreements that support
investment in derisking and monetising the asset on a basis consistent with
our financial model.
Our growth plans remain dependent on ongoing payments from the KRG. The KRG
advised us that the delay in 2019 payments was caused by external factors
beyond the control of the KRG. We have been advised that delays in 2020 have
been caused by a reorganisation of the payment process within the KRG. The
KRG continues to state the importance of ongoing payments to the oil
companies that drive their economy, and we expect them to deliver on this
promise. We will ensure that our expenditure matches our confidence in the
receipt of ongoing payments, which in the past were sustained when the oil
price fell below $30/bbl - and this was a time when they were not receiving
money from Baghdad and their exports were considerably less than the nearly
half a million barrels a day at present.
Outlook and financial priorities for 2020
Our capital allocation philosophy remains the same, despite the recent fall
in oil price - invest in those projects with the potential to create most
shareholder value, targeting those assets that fit the criteria set out
previously. This applies both to allocation of capital to the existing
portfolio and also to assets or opportunities that we acquire. In 2020 we
will continue to invest in accordance with external conditions, striking the
right balance between investing and retaining sufficient liquidity to retain
our strong balance sheet and advantaged financial position that underpins
our business model and allows us to capitalise on opportunities. Optimising
production and developing Sarta, which has an ideal production profile to
benefit as the external situation evolves, are key priorities, and we are
committed to the dividend.
We will continue to be disciplined in our capital allocation and invest in
areas where we can deliver most value. Rigorous cost management is
maintained across all operations, while ensuring spend is sufficient to take
advantage of the growth opportunities in the portfolio, and to maximise (net
present) value of the portfolio.
For 2020 the financial priorities of the Company are the following:
· Maintaining our financial strength through existing market conditions
· Continued focus on capital allocation, with prioritisation of highest
value investment in assets with ongoing or near-term cash and value
generation
· Delivery of a 2020 work programme on time and on budget, that is
appropriate to the external environment
· Continued focus on identifying additional assets that offer potential
for significant value to the Company with near to mid-term cash
generation, primarily to further build the Company's cash generation
options when the override royalty agreement ends in Q3 2022 and provide
the basis for increasing the dividend in the future
A summary of the financial results for the year is provided below.
Financial results for the year
Income statement
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Working interest production of 36,250 bopd was increased compared to last
year (2018: 33,700 bopd), principally as a result of higher average
production from Peshkabir offsetting decline at the Tawke field.
Revenue increased from $355.1 million to $377.2 million. The year-on-year
increase was caused principally by increased cost oil and production,
despite the Brent oil price decreasing by $7/bbl.
Production costs of $37.7 million increased from last year (2018: $28.7
million) primarily as a result of high production contribution from
Peshkabir. Production cost per barrel increased from $2.3/bbl to $2.9/bbl,
mostly due to trucking costs in Peshkabir.
General and administration costs were $19.1 million (2018: $24.0 million),
of which cash costs were $14.1 million (2018: $17.4 million). The reduction
from the prior period is a result of higher capitalisation as capital
activity has increased, principally at Sarta and Qara Dagh.
The increase in revenue resulted in EBITDAX of $321.8 million (2018: $304.1
million):
(all figures $ million) FY 2019 FY 2018
Profit oil 117.2 147.1
Cost oil 147.2 97.8
Override royalty 112.8 110.2
Revenue 377.2 355.1
Operating costs (37.7) (28.7)
G&A (excl. depreciation) (17.7) (22.3)
EBITDAX 321.8 304.1
Depreciation and amortisation (158.5) (136.2)
Net interest (27.7) (28.8)
Income tax expense (0.7) (0.2)
Underlying profit 134.9 138.9
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. Underlying profit is presented in order to understand the
profitability of the recurring business, excluding the impact of items that
tend to be one off in nature, such as impairment and exploration
expenditure.
Depreciation of $88.8 million (2018: $72.4 million) and Tawke intangibles
amortisation of $68.3 million (2018: $62.1 million) increased year-on-year
as a result of a combination of an 8% increase in working interest
production and higher estimated future costs on the Tawke PSC
(depreciation/bbl: $6.1/bbl (2018: $5.2/bbl), noting that these costs are
fully recoverable.
An impairment expense of $29.8 million was recorded in relation to Tawke and
Taq Taq, which is explained further in note 1 (2018: $424.0 million relating
to Miran).
Bond interest expense of $30.0 million was in line with prior year. Finance
income of $6.6 million (2018: $4.4 million) was bank interest income. Other
finance expense of $4.3 million (2018: $3.2 million) included a 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 of $0.7 million (2018: $0.2 million) was related to
taxation of the service companies.
Capital expenditure
Capital expenditure is the aggregation of spend on production assets ($115.1
million) and pre-production assets ($43.0 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 $158.1 million, predominantly focused on production assets and
the Sarta PSC ($22.1 million):
(all figures $ million) FY 2019 FY 2018
Cost recovered production capex 115.1 70.4
Pre-production capex - oil 22.1 -
Pre-production capex - gas 11.9 12.0
Other exploration and appraisal capex 9.0 13.1
Capital expenditure 158.1 95.5
Cash flow, cash, net cash and debt
Gross proceeds received was $317.4 million (2018: $335.1 million), of which
$91.5 million (2018: $92.5 million) was received for the override royalty.
(all figures $ million) FY 2019 FY 2018
Brent average oil price $64/bbl $71/bbl
Operating cash flow 272.9 299.2
Producing asset cost recovered capex (105.1) (65.3)
Development capex (18.7) -
Exploration and appraisal capex (26.5) (39.7)
Restricted cash release 7.0 8.5
Interest and other (30.6) (30.0)
Free cash flow 99.0 172.7
Cash received post period end 54.1 -
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 flow before dividend was $99.0 million, with an overall increase in
cash of $56.4 million in the year (2018: $172.3 million).
(all figures $ million) FY 2019 FY 2018
Free cash flow 99.0 172.7
Dividend paid (incl. expenses) (29.0) -
Purchase of shares (13.5) -
Other (0.1) (0.4)
Net change in cash 56.4 172.3
Opening cash 334.3 162.0
Closing cash 390.7 334.3
Debt reported under IFRS (297.9) (297.3)
Net cash / (debt) 92.8 37.0
Closing cash of $390.7 million and net cash of $92.8 million (2018: $37.0
million) exclude restricted cash of $3.0 million (2018: $10.0 million). Net
cash is reported in order for users of the financial statements to
understand how much cash remains if the Company paid its debt obligations
from its available cash on the period end date.
Reported IFRS debt was $297.9 million (31 December 2018: $297.3 million),
comprised of $300 million of bond debt less amortised costs. The bond pays a
10.0% coupon and matures in December 2022. A reconciliation of debt and cash
is provided in note 15 to the financial statements.
The bond has three financial covenant maintenance tests:
Financial covenant Test YE 2019
Net debt / EBITDAX< 3.0 (0.3)
Equity ratio (Total equity/Total assets) > 40% 71%
Minimum liquidity > $30m $391m
Net assets
Net assets at 31 December 2019 were $1,386.1 million (2018: $1,331.4
million) and consist primarily of oil and gas assets of $1,412.5 million
(2018: $1,384.2 million), trade receivables of $150.2 million (2018: $94.8
million) and net cash of $92.8 million (2018: $37.0 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
Maiden dividend distribution of $27.4 million (2018: nil) paid to
shareholders in June 2019. An interim dividend of 5¢ per share was then paid
to shareholders in January 2020. Total dividends declared in 2019 were $40.8
million (2018: nil), representing 15¢ per share.
Given Genel's robust financial position and the positive outlook for the
Company, the Board is recommending no change in the final dividend of 10¢
per share (2019: 10¢ per share), a total distribution of c.$27.8 million.
The payment timetable is below:
· Annual General Meeting: 21 May 2020
· Ex-dividend date: 28 May 2020
· Record Date: 29 May 2020
· Payment Date: 29 June 2020
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 2019 and
consequently that the Company is considered a going concern.
Consolidated statement of comprehensive income
For the year ended 31 December 2019
Note 2019 2018
$m $m
Revenue 2 377.2 355.1
Production costs 3 (37.7) (28.7)
Depreciation and amortisation of oil assets 3 (157.1) (134.5)
Gross profit 182.4 191.9
Exploration (expense) / credit 3 (1.2) 1.5
Impairment of intangible assets 3-8 - (424.0)
Impairment of property, plant and equipment 3-9 (29.8) -
General and administrative costs 3 (19.1) (24.0)
Operating profit / (loss) 132.3 (254.6)
Operating profit / (loss) is comprised of:
EBITDAX 321.8 304.1
Depreciation and amortisation 3 (158.5) (136.2)
Exploration (expense) / credit 3 (1.2) 1.5
Impairment of intangible assets 3-8 - (424.0)
Impairment of property, plant and equipment 3-9 (29.8) -
Finance income 5 6.6 4.4
Bond interest expense 5 (30.0) (30.0)
Other finance expense 5 (4.3) (3.2)
Profit / (Loss) before income tax 104.6 (283.4)
Income tax expense 6 (0.7) (0.2)
Profit / (Loss) and total comprehensive 103.9 (283.6)
income / (expense)
Attributable to:
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Shareholders' equity 103.9 (283.6)
103.9 (283.6)
Profit / (Loss) per ordinary share ¢ ¢
Basic 7 37.8 (101.6)
Diluted 7 37.0 (101.6)
Underlying 49.0 49.8
Consolidated balance sheet
At 31 December 2019
Note 2019 2018
$m $m
Assets
Non-current assets
Intangible assets 8 775.6 818.4
Property, plant and equipment 9 636.9 565.8
1,412.5 1,384.2
Current assets
Trade and other receivables 10 157.4 99.4
Restricted cash 11 3.0 10.0
Cash and cash equivalents 11 390.7 334.3
551.1 443.7
Total assets 1,963.6 1,827.9
Liabilities
Non-current liabilities
Trade and other payables 12 (118.8) (76.8)
Deferred income 13 (26.7) (31.9)
Provisions 14 (37.4) (32.9)
Borrowings 15 (297.9) (297.3)
(480.8) (438.9)
Current liabilities
Trade and other payables 12 (91.7) (52.6)
Deferred income 13 (5.0) (5.0)
(96.7) (57.6)
Total liabilities (577.5) (496.5)
Net assets 1,386.1 1,331.4
Owners of the parent
Share capital 17 43.8 43.8
Share premium account 4,033.4 4,074.2
Accumulated losses (2,691.1) (2,786.6)
Total equity 1,386.1 1,331.4
Consolidated statement of changes in equity
For the year ended 31 December 2019
Note Share Share Accumulated Total equity
capital premium losses
$m
$m $m $m
At 1 January 43.8 4,074.2 (2,508.2) 1,609.8
2018
Loss and total - - (283.6) (283.6)
comprehensive
expense
Share-based - - 5.2 5.2
payments
At 31 December 43.8 4,074.2 (2,786.6) 1,331.4
2018 and 1
January 2019
Profit and - - 103.9 103.9
total
comprehensive
income
Share-based 20 - - 5.1 5.1
payments
Purchase of - - (8.2) (8.2)
shares to
satisfy share
awards
Purchase of - - (5.3) (5.3)
treasury
shares
Dividends 18 - (40.8) - (40.8)
provided for
or paid1
At 31 December 43.8 4,033.4 (2,691.1) 1,386.1
2019
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 2019
Note 2019 2018
$m $m
Cash flows from operating activities
Profit / (Loss) and total comprehensive 103.9 (283.6)
income / (expense)
Adjustments for:
Finance income 5 (6.6) (4.4)
Bond interest expense 5 30.0 30.0
Other finance expense 5 4.3 3.2
Taxation 6 0.7 0.2
Depreciation and amortisation 3 158.5 136.2
Exploration expense / (credit) 3 1.2 (1.5)
Impairment of intangible assets 3 - 424.0
Impairment of property, plant and equipment 3 29.8
Other non-cash items 3 (2.4) 4.9
Changes in working capital:
Increase in trade receivables (55.4) (21.5)
Increase in other receivables (0.2) (1.1)
Increase in trade and other payables 3.3 9.2
Cash generated from operations 267.1 295.6
Interest received 5 6.6 4.4
Taxation paid (0.8) (0.8)
Net cash generated from operating 272.9 299.2
activities
Cash flows from investing activities
Purchase of intangible assets (26.5) (39.7)
Purchase of property, plant and equipment (123.8) (65.3)
Movement in restricted cash 11 7.0 8.5
Net cash used in investing activities (143.3) (96.5)
Cash flows from financing activities
Dividends paid to company's shareholders, 18 (29.0) -
including expenses
Purchase of shares for employee share trust (8.2) -
Purchase of treasury shares (5.3) -
Lease payments 19 (0.6) -
Interest paid (30.0) (30.0)
Net cash used in financing activities (73.1) (30.0)
Net increase in cash and cash equivalents 56.5 172.7
Foreign exchange loss on cash and cash (0.1) (0.4)
equivalents
Cash and cash equivalents at 1 January 11 334.3 162.0
Cash and cash equivalents at 31 December 11 390.7 334.3
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 ($m)
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 21 and 23.
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.
Going concern
The Company regularly evaluates its financial position, cash flow forecasts
and its covenants by sensitising with a range of scenarios which incorporate
changes in oil prices, discount rates, production volumes as well as capital
and operational spend. 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 2019 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
Arrangements under which the Company has contractually agreed to share
control with another party, or parties, are joint ventures where the parties
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DJ Genel Energy PLC: Full-Year Results -8-
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 Apart from those involving estimations (which are dealt with separately below), there is no significant judgements that the directors have made in the process of applying the Company's accounting policies and that has the most significant effect on the amounts recognised in the financial statements. 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 has 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. Proven 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 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 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 nominal discount rate of 12.5% is used when assessing the impairment testing of the Company's oil assets. 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 CGUs, 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, which 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. Lack of progress could result in significant delays in value realisation and consequently a materially lower asset value. Under the existing PSCs for both Bina Bawi and Miran, effective from 30 April 2020 and 31 May 2020 respectively, the KRG has a right (not an obligation) to terminate the PSCs in the absence of new Gas Lifting Agreement(s) being in place. The KRG is required under the PSCs to give notice of its intention to terminate and there are various consequent provisions in the PSC that provide periods for remedy by Genel and/or delay to any purported termination by the KRG, which consequently would take some time. Change in accounting estimate - Tawke carrying value Management has assessed Tawke production and its updated oil price forecast as indicators of impairment. Management has performed its impairment assessment, with a reduction in oil price and production forecast resulting in an impairment of $21 million. Change in accounting estimate - Taq Taq carrying value Management has assessed Taq Taq production and its updated oil price forecast as indicators of impairment. Management has performed its impairment assessment, with a reduction in oil price and production forecast resulting in an impairment of $9 million. Change in accounting estimate - Tawke depreciation Management assessment of depreciation has resulted in an increase in depreciation rate per barrel, principally as a result of an increased estimate of future costs, which are cost recoverable and do not materially impact NPV as explained in the sensitivity to capital expenditure disclosure in note 9. This resulted in a depreciation expense that was $11 million
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DJ Genel Energy PLC: Full-Year Results -9-
higher compared to the expense based on prior depreciation rate per barrel.
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 2023 price then inflated at 2% per annum.
$/bbl 2020 2021 2022 2023
Forecast 65 67 68 72
Prior year forecast 66 68 71 72
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 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.
The trade receivable is recognised when the control of oil is transferred to
the customer at the metering point, as this is the time the consideration
becomes unconditional. The trade receivable reflects the Company's
entitlement based on the netback price and oil transferred.
Acquisitions of Sarta and Qara Dagh PSCs
On 28 February 2019 the Company completed the acquisition of a 30% interest
in the Sarta PSC, with an economic date of 1 January 2019. Shortly after
acquisition date, final investment decision ("FID") was taken on phase 1A
development, resulting in the recognition of gross 2P reserves at the asset
level of 34mmbbls, of which the Company's share was 10mmbbls. The interest
has been accounted for as an asset acquisition under IAS 16, with the result
being the recognition of a development asset, reflecting the acquired 2P
reserves. Consideration of $49.4 million (note 8 and 12) for the asset is a
combination of cost recoverable carry and a milestone success payment and
has been assessed based on the 2P reserves that have been recognised. On the
same date, the Company also completed the acquisition of a 40% interest in
the Qara Dagh PSC. Consideration on the asset is cost recoverable carry
arrangement on one well. Both assets are treated as Joint Operations under
IFRS 11.
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 2018, 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 oil sales. Revenue is earned based on the entitlement mechanism
under the terms of the relevant PSC; 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 from Taq Taq licence, 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. Capacity building
payments due on Tawke profit oil receipts were waived from August 2017
onwards as part of the RSA. ORRI is calculated as 4.5% of Tawke PSC field
revenue. Royalty income was received in advance and is recognised in line
with production.
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 typically due within 30 days
but under the normal operating cycle, payments are received on 75 days
average. 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 $/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
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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 excess of the purchase price of acquisitions over the net book value of assets acquired to be allocated 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 and Taq Taq PSCs, payment for entitlement is due within 30 days. Since February 2016, a track record of payments being received three months after invoicing has been established, and consequently three months has been assessed as the established operating cycle under IAS 1. 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 2019, which are expected to be collected in 2020 under the normal operating cycle, for ECLs. The model calculates net present value of outstanding receivables discounted by the discount rate, for a range of possible scenarios including short and mid-term delays and no payment with a probability assigned to each, and determines the ECL as the weighted average of these scenarios. The Company uses both past track record of receivables, information available until the reporting date and future expected performance. The result of the Company's assessment under IFRS is a $0.5 million adjustment. A financial asset is assessed at each reporting date to determine whether
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