Webdisclosure.com

Search

GENEL ENERGY (LON:GENL) Genel Energy PLC: Full-Year Results

Directive transparence : information réglementée

19/03/2020 08:00

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 (¢ per share)

15.0

-

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

Andrew Benbow, Head of Communications

+44 20 7659 5100

Vigo Communications

Patrick d'Ancona 

+44 20 7390 0230

 

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.

 

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 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, 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 (MMbbls)

Resources (MMboe)

 

Contingent

Prospective

1P

2P

1C

2C

Best

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

 

31 December 2018

379

99

574

155

1,274

1,230

2,826

2,761

4,267

2,731

 

Production

(50)

(13)

(50)

(13)

-

-

-

-

-

-

 

Acquisitions

-

-

-

-

-

-

-

-

-

250

 

Extensions and discoveries

-

-

-

-

-

-

-

-

-

-

 

New developments

-

-

-

-

-

-

-

-

-

-

 

Revision of previous estimates

(71)

(17)

(70)

(18)

19

(58)

(234)

(447)

105

555

 

31 December 2019

258

69

455

124

1,294

1,173

2,592

2,313

4,372

3,536

 
                       

 

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 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 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 allocation, with prioritisation of highest value investment in assets with ongoing or near-term cash and value generation
  • Capital expenditure was principally focused on Peshkabir and Tawke, providing rapid payback and thereafter liquidity, and providing incremental production beyond the financial year of the spend
  • Investment in lower risk development opportunities with high potential
  • Progression towards Sarta first oil and Qara Dagh appraisal well, submission of FDP for Bina Bawi
  • Continued focus on acquiring assets with the potential to add significant value to the Company through near to mid-term cash generation
  • The Company has performed detailed analysis on a similar number of external opportunities as 2018, which culminated in farm-ins to 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 capital structure of the Company, committing to distributing a minimum of $40 million in dividends each year
  • Dividends of $41 million (10¢ FY18 final and 5¢ FY19 interim) were declared in the year, with a FY19 final dividend retained at 10¢ per 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 amortisation)

(17.7)

(22.3)

(22.3)

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 dividend

183.3

185.8

208.1

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 year-end

54.1

-

-

 

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

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 income / (expense)

 

103.9

(283.6)

 

 

 

 

Attributable to:

 

 

 

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 capital

$m

Share premium

$m

Accumulated losses

$m

Total equity

$m

At 1 January 2018

 

43.8

4,074.2

(2,508.2)

1,609.8

 

 

 

 

 

 

Loss and total comprehensive expense

 

-

-

(283.6)

(283.6)

Share-based payments

 

-

-

5.2

5.2

 

 

 

 

 

 

At 31 December 2018 and 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

 

43.8

4,033.4

(2,691.1)

1,386.1

 

 

1 The Companies (Jersey) Law 1991 does not define the expression "dividend" but refers instead to "distributions". Distributions may be debited to any account or reserve of the Company (including share premium account).

 

 

 

 

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 income / (expense)

 

103.9

(283.6)

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 activities

 

272.9

299.2

 

 

 

 

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, including expenses

18

(29.0)

-

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 equivalents

 

(0.1)

(0.4)

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 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.

 

  1. 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 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 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 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.

 

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 a number of equity-settled, share-based compensation plans. The economic cost of awarding shares and share options to employees is recognised as an expense in the statement of comprehensive income equivalent to the fair value of the benefit awarded. The fair value is determined by reference to option pricing models, principally Monte Carlo and adjusted Black-Scholes models. The charge is recognised in the statement of comprehensive income over the vesting period of the award.

 

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 the profits of the Turkish and UK services 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 2019. Amendments to IFRS 9 - Prepayment Features with Negative Compensation, Amendments to IAS 28 - Long-term Interests in Associates and Joint Ventures, Amendments to IAS 19 - Plan Amendment, Curtailment or Settlement, IFRIC 23 - Uncertainty over Income Tax Treatments, Annual Improvements to IFRS Standards 2015-2017 Cycle. The adoption of these standards and amendments has had no impact on the Company's results or financial statement disclosures. IFRS 16 - Leases is effective on 1 January 2019 and the impact on the Company's financial statements is explained below.

 

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: Amendments to References to the Conceptual Framework in IFRS Standards (effective 1 Jan 2020), Amendment to IFRS 3 Business Combinations (effective 1 Jan 2020), Amendments to IAS 1 and IAS 8: Definition of Material (effective 1 Jan 2020), Amendments to IFRS 9, IAS 39 and IFRS 7 - Interest rate benchmark reform (effective 1 Jan 2020), IFRS 17 Insurance contracts (effective 1 Jan 2021).

 

Changes in accounting policies

IFRS 16 - Leases, which became effective by 1 January 2019, requires the lessee to recognise a right to use asset and lease liability, depreciate the associated asset, re-measure and reduce the liability through lease payments; unless the underlying leased asset is of low value and/or short term in nature. The Company has adopted IFRS 16 from 1 January 2019 with the modified retrospective approach, and has not restated comparatives. The reclassifications and the adjustments arising from the new leasing rules are therefore recognised in the opening balance sheet on 1 January 2019 and further explained in Note 19.

 

In applying IFRS 16 for the first time, the Company has used the following practical expedients permitted by the standard: applying a single discount rate to a portfolio of leases with reasonably similar characteristics, accounting for operating leases with a remaining lease term of less than 12 months as at 1 January 2019 as short-term leases, and using hindsight in determining the lease term where the contract contains options to extend or terminate the lease.

 

On adoption of IFRS 16, the Company recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of IAS 17 Leases. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 January 2019. The weighted average lessee's incremental borrowing rate applied to the lease liabilities on 1 January 2019 was 2.5%

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) and the Taq Taq PSC (Taq Taq), 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 Sarta PSC, 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. '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 2019

 

 

Production

 

Pre-production

 

Other

Total

 

$m

$m

$m

$m

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)

 

 

 

 

 

 

 

 

 

 

Revenue from contracts with customers includes $104.3 million (2018: $105.4 million) arising from the 4.5% royalty interest on gross Tawke PSC revenue ending at the end of July 2022 ("the ORRI"). Total assets and liabilities in the other segment are predominantly cash and debt balances.

 

 

 

For the period ended 31 December 2018

 

The Company has updated its segmental reporting 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.

 

 

Production

 

Pre-production

 

Other

Total

 

$m

$m

$m

$m

Revenue from contracts with customers

350.3

-

-

350.3

Revenue from other sources

4.8

-

-

4.8

Cost of sales

(163.2)

-

-

(163.2)

Gross profit

191.9

-

-

191.9

 

 

 

 

 

Exploration credit

-

1.5

-

1.5

Impairment of intangible assets

-

(424.0)

-

(424.0)

General and administrative costs

-

-

(24.0)

(24.0)

Operating profit / (loss) 

191.9

(422.5)

(24.0)

(254.6)

 

 

 

 

 

Operating profit / (loss) is comprised of

 

 

 

 

EBITDAX

326.4

-

(22.3)

304.1

Depreciation and amortisation

(134.5)

-

(1.7)

(136.2)

Exploration credit

-

1.5

-

1.5

Impairment of intangible assets

-

(424.0)

-

(424.0)

 

 

 

 

 

Finance income

-

-

4.4

4.4

Bond interest expense

-

-

(30.0)

(30.0)

Other finance expense

(1.7)

(0.2)

(1.3)

(3.2)

Profit / (Loss) before income tax

190.2

(422.7)

(50.9)

(283.4)

 

 

 

 

 

 

 

 

 

 

Capital expenditure

70.4

25.1

-

95.5

Total assets

1,015.4

493.2

319.3

1,827.9

Total liabilities

(89.1)

(100.5)

(306.9)

(496.5)

 

 

 

 

 

 

 

 

 

 

Total assets and liabilities in the other segment are predominantly cash and debt balances.

 


3. Operating costs

 

2019

2018

 

$m

$m

Production costs

(37.7)

(28.7)

Depreciation of oil and gas property, plant and equipment

(88.8)

(72.4)

Amortisation of oil and gas intangible assets

(68.3)

(62.1)

Cost of sales

(194.8)

(163.2)

 

 

 

Exploration (expense) / credit

(1.2)

1.5

 

 

 

Impairment of intangible assets (note 8)

-

(424.0)

Impairment of property, plant and equipment (note 9)

(29.8)

-

 

 

 

 

 

 

Corporate cash costs

(14.1)

(17.4)

Corporate share-based payment expense

(3.6)

(4.9)

Depreciation and amortisation of corporate assets

(1.4)

(1.7)

General and administrative expenses

(19.1)

(24.0)

 

 

 

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.

 

 

Fees payable to the Company's auditors:

 

2019

2018

 

 

$m

$m

 

Audit of consolidated and subsidiary financial statements

(0.7)

(0.4)

 

Tax and advisory services

(0.2)

(0.3)

 

Total fees

(0.9)

(0.7)

 

 

 

 

       

 

4. Staff costs and headcount

 

 

2019

2018

 

$m

$m

Wages and salaries

(18.6)

(17.1)

Social security costs

(1.6)

(1.0)

Share based payments

(5.8)

(6.3)

 

(26.0)

(24.4)

 

Average headcount was:

 

2019 number

2018

number

Turkey

62

64

KRI

18

15

UK

24

17

Somaliland

17

17

 

121

113

 

 

 

5. Finance expense and income 

 

2019

2018

 

$m

$m

Bond interest payable

(30.0)

(30.0)

Other finance expense

(4.3)

(3.2)

Finance expense

(34.3)

(33.2)

 

 

 

Bank interest income

6.6

4.4

Finance income

6.6

4.4

 

Bond interest payable is the cash interest cost of Company bond debt. Other finance expense primarily relates to the discount unwind on the bond and the asset retirement obligation provision.

 

 

6. Income tax expense

 

Current tax expense is incurred on the profits of the Turkish and UK services companies. Under the terms of the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in note 1.

 

 

7. Earnings per share

 

Basic

Basic earnings per share is calculated by dividing the profit attributable to equity holders of the Company by the weighted average number of shares in issue during the period.

 

 

2019

2018

 

 

 

Profit / (Loss) attributable to equity holders of the Company ($m)

103.9

(283.6)

 

 

 

Weighted average number of ordinary shares - number 1

275,197,007

279,065,717

Basic earnings / (loss) per share - cents per share

37.8

(101.6)

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:

 

 

2019

2018

 

 

 

Profit / (Loss) attributable to equity holders of the Company ($m)

103.9

(283.6)

 

 

 

Weighted average number of ordinary shares - number1

275,197,007

279,065,717

Adjustment for performance shares, restricted shares and share options

5,859,457

1,182,481

Weighted average number of ordinary shares and potential ordinary shares

281,056,464

280,248,198

Diluted earnings / (loss) per share - cents per share

37.0

(101.6)

1 Excluding shares held as treasury shares 

 

 

 

 

 

 

 

 

 

 

8. Intangible assets

 

Exploration and evaluation assets

 

Tawke

RSA

Other

assets

Total

 

$m

$m

$m

$m

Cost

 

 

 

 

At 1 January 2018

1,471.7

425.1

6.5

1,903.3

Additions

25.1

-

0.3

25.4

Discount unwind of contingent consideration

8.1

-

-

8.1

Other

(11.7)

-

-

(11.7)

At 31 December 2018 and 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

1,518.5

425.1

7.3

1,950.9

 

 

 

 

 

Accumulated amortisation and impairment

 

 

 

 

At 1 January 2018

(581.3)

(32.8)

(6.3)

(620.4)

Amortisation charge for the period

-

(62.1)

(0.2)

(62.3)

Impairment

(424.0)

-

-

(424.0)

At 31 December 2018 and 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

(1,005.3)

(163.2)

(6.8)

(1,175.3)

 

 

 

 

 

Net book value

 

 

 

 

At 31 December 2018

487.9

330.2

0.3

818.4

At 31 December 2019

513.2

261.9

0.5

775.6

 

 

 

 

2019

2018

Book value

 

$m

$m

Bina Bawi PSC

Discovered gas and oil, appraisal

352.9

338.7

Miran PSC

Discovered gas and oil, appraisal

120.3

116.2

Somaliland PSC

Exploration

33.8

33.0

Qara Dagh PSC

Exploration / Appraisal

6.2

-

Exploration and evaluation assets

 

513.2

487.9

 

 

 

 

Tawke overriding royalty

 

160.2

217.5

Tawke capacity building payment waiver

101.7

112.7

Tawke RSA assets

 

261.9

330.2

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

9. Property, plant and equipment

 

 

Producing assets

Development assets

Other

assets

 

Total

 

$m

$m

$m

$m

Cost

 

 

 

 

At 1 January 2018

2,683.9

-

9.4

2,693.3

Additions

70.4

-

0.2

70.6

Non-cash additions for ARO/share-based payments

2.9

-

-

2.9

At 31 December 2018 and 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 (note 19)

-

-

3.6

3.6

Net change in payable

-

(3.6)

-

(3.6)

Non-cash additions for ARO/share-based payments

3.8

0.1

-

3.9

At 31 December 2019

2,876.1

68.0

13.5

2,957.6

 

 

 

 

 

Accumulated depreciation and impairment

 

 

 

 

At 1 January 2018

(2,119.7)

-

(8.6)

(2,128.3)

Depreciation charge for the period

(72.4)

-

(0.3)

(72.7)

At 31 December 2018 and 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

(2,310.7)

-

(10.0)

(2,320.7)

 

 

 

 

 

Net book value

 

 

 

 

At 31 December 2018

565.1

-

0.7

565.8

At 31 December 2019

565.4

68.0

3.5

636.9

 

 

Asset acquisitions of $49.4 million relates to the Sarta PSC. Further explanation on oil and gas assets is provided in the significant accounting judgements and estimates in note 1.

 

 

 

2019

2018

Book value

 

$m

$m

Tawke PSC

Oil production

474.9

478.2

Taq Taq PSC

Oil production

90.5

86.9

Producing assets

 

565.4

565.1

 

 

 

 

Sarta PSC

Oil development

68.0

-

 

 

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

CGU

$m

Tawke CGU

$m

Long term Brent +/- $5/bbl

+/- 3

+/- 18

Discount rate +/- 2.5%

+/- 6

+/- 48

Production and reserves +/- 10%

+/- 8

+/- 62

 

 

10. Trade and other receivables

 

2019

2018

 

$m

$m

Trade receivables

150.2

94.8

Other receivables and prepayments

7.2

4.6

 

157.4

99.4

 

At 31 December 2019, $54.1 million relating to invoices due in November and December was overdue. Payment for these invoices was received January and February 2020. The fair value of trade receivables is broadly in line with the carrying value.

 

Movement on trade receivables in the period

2019

$m

2018

$m

Carrying value at 1 January

94.8

73.3

Revenue from contracts with customers

368.7

350.3

Cash proceeds

(317.4)

(335.1)

Loss allowance

(0.5)

-

Capacity building payments

4.6

6.3

Carrying value at 31 December

150.2

94.8

 

$0.5 million of loss allowance is made under the expected credit loss model as explained at note 1.

 

 

11. Cash and cash equivalents and restricted cash

 

2019

2018

 

$m

$m

Cash and cash equivalents

390.7

334.3

Restricted cash

3.0

10.0

 

393.7

344.3

 

Cash is primarily held on time deposit with major financial institutions or in US Treasury bills. Restricted cash of $3.0 million relates principally to exploration activities in Morocco.

 

 

12. Trade and other payables

 

2019

2018

 

$m

$m

Trade payables

10.3

10.7

Other payables

144.4

81.3

Accruals

55.8

37.4

 

210.5

129.4

 

 

 

Non-current

118.8

76.8

Current

91.7

52.6

 

210.5

129.4

 

 

 

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 $73.7 million (2018: $68.5 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 $145.0 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, explained in note 1. 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.

 

 

 

13. Deferred income

 

2019

2018

 

$m

$m

Non-current

26.7

31.9

Current

5.0

5.0

 

31.7

36.9

 

 

 

14. Provisions

 

2019

2018

 

$m

$m

Balance at 1 January

32.9

29.3

Interest unwind

1.3

1.2

Additions

3.2

2.5

Reversal

-

(0.1)

Balance at 31 December

37.4

32.9

 

 

 

Provisions cover expected decommissioning and abandonment costs arising from the Company's assets. The decommissioning and abandonment provision is 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% (2018: 2%) and discounted at 4% (2018: 4%). The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2028 and 2038.

 

 

15. Borrowings and net cash

 

1 Jan 2019

Discount unwind

Dividend paid

Net change in cash

31 Dec 2019

 

$m

$m

$m

$m

$m

2022 Bond 10.0%

(297.3)

(0.6)

-

-

(297.9)

Cash

334.3

-

(27.4)

83.8

390.7

Net Cash

37.0

(0.6)

(27.4)

83.8

92.8

 

The fair value of the bonds is $316.5 million (2018: $308.3 million).

 

 

1 Jan 2018

Discount unwind

Net change in cash

31 Dec 2018

 

$m

$m

$m

$m

2022 Bond 10.0%

(296.8)

(0.5)

-

(297.3)

Cash

162.0

-

172.3

334.3

Net Cash

(134.8)

(0.5)

172.3

37.0

 

 

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:

 

2019
$m

2018

$m

Trade and other receivables

155.3

97.0

Cash and cash equivalents

390.7

334.3

 

546.0

431.3

 

All trade receivables are owed by the KRG with $54.1 million overdue year-end. This was received post year-end, with $64.5 million overdue at the signing date. 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 2019 the Company had cash and cash equivalents of $390.7 million (2018: $334.3 million).

 

Oil price risk

The Company's revenues are calculated from Dated Brent oil price, and a $5/bbl change in average Dated Brent would result in a profit before tax change of circa $25 million. Sensitivity of the carrying value of its assets to oil price risk is provided in notes 8 and 9.

 

Currency risk

As other than head office costs, substantially all of the Company's transactions are measured and denominated in US dollars, therefore the exposure to currency risk is not material and no sensitivity analysis has been presented.

 

Interest rate risk

The Company reported borrowings of $297.9 million (2018: $297.3 million) in the form of a bond maturing in December 2022, with fixed coupon interest payable of 10% on the nominal value of $300 million. Although interest is fixed on existing debt, 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 debt of the Company would result in an additional cost of $3 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 $390.7 million (2018: $334.3 million).

 

 

17. Share capital

 

 

Total

 Ordinary Shares

 

 

At 1 January 2018 - fully paid1

280,248,198

 

 

At 31 December 2018, 1 January 2019 and 31 December 2019 - fully paid1

280,248,198

 

 

   

1 Ordinary shares include 2,577,720 (2018: 1,005,839) treasury shares. Share capital includes 4,303,249 (2018: 1,324,150) 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 £0.10 per share.

 

 

18. Dividends

 

 

2019

2018

 

$m

$m

Ordinary shares

 

 

Final dividend for the year ended 31 December 2018 of 10¢ per share

27.6

-

Interim dividend for the year ended 31 December 2019 of 5¢ per share

13.2

-

Total dividends provided for or paid

40.8

-

 

 

 

Paid in cash

27.4

-

Recognised as payable (paid on 8 January 2020)

13.2

-

Foreign exchange income on dividend paid

0.2

-

 

40.8

-

 

 

 

 

 

 

19. Right-of-use assets / Lease liabilities

 

The Company's right-of-use assets are related to office, car and warehouse rents. The Company has elected to apply the transition exemptions for short-term and low-value leases. These leases are expensed when they incur.

 

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
$m

Cost

 

At 1 January 2019

1.9

Additions

1.7

At 31 December 2019 (note 9)

3.6

 

 

Accumulated depreciation

 

At 1 January 2019

-

Depreciation charge for the period

(0.9)

At 31 December 2019

(0.9)

 

 

Net book value

 

At 31 December 2018

1.9

At 31 December 2019

2.7

 

 

On adoption of IFRS 16, the Company recognised lease liabilities in relation to leases which had previously been classified as 'operating leases' under the principles of IAS 17 Leases. These liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate as of 1 January 2019. The weighted average lessee's incremental borrowing rate applied to the lease liabilities on 1 January 2019 was 2.5%. Right-of-use assets are depreciated over the lifetime of the related lease contract. The lease terms vary from one to five years.

 

 

Lease liabilities
$m

 

 

At 1 January 2019

(1.9)

Additions

(1.7)

Payments of lease liabilities

0.6

At 31 December 2019 (note 12)

(3.0)

 

 

 

Included within lease liabilities of $3.0 million are non-current lease liabilities of $2.2 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. As at 31 December 2019, the contractual maturities of the Company's lease liabilities are as follows:

 

 

Less than

1 year
$m

Between

1 -2 years
$m

Between

2 - 5 years

$m

Total contractual cash flow

$m

Carrying

Amount

$m

 

 

 

 

 

 

Lease liabilities

(1.0)

(0.8)

(1.4)

(3.2)

(3.0)

 

 

 

 

 

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

Form of awards

 

Performance shares.
The intention is to deliver
the full value of vested shares at no cost to the participant (e.g. as conditional shares or nil-cost options).

 

Restricted shares.
The intention is to deliver
the full value of shares
at no cost to the participant (e.g. as conditional shares
or nil-cost options).

 

Market value options.
Exercise price is set equal to the average share price over a period of up to 30 days to grant.

Performance conditions

 

Performance conditions will apply. Awards granted from 2017 are based on relative and absolute TSR measured against a group of industry peers over a three year period.

 

Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.

 

Performance conditions may or may not apply. For awards granted to date, there are no performance conditions.

Vesting period

 

Awards will vest when the Remuneration Committee determine whether the performance conditions
have been met at the end
of the performance period.

 

Awards typically vest over three years.

 

Awards typically vest after three years. Options are exercisable until the 10th anniversary of the grant date.

Dividend equivalents

 

Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply.

 

Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply.

 

Provision of additional cash/shares to reflect dividends over the vesting period may or may not apply.

 

In 2019, 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 2019 are set out below:

 

 

 

PSP

(nil cost)

 

RSP

(nil cost)

 

Share option plan

SOP

weighted avg. exercise price

 

Outstanding at the beginning of the year

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 the end of the year

9,990,853

1,723,544

119,588

810p

 

 

 

 

 

 

               

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 2019 and fair values per share using the model were as follows:

 

 

 

 

 

 

 

RSP

7/5/19

RSP

21/8/19

PSP

7/5/19

PSP

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 in the period is 129p and for RSP awards granted in the period is 206p.

 

Total share-based payment charge for the year was $5.8 million (2018: $6.3 million).

 

 

21. Capital commitments

 

Under the terms of its PSCs and JOAs, 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:

 

 

 

2019
$m

2018

$m

Board remuneration

 

0.7

0.7

Key management emoluments and short-term benefits

 

5.6

6.0

Share-related awards

 

0.6

1.4

 

 

6.9

8.1

 

There are no other significant related party transactions.

 

 

23. Events occurring after the reporting period

 

After the balance sheet date, there has been a significant fall in oil price as a result of a number of macro events and the Company's operations have been impacted by COVID-19. Under IFRS these are non-adjusting events in respect of the year-end 31 December 2019. Although the full extent and timing of the impact of these events is not yet known, the Company expects to experience delays in operations as a result of COVID-19 and the lower oil price is impacting the cash generation of the business. Consequently, the financial reporting impact will need to be considered in 2020 and could impact areas such as the carrying value of our oil and gas assets.

 

 

 

 

 

 

 

 

 

 

24. Subsidiaries and joint arrangements

 

The Company has four joint arrangements in relation to its producing assets Taq Taq, Tawke and pre-production assets Sarta and 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 2019 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 Africa Limited (in liquidation)4

 

UK

 

100

Genel Energy Exploration 2 Limited (in liquidation)4

 

UK

 

100

Genel Energy Finance 2 Limited5

 

Jersey

 

100

Genel Energy Finance plc (in liquidation)4

 

UK

 

100

Genel Energy Gas Company Limited5

 

Jersey

 

100

Genel Energy Holding Company Limited5

 

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. 5 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 Yӧnetim Hizmetleri A.Ş.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 3 Field Court, London, WC1R 5EF

5 Registered office is 12 Castle Street, St Helier, JE2 3RT, Jersey

6 Registered office is PO Box 1338, Maico Building, The Valley, Anguilla

7 Registered office is Next Level İş Merkezi, Eskişehir Yolu, Dumlupınar Bulvarı, No:3A-101, Söğütözü, Ankara, 06500, 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 2019 annual report will be despatched to shareholders in April 2020 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 2019 contained in this preliminary announcement has been audited and was approved by the board on 18 March 2020. The financial information in this statement does not constitute the Company's statutory financial statements for the years ended 31 December 2019 or 2018. The financial information for 2019 and 2018 is derived from the statutory financial statements for 2018, which have been delivered to the Registrar of Companies, and 2019, which will be delivered to the Registrar of Companies and issued to shareholders in April 2020. The auditors have reported on the 2019 and 2018 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 2019 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 2018 annual report.



ISIN: JE00B55Q3P39
Category Code: ACS
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 53289
EQS News ID: 1001323

 
End of Announcement EQS News Service

fncls.ssp?fn=show_t_gif&application_id=1001323&application_name=news&site_id=symex

01/06/2020 15:00
28/05/2020 08:00
27/05/2020 08:00
14/05/2020 12:30
14/05/2020 08:00
07/05/2020 08:00
01/05/2020 08:00
27/04/2020 12:03
17/04/2020 08:00
09/04/2020 09:00