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

Directive transparence : information réglementée

18/03/2021 08:00

Genel Energy PLC (GENL)
Genel Energy PLC: Full-Year Results

18-March-2021 / 07:00 GMT/BST
Dissemination of a Regulatory Announcement that contains inside information according to REGULATION (EU) No 596/2014 (MAR), transmitted by EQS Group.
The issuer is solely responsible for the content of this announcement.


18 March 2021

Genel Energy plc

Audited results for the year ended 31 December 2020

 

Genel Energy plc ('Genel' or 'the Company') announces its audited results for the year ended 31 December 2020.

 

Bill Higgs, Chief Executive of Genel, said:

"2020 was a uniquely challenging year for everyone. As for Genel, our continued progress and strong performance in 2020 has laid the foundation for a year of growth and operational catalysts in 2021. We continued investment in Sarta, which entered production in November, and the field is generating cash as we now move to rapidly appraise its exciting potential. Three appraisal wells will be drilled at the licence in 2021. The QD-2 well at Qara Dagh is also set to spud shortly, as we look to evaluate the potential to add a fifth producing field.

 

As we make this investment in growth, the low-cost and high-margin nature of our growing oil production means that we expect to generate significant free cash flow at the prevailing oil price. In turn, this gives us the confidence in our material and sustainable dividend distribution, including a final dividend of 10 cents per share announced today, as we continue to offer investors a compelling mix of growth and returns."

 

Results summary ($ million unless stated)

 

2020

2019

Average Brent oil price ($/bbl)

42

64

Production (bopd, working interest)

 31,980

36,250

Revenue

 159.7

377.2

EBITDAX1

 114.6

321.8

  Depreciation and amortisation

 (153.7)

(158.5)

  Exploration expense

(2.2)

(1.2)

  Impairment of oil and gas assets2

(286.3)

(29.8)

  Impairment of receivables

(36.9)

-

Operating (loss) / profit

(364.5)

132.3

Cash flow from operating activities

129.4

272.9

Capital expenditure

109.7

158.1

Free cash flow4

(4.4)

99.0

Dividends declared (¢ per share)

15

15

Cash

354.5

390.7

Cash after post-year end payments5

273.5

377.1

Total debt after settlement of called bonds5

280.0

300.0

Net cash6

6.2

92.8

Basic EPS (¢ per share)

(152.0)

37.8

Underlying EPS (¢ per share)3

41.8

116.9

 

 

 

 

  1. EBITDAX is operating loss / (profit) adjusted for the add back of depreciation and amortisation ($153.7 million), exploration expense ($2.2 million), impairment of property, plant and equipment ($242.0 million), impairment of intangible assets ($44.3 million) and impairment of receivables ($36.9 million)
  2. Despite production in line with expectations, the low oil price in June 2020 resulted in an impairment of production assets at the half-year results, which under IFRS cannot be reversed despite the improved oil price outlook
  3. Underlying EPS is EBITDAX divided by weighted average number of ordinary shares
  4. Free cash flow is reconciled on page 13
  5. On 8 January 2021, shortly after the balance sheet date, the Company paid $81.0 million to settle $77.1 million of old bonds reducing its gross debt balance to $280.0 million, with $267.7 million reported under IFRS in the balance sheet (2019: Cash reported at 31 December 2019 less interim dividend paid ($13.6 million) on 8 January 2020)
  6. Reported cash less IFRS debt (page 13)

 

 

Highlights

  • Zero lost time injuries ('LTI') and zero tier one loss of primary containment events in 2020 at Genel and TTOPCO operations
    • No LTIs since 2015, with over 13 million work hours since the last incident as of end-2020
  • Net production averaged 31,980 bopd in 2020 (2019: 36,250 bopd), following the pause in the drilling programme at Tawke, appropriate to the external environment
    • First oil from Sarta achieved in November 2020, with asset now producing over 10,000 bopd
  • $173 million of cash proceeds were received in 2020 (2019: $317 million)
  • The low-production cost per barrel of $2.8/bbl in 2020 helped deliver cash generation of $85 million in the year from producing assets
    • Free cash outflow of $4 million following material capital expenditure on growth assets 
  • Dividends of 15¢ per share announced in 2020 (2019: 15¢ per share)
  • Net cash of $6 million at 31 December 2021 following the call of the old 2022 bond, with cash of $274 million and reported IFRS debt of $268 million
  • Carbon intensity of 13 kgCO2e/bbl for scope 1 and 2 emissions in 2020, significantly below the global oil and gas industry average of 20 kgCO2e/boe

 

Outlook

  • Production guidance for 2021 maintained as slightly above the 2020 average of 31,980 bopd, with the potential for a higher exit rate and further growth in 2022 depending on success of the Sarta appraisal programme
    • Margin of $15 per working interest barrel expected in 2021 at average Brent oil price $60/bbl, with receivable recovery payments increasing that to $20/bbl
  • 2021 capital expenditure guidance maintained at $150 million to $200 million, with the current macro environment and outlook supporting investment at the top end of this range
    • c.$100 million expenditure is forecast to be spent on growth assets, with three appraisal wells at Sarta targeting a material 2C resource and the QD-2 well, set to spud shortly, aiming to open up a new producing field
  • Operating costs still expected to be c.$50 million (2020: $33 million), equating to c.$4/bbl in 2021 ($2.8/bbl in 2020), retaining our advantageous low operating cost position, with the increase from 2020 due to the addition of Sarta early production costs
  • Given the increase in Brent oil price and confidence in ongoing payments from the Kurdistan Regional Government ('KRG'), including override and receivable recovery payments, Genel expects to generate cash in 2021 post-dividend payments
    • Receivable recovery payments expected to generate c.$50 million in 2021 at an oil price of $60/bbl
    • A $5/bbl change in Brent impacts cash generation by c.$35 million in 2021
  • Due to Genel's robust financial position and confidence in the Company's future prospects, the Board is accordingly recommending a final dividend of 10¢ per share (2020: 10¢ per share), a distribution of $27.9 million

 

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 0900 GMT, with an associated webcast available on the Company's website, www.genelenergy.com.

 

This announcement includes inside information.

 

Disclaimer

This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements.

 

 

CHAIRMAN'S STATEMENT

I am pleased to welcome you to Genel Energy's ninth annual results statement. 2020 was a difficult year for everybody, with COVID-19 impacting the global business environment in a way that was unexpected and unforeseeable. The challenges that it presented were unique, but the low-oil price environment that it created was a powerful reminder of the need to have a business model that is both robust and adaptable to rapidly changing external conditions.

 

Genel has worked to put in place a business model that is appropriate for fluctuating market conditions, allowing the Company to continue strategic delivery when times are tough and lay the foundations to thrive in better times ahead. 2020 was a strong indicator that our strategy is the right one as we not merely survived but had the financial strength to invest in our key growth projects, and maintain our material dividend, delivering on our promises to investors with a reliability for which we are striving to be well known.

 

Focusing on key areas

As the impact of COVID-19 became clear and the oil price collapsed in the first quarter of the year, the flexibility and elasticity of our business model was demonstrated. Swift decisions were made to focus on key areas and fit our investment programme to the external environment. We reshaped our capital expenditure programme to live within our means, removing c.$80 million from our original guidance, while still investing in growth and maintaining the dividend.

 

The low oil price helped to reinforce our capital investment priorities, which as you would expect support our strategic priorities. Investment at Tawke was delayed appropriately by the operator DNO, with whom we are closely aligned, and the decision was made to continue investing in the delivery of first oil at Sarta. This was achieved in November, only 21 months after completing the acquisition of the stake in the field. This rapid delivery, despite the challenges of COVID-19, was an exceptional achievement and a testimony to our workforce and field partners.

 

Already the only multi-licence oil producer in the Kurdistan Region of Iraq ('KRI'), the addition of Sarta provides us with a material growth opportunity going forward, as we work with Chevron to develop what could potentially be the largest field in the KRI.

 

Our final capital allocation priority is the dividend, and we are proud of our ability to retain this at such a significant level despite the external upheaval, a testament to the resilience of our strategy and business model.

 

A strategy resilient by design

Our strategy remains very simple. We aim to increase our low-cost production, invest in growth, and retain surplus cash to pay a material and sustainable dividend.

 

Central to this strategy is prudent financial planning, as your Board and management team look to minimise risk and create sustainable shareholder value. The successful bond refinancing in September allowed us to extend the tenor of our debt while reducing the interest cost. Genel remains committed to retaining a robust balance sheet and strong liquidity, providing the foundation for our flexible capital investment programme.

 

It is this financial strength and focus on the balance sheet, together with a positive business outlook, that underpins our confidence in the sustainability of our dividend, which we are once again pleased to maintain in 2021.

 

With the worst of the pandemic hopefully now behind us and a recovery in the oil price further boosting our finances as we enter a year of exciting investment in the portfolio, Genel is confident that we can continue delivering on our strategy and create material value for our stakeholders.

 

The ramp up of work at Sarta promises to increase our low-cost production in 2021, with the possibility for much more to come in 2022 and the years ahead. Work at Qara Dagh also offers the potential to unlock value from a fifth field in the KRI, and we will of course remain prudent in our expenditure as we aim to provide a compelling mix of growth and returns.

 

A socially responsible contributor

Last year I discussed the period of significant and necessary change into which the energy industry is entering. Despite the pressures and challenges of 2020, we retained our focus on ensuring that Genel is at the forefront of this process.

 

As we grow, we continue to focus on our social and environmental responsibilities as we look to live up to our mantra of having the right assets, in the right location, with the right emissions, in the hands of the right people. The frequency and intensity of Board discussions on ESG signify how seriously we take the issue, and we firmly believe that responsible producers have a key part to play in the energy transition and delivering the goals of the Paris Agreement. 

 

We will be measured against the promises that we make, and we issued our first GRI compliant Sustainability Report in 2020 setting out where we are on our sustainability journey. The report illustrates our commitment to support the communities in which we operate and solidify our place in the energy transition, minimising emissions as we look to play our part through delivering some of the fewer and better natural resources projects that the world needs as it moves towards clean energy. 

 

Given our low-cost and low-carbon barrels, and the positive social impact our operations have on the Kurdistan Region of Iraq, it is our belief that Genel has the right portfolio to continue powering the energy transition and deliver value to our shareholders as a socially responsible contributor to the global energy mix.

 

 

CEO STATEMENT

It would be an understatement to say that 2020 was not the year that anyone expected. In spite of the challenges that resulted, we continued to do what we say and delivered on our strategy.

 

Executing our strategy

Our first strategic priority remains the maximisation of the value of our low-cost production. Despite the reduction of investment at Tawke, production at the licence remained over 100,000 bopd again in 2020, and this continues to form the bedrock of our production, which averaged just under 32,000 bopd in the year. We see this as being a platform for Genel going forward, as we expect year-on-year production growth in both 2021 and 2022.

 

This robust and predictable production, and the low production cost, meant that we continued to generate material cash at an asset level. Taken in isolation, our producing assets generated $85 million of cash, even allowing for the low oil price, delayed KRG payments and suspended override proceeds. Despite the suspension of the override payments, and $159 million of unpaid KRG debts in 2020, our free cash outflow in the year was only $4 million. Given the fact that we also continued to invest in the priority growth projects that provide us with exciting value creation potential, this is a creditable performance powered by a cost base that is amongst the lowest in the sector.

 

Further diversifying production

The key project that formed the bulk of our investment in growth in 2020 was Sarta, and first oil was successfully delivered in November. This was an important strategic and operational milestone for Genel, not least given the challenges presented by COVID-19. This operational delivery, brought in on budget, was a tribute to the quality and professionalism of our workforce, and the close cooperation we enjoy with partners and contractors.

 

Production began with the Sarta-3 well, which has produced in line with expectations. Sarta-2 then entered production in Q1 this year, and the Sarta-1 well will hopefully add to production around the end of this year. Should we have appraisal success in 2021, then material further production can be added in 2022.

 

It is not just the geological potential of Sarta that excites us, but the low-cost of the field and impressive margins that promise material value creation. The unrecovered back costs support PSC economics that mean field production achieves a margin of c.$21/bbl at a Brent oil price of $60/bbl, which to put it into context is more than equal to that of Tawke with the override. This cash generation makes Sarta a perfect fit for our low-cost and high-margin portfolio, and a key growth and value driver for Genel, and hopefully the KRI oil industry as a whole going forward.

 

Strengthening the foundations

Given the lower oil price and overdue payments, the fact that we still ended 2020 in a net cash position - even after dividend distributions and making the investment to bring Sarta to production this year - was a testament to our resilience.

 

This resilience comes in part due to our focus on the minimisation of risk and the retention of a strong balance sheet, combining to provide us with the ability to invest in areas that have the potential to provide the highest returns to shareholders. Our production is robust, and assets generate cash flows even at a low oil price. Our financial strength was bolstered by our decision to refinance our bond early, which gives us the certainty about our near-term liquidity position to invest confidently in future growth.

 

Following the refinancing, we have liquidity of over $270 million, no debt maturity until 2025, a flexible capital programme, and the financial foundations from which to grow. Investment programmes at the Tawke licence resumed as conditions improved through the second half of 2020, and the operator expects another year of production over 100,000 bopd. With the external environment looking far brighter, 2021 is now about delivering the growth that we spent 2020 gearing up for.

 

Delivering growth and returns

The key focus of our near-term growth investment remains Sarta and Qara Dagh.

 

At Sarta, our appraisal campaign is targeting a material reserves addition, with net 79 MMbbls currently designated as 2C resources. This is only scratching the surface of the field's potential. Appraisal activity is scheduled to begin early in the second quarter, with the drilling of the Sarta-5 well. This will immediately be followed by Sarta-6, with results from the first well expected in Q3, and both will be completed by end-Q4. We very much look forward to the results of these wells, which could provide a roadmap for significant and long-term growth.

 

The second area of focus of our growth investment is Qara Dagh where the QD-2 well is set to be spud around the end of Q1. This well will test the commerciality of a potentially very large resource, estimated by Genel at gross mean c.400 MMbbls. We are already the only multi licence oil producer in the KRI and the potential to add a fifth field is very exciting, especially one that could possibly be so material and with light oil.

 

As we invest in these growth projects and significantly increase our capital expenditure year-on-year, increased payments from the KRG will help us retain our strong financial position. From January 2021, invoices once again include our contractual override payments and a receivable recovery mechanism tabled in December 2020 and implemented by the KRG with respect to the January 2021 payment.

 

Payments in 2020 were impacted by external factors, of which the volatile oil price was then the final straw, that temporarily derailed the KRG's ability to make payments in the first two months of the year. Consistent payments from March onwards once again illustrated the KRG's willingness and ability to prioritise payments to IOCs, and the track record over the last six years gives us confidence that these will continue going forward.

 

We have a constructive relationship with the government, and we are hopeful that the confirmation of a new oil minister will also help provide the clarity that the industry requires as we work together for the benefit of all stakeholders. We look forward to working with the minister as we continue to search for a solution that will help unlock the potential of Bina Bawi, the priority of our gas strategy.

 

Supporting the energy transition

A core stakeholder group on which we continue to focus is the local community in Kurdistan. We continue to invest in the local community, while maximising local employment. We are committed to utilising local people and companies wherever possible, and currently employ around 250 Kurdish nationals directly, with just under 30 local companies supported by Genel assets.

 

Providing a meaningful benefit to society while delivering the power to increase living standards is something that we see as key to deciding which barrels of oil should be produced as we transition to clean energy. As activity ramps up at Sarta, and hopefully in turn Qara Dagh, we look forward to deepening our local community involvement and increasing our positive impact on the local area. 

 

Of course, the production of natural resources has a wider impact than just that of the financial benefits to the local area, and we recognise that as a natural resources company we have a role to play in the energy transition. As such, we have evaluated the best way to manage emissions in order to deliver the Paris Agreement goals of limiting global warming to 1.5 degrees and leading to net zero by 2050. In order to meet this goal, energy efficiency and flaring management practices have been formalised in a GHG Emissions Management Standard that emphasises an asset life-cycle approach to emission mitigation. This standard applies to all operated and non-operated assets, and provides a systematic framework to identify an asset's carbon budget that aligns with the Paris Agreement pathway. 

 

The enhanced oil recovery project at the Tawke PSC was a key step on our emission reduction journey, and the carbon intensity of our portfolio reduced to 7kg CO2e/bbl for scope 1 and 2 emissions in the second half of 2020 following the material reduction in flaring at the Tawke PSC. This intensity will rise during early production at Sarta, but we are already committed to a flares out programme at the asset as production increases, and we will aim to live up to our value of ingenuity by seeking innovative ways to further reduce our footprint going forward.

 

As well as the local community and global environment, our commitment to safe operations remains at the forefront of everything that we do. We are proud of our safety record, and we have not had a lost time incident for five years and 13 million hours worked. This is the result of a lot of hard work and a commitment to a culture of incident-free operations for which I would like to pay tribute to our team. Our success in this area does not make us complacent, and we will endeavour to repeat this performance going forward.

 

A year of growth and catalysts

With the challenges of 2020 hopefully now receding, the work we did in the year to build the foundations for growth can now be delivered on, as we continue to execute our simple strategy. Sarta will help us to increase our low-cost production, and investment in growth both there and at Qara Dagh will tell us a lot more about their value creation potential, with four appraisal wells that have the potential to add reserves and production going forward.

 

Despite this material expenditure we expect to generate material free cash flow at the prevailing oil price. Our strong financial position, and confidence in increased payments, also supports the maintenance of material distributions to shareholders, as we aim to fulfil our goal of being a world-class creator of shareholder value.

 

 

OPERATING REVIEW

Reserves and resources development

Genel's proven (1P) and proven plus probable (2P) net working interest reserves totalled 69 MMbbls (31 December 2019: 69 MMbbls) and 117 MMbbls (31 December 2019: 124 MMbbls) respectively at the end of 2020.

 

Gross upward technical revisions of 47 MMbbls at the Tawke PSC, relating to both the Tawke and Peshkabir fields, more than offset the 40 MMbbls of production at the licence, and contributed to our reserves remaining materially unchanged. The appraisal campaign getting underway at Sarta in 2021 has the potential to convert material 2C resources into reserves.  

 

 

 

Remaining reserves (MMbbls)

Resources (MMboe)

 

Contingent

Prospective

1P

2P

1C

2C

Best

Gross

Net

Gross

Net

Gross

Net

Gross

Net

Gross

Net

 

31 December 2019

258

69

455

124

1,294

1,173

2,592

2,313

4,372

3,536

 

Production

(44)

(12)

(44)

(12)

-

-

-

-

-

-

 

Acquisitions

-

-

-

-

-

-

-

-

-

-

 

Extensions and discoveries

-

-

-

-

-

-

-

-

-

-

 

New developments

-

-

-

-

-

-

-

-

-

-

 

Revision of previous estimates

48

12

26

5

(34)

(9)

(38)

(10)

1,335

931

 

31 December 2020

262

69

437

117

1,259

1,164

2,554

2,303

5,706

4,467

 
                       

 

Production

Working interest production in 2020 averaged 31,980 bopd (2019: 36,250 bopd). This decrease was largely due to the delay in the investment programme at the Tawke PSC, which resumed later in 2020 as the external environment stabilised and improved.

 

Production currently comes from 76 wells, with the addition of Sarta meaning that we now have four producing fields, making production yet more diverse and reliable. Production from Sarta in 2021 is expected to more than offset declines from Tawke and Taq Taq, and full-year production is expected to be slightly above the 2020 average. Year to date production averages c.33,000 bopd.

 

Depending on the success of the Sarta appraisal programme and the timing of possible production from the Sarta-1 well, there is the clear potential for a higher 2021 exit rate and further production growth in 2022.

 

PRODUCING ASSETS

Tawke PSC (25% working interest)

Gross production at the Tawke PSC averaged 110,280 bopd in 2020, of which Peshkabir contributed 52,710 bopd.

 

There will be an active drilling campaign in 2021 on the Tawke licence as we continue to work in close alignment with the operator, DNO. Up to eight new development wells are set to be drilled and multiple workovers on existing producing wells are due to be undertaken in the drive to maintain production above 100,000 bopd.

 

Sarta (30% working interest)

Bringing Sarta to production was a key goal in 2020. As expenditure was reduced across the portfolio, the decision was made to continue investment in this goal, as Sarta is a key growth asset going forward. With first oil having been achieved in November 2020, the field is now generating cash that will support the funding of future appraisal and development, as we look to replicate the success of the Peshkabir produce while appraise model. 

 

The first well on production was Sarta-3. This was joined in February 2021 by the Sarta-2 well, and production from the field is now over 10,000 bopd, with the ongoing optimisation of facilities configuration expected to further increase production.

 

Sarta will again form the majority of our pre-production expenditure in 2021, with c.$60 million to be spent on the appraisal drilling campaign and associated facilities work. The campaign will begin at the start of Q2 and Sarta-5 and Sarta-6 will be drilled back to back, with results from the first well expected in Q3, and operations on both wells complete in Q4 2021. The campaign is targeting a material portion of the 250 MMbbls of existing contingent resources, and prospective resources, in Jurassic formations.

 

Re-entry and deepening of the Sarta-1 (S-1D) well is expected around the middle of the year. Should S-1D be successful, a flowline will be constructed in order to enable the well to enter production around the end of 2021.

 

Taq Taq (44% working interest, joint operator)

Gross production at Taq Taq averaged 9,670 bopd in 2020, following the suspension of drilling activity in H1 2020.

 

Operations at Taq Taq are focused on optimising cash flow, and no drilling is scheduled in 2021, with activity limited to workovers that will help manage field decline. Genel continues to explore the best way to obtain value from future production at the licence.

 

PRE-PRODUCTION ASSETS

Qara Dagh (40% working interest, operator)

Preparations were well under way to spud the QD-2 well in H1 2020, prior to the uncertainty caused by COVID-19 forcing Genel to notify the KRG of the occurrence of a force majeure event preventing the Company from being able to perform its contractual obligations as scheduled.

 

The increased certainty in the operating environment, and Genel's ability to operate under the expected level of restrictions, allowed the lifting of force majeure at Qara Dagh in early Q4 2020. Genel was able to proceed with approvals for activities necessary in order to reach a spud date for the QD-2 well, which is expected in coming weeks.

 

The Parker rig has now been mobilised, and the well is expected to spud in line with this schedule, with drilling operations anticipated to complete in Q3 2021.

 

Qara Dagh offers an exciting appraisal opportunity. The QD-1 well, completed in 2011, tested light oil in two zones from the Shiranish formation. The QD-2 well location has been selected c.10 km to the northwest of QD-1, and will test a more crestal position on the structure with a high angle well to maximise contact with reservoir fractures. The field holds resources estimated by Genel at gross mean c.400 MMbbls.

 

Bina Bawi and Miran (100% working interest, operator)

Bina Bawi and Miran are assets that have the potential to generate significant shareholder value, and efforts have continued to explore a commercial solution to allow the unlocking of the material resources.

 

Discussions with the KRG are ongoing at the highest levels, which would enable the Company to progress to the next stage of activity.

 

Genel continues to maintain capex discipline, and will only commence investment upon certainty of alignment with the KRG and a clear path to monetisation.

 

African exploration

The uncertainty created by COVID-19 delayed the search for partners to fund and minimise Genel's spend on our potentially high-impact exploration wells, but the farm-out process relating to the highly prospective SL10B13 block in Somaliland (100% working interest and operator) continues to progress, with potential partners involved in assessing the opportunity.

 

A farm-out campaign is also planned relating to the Lagzira block offshore Morocco (75% working interest and operator), with the aim of bringing a partner onto the licence prior to considering further commitments.

 

 

FINANCIAL REVIEW

Overview

Our now well-established and proven business model enabled us to successfully navigate the extremely challenging conditions faced in 2020, with COVID-19's adverse impact on oil price and operating conditions severely testing our ability to deliver against our priorities. Our success in doing so has positioned us well to maximise the benefit from the recent oil price improvement with a stronger and more diverse portfolio.

 

Resilient operating model and assets

2020 demonstrated the resilience of our operating model and assets in three principal ways. Firstly, through the speed at which we were able to reduce capital activity and spend. Secondly, by the ability of our production assets to be profitable even at low oil prices. That profitability meant that we generated sufficient income to cover our outgoings. Thirdly, our success at Sarta proved the benefits of bringing assets onto production quickly and at low cost, meaning that the cost to first oil was affordable even in stressed conditions.

 

Strong balance sheet with no near-term debt maturity

Maintaining a strong balance sheet remains one of our key priorities. We reported net cash at the end of the year, despite not being paid $159 million owed to us by the KRG for oil sales.

 

The resilient business, strong balance sheet and significant liquidity enabled the Company to take an important and proactive step forward and derisk the balance sheet and the funding of our capital activity programme by refinancing our debt, thereby moving the maturity date from December 2022 to October 2025.

 

The old bonds of $300 million were settled at an average redemption price of 106.5, a small premium over the 103 that we would have paid if we had waited until the final year of the bond to redeem, or 102 if we waited as late as the last 6 months.

 

New bonds, maturing in 2025, were issued in October at a 3% discount. The issue discount of 3% results in an implied coupon of 9.85%. The Company has taken the opportunity to purchase $20 million of its own bonds, in order to reduce interest cost but retain optionality.

 

Our current debt level of $280 million reduced materially after year-end following settlement of the remaining $77 million 2022 bonds at the call price of 105, resulting in net cash of $6 million.

   

FY2020 financial priorities and financial performance

The table below summarises our progress against the 2020 financial priorities of the Company as set out at our 2019 results.

 

FY2020 financial priorities

Progress

  • Maintaining our financial strength through existing market conditions

 

  • Net cash position maintained at YE2020, with the expectation of the same in 2021 at the prevailing oil price 

 

  • Continued focus on capital allocation, with prioritisation of highest value investment in assets with ongoing or near-term cash and value generation
  • Despite COVID-19 bringing material challenges: we invested to bring Sarta to first oil in 2020 and prepared for the drilling of the Qara Dagh-2 well in 2021

 

  • Delivery of a 2020 work programme on time and on budget, that is appropriate to the external environment

 

  • A recut 2020 work programme and budget, appropriate to the external environment, was delivered on time and within budget

 

  • Continued focus on identifying and developing additional assets that offer potential for significant value to the 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

 

  • With a specific reference to progressing Sarta and Qara Dagh, management continues to seek to mature further growth opportunities that fit the Company's capital structure and business model both within and outside the existing portfolio

 

The table below summarises our financial performance in the year (all figures $ million unless stated) reporting a free cash outflow of only $4.4 million despite the non-payment of $159 million that was due in the period:

 

 

FY2020

FY2019

Brent average oil price

$42/bbl

$64/bbl

Revenue

159.71

377.2

Production costs

(32.7)

(37.7)

Producing asset capex

(56.5)

(115.1)

Working capital

14.9

(59.7)

Cash generated from producing assets

85.41

164.7

G&A (excl. depreciation and amortisation)

(12.4)

(17.7)

Net cash interest2

(23.8)

(23.4)

Free cash flow before investment in growth

49.2

123.6

Pre-production capex

(53.2)

(43.0)

Working capital and other

(0.4)

18.4

Free cash flow

(4.4)

99.0

Sales receipts due but not received (see note 10) plus suspended override1

158.6

54.1

 

1 Revenue does not include $37.8 million of invoiced override revenue where payment was suspended from March 2020 to December 2020 because it did not meet criteria for recognition (see note 1)

2 Net cash interest is bond interest payable less bank interest income (see note 5)

  • Our producing assets have delivered predictable production, and liquidity has been preserved by taking quick steps to materially reduce capex to a level appropriate to the oil price
  • General and administration costs have been optimised

 

Fully funded appraisal and development programme for Sarta; Qara Dagh funded in success case

The combination of our resilient assets, strong balance sheet, and extended debt maturity puts us in a position where we are not dependent on oil price or recovery of monies owed by the KRG to execute Sarta and Qara Dagh appraisal and, in the success case, subsequent expansion of both.

 

We are pleased to note the recent oil price improvement and are encouraged at the progress regarding payment of the monies owed to us by the KRG. The KRG has announced incremental repayments based on 50% of the surplus of average monthly Brent price above $50/bbl multiplied by production. The first payment on this basis was received in March.

 

The combination of oil price, payment for overdue receivables, and the resumption of override payments, significantly increases the cash generation of our production business. Our production covers costs and investment in production maintenance and growth at lower oil prices and is significantly cash generative based on the current oil price and outlook.

 

Dividend

In 2019, our confidence in our business plan to replace and grow producing asset cash generation at value accretive cost was demonstrated by the commencement of a material and sustainable dividend, and $41 million was distributed to shareholders in the year.

 

The Company was committed to and able to maintain our dividend unchanged through the challenges of 2020, illustrating a resilience that we believe sets us apart from many of our peers. The dividend is an important part of our investment story and the hard work done in 2020 has put us in a good position to benefit from oil price improvement and continue that story. Our dividend capacity is solid, despite having Sarta, Qara Dagh and Bina Bawi that all have potential to require near-term capital in the success case. The Board has approved the final dividend unchanged at 10c per share, resulting in a final dividend payment of around $28 million. Including the earlier distributed interim dividend, this brings our total dividends for the financial year to 15c per share, a total payment of $42 million. We continue to look to increase the dividend, with confidence in a growing reserve base and outlook cash being key to that decision.

 

Outlook and financial priorities for 2021

With cash of $274 million after settlement of bonds, producing asset cash flows that cover corporate and bond interest costs and fund pre-production investment, and Sarta now contributing meaningfully to our cash generation, the Company is well positioned for 2021.

 

The Company has a portfolio that contains discovered resource with potential for creation of material shareholder value.

 

We will continue to focus our capital allocation where we see it delivering most value and the most rapid returns. For 2021, capital expenditure guidance is $150-200 million, which at the upper end of the range is nearly double our spend in 2020 as we appraise Sarta and drill Qara Dagh-2. Although the objective of these wells is primarily to deliver incremental reserves and resources, they have the potential to add significantly to production already in 2022.

 

For 2021, our financial priorities are the following:

  • Maintain our financial strength and continue protecting the balance sheet
  • Maximise NPV by prioritising highest value investment in assets with ongoing or near-term cash and value generation
  • Deliver 2021 work programme on time and on budget
  • Continue to focus on growing our income streams and cash generation, bringing greater resilience and diversity to the business and supporting our sustainable and progressive dividend programme

 

Financial results for the year

Income statement

(all figures $ million)

FY 2020

FY 2019

Production (bopd, working interest)

31,980

36,250

Profit oil

55.4

117.2

Cost oil

84.9

147.2

Override royalty

19.4

112.8

Revenue

159.7

377.2

Production costs

(32.7)

(37.7)

G&A (excl. depreciation and amortisation)

(12.4)

(17.7)

EBITDAX

114.6

321.8

Depreciation and amortisation

(153.7)

(158.5)

Impairment

(323.2)

(29.8)

Exploration expense

(2.2)

(1.2)

Net finance expense

(52.2)

(27.7)

Income tax expense

(0.2)

(0.7)

(Loss) / Profit

(416.9)

103.9

 

Working interest production of 31,980 bopd decreased year-on-year (2019: 36,250 bopd), with the decrease in revenue from $377.2 million to $159.7 million, principally caused by:

  • lower Brent oil price   $108 million  
  • lower capex resulting in lower cost oil $62 million  
  • override unpaid from March onwards $38 million 

 

Production costs of $32.7 million decreased from last year (2019: $37.7 million) as a result of scaled back activity on producing assets. Production cost per barrel was $2.8/bbl in 2020 (2019: $2.9/bbl).

 

General and administration costs were $12.8 million (2019: $19.1 million), of which corporate cash costs were $9.6 million (2019: $13.3 million). The reduction from the prior period is a result of optimisation of costs and increased capital activity, principally at Sarta and Qara Dagh.

 

The decrease in revenue resulted in a similar reduction to EBITDAX of $114.6 million (2019: $321.8 million). EBITDAX is presented in order for the users of the financial statements to understand the cash profitability of the Company, which excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation and impairments.

 

Depreciation of $98.7 million (2019: $88.8 million) and Tawke intangibles amortisation of $54.6 million (2019: $68.3 million) slightly decreased in total as a net result of decrease in production and impairments at half year lowering the deprecation rate per barrel.

 

At the half year, an impairment expense of $254.7 million for Tawke CGU, $31.6 million for Taq Taq and $34.9 million for trade receivables was booked which is explained further in note 1 (2019: $29.8 million). There was no further impairment at year-end.

 

Bond interest expense of $31.5 million was slightly increased due to higher bond payable at year end. Call option for remaining part of existing bond was settled in January 2021. Finance income of $2.0 million (2019: $6.6 million) was bank interest income. Other finance expense of $22.7 million (2019: $4.3 million) included premium on bond buyback and non-cash discount unwind expense on liabilities.

In relation to taxation, under the terms of the KRI production sharing contracts, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. Tax presented in the income statement was related to taxation of the service companies (2020: $0.2 million, 2019: $0.7 million).

 

Capital expenditure

Capital expenditure is the aggregation of spend on production assets ($56.5 million) and pre-production assets ($53.2 million) and is reported to provide investors with an understanding of the quantum and nature of investment that is being made in the business. Capital expenditure for the period was $109.7 million, predominantly focused on production assets and the Sarta PSC ($30.0 million) and Qara Dagh ($10.6 million):

 

(all figures $ million)

FY 2020

FY 2019

Cost recovered production capex

 56.5

115.1

Pre-production capex - oil

 30.0

22.1

Pre-production capex - gas

 10.0

11.9

Other exploration and appraisal capex

 13.2

9.0

Capital expenditure

 109.7

158.1

 

Cash flow, cash, net cash and debt

Gross proceeds received totalled $173.4 million (2019: $317.4 million), of which $22.9 million (2019: $91.5 million) was received for the override royalty.

 

(all figures $ million)

FY 2020

FY 2019

Brent average oil price

$42/bbl

$64/bbl

Operating cash flow

129.4

272.9

Producing asset cost recovered capex

(60.2)

(105.1)

Development capex

(25.3)

(18.7)

Exploration and appraisal capex

(24.2)

(26.5)

Restricted cash release

3.0

7.0

Interest and other

(27.1)

(30.6)

Free cash flow

(4.4)

99.0

 

Free cash flow is presented in order to show the free cash generated that is available for the Board to invest in the business. The measure provides the reader a better understanding of the underlying business cash flows. Free cash out flow before dividend was $4.4 million (2019: positive $99.0 million), with an overall decrease in cash of $36.2 million in the year (2019: $56.4 million increase).

 

(all figures $ million)

FY 2020

FY 2019

Free cash flow

(4.4)

99.0

Dividend paid (incl. expenses)

(55.3)

(29.0)

Purchase of own shares

(3.4)

(13.5)

Bond refinancing

28.9

-

Other

(2.0)

(0.1)

Net change in cash

(36.2)

56.4

Opening cash

390.7

334.3

Closing cash

354.5

390.7

Debt reported under IFRS

(348.3)

(297.9)

Net cash

6.2

92.8

 

 

The bonds maturing 2025 have two financial covenant maintenance tests:

 

Financial covenant

Test

YE 2020

Equity ratio (Total equity/Total assets)

> 40%

60%

Minimum liquidity

> $30m

$355m

 

 

 

Net assets

Net assets at 31 December 2020 were $929.8 million (2019: $1,386.1 million) and consist primarily of oil and gas assets of $1,095.1 million (2019: $1,412.5 million), trade receivables of $94.0 million (2019: $150.2 million) and net cash of $6.2 million (2019: $92.8 million).

 

Liquidity / cash counterparty risk management

The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills or on time deposits with a number of major financial institutions. Suitability of banks is assessed using a combination of sovereign risk, credit default swap pricing and credit rating.

 

Dividend

Total dividends declared in 2020 amounted to $41.5 million (2019: $40.8 million), representing 15¢ per share (2019: 15¢ per share).

 

The Board is recommending no change in the final dividend of 10¢ per share (2019: 10¢ per share), a total distribution of c.$27.9 million.

 

The payment timetable for the final dividend is below:

  • Annual General Meeting: 6 May 2021
  • Ex-dividend date: 13 May 2021
  • Record Date: 14 May 2021
  • Payment Date: 14 June 2021

 

Going concern

The Directors have assessed that the Company's forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the annual report for the period ended 31 December 2020 and consequently that the Company is considered a going concern. In assessing going concern, the Directors have assessed that prolonged prevalence of COVID-19 may have a further negative impact on the oil price and in turn revenues, operational activity and receipt of amounts owed. The Company's low run rate costs, flexible capital programme, and strong cash position provide appropriate mitigation of the reduction of cash inflows that COVID-19 may cause for the going concern basis to remain appropriate.

 

 

Consolidated statement of comprehensive income

For the year ended 31 December 2020

 

 

Note

2020

2019

 

 

$m

$m

 

 

 

 

Revenue

2

159.7

377.2

 

 

 

 

Production costs

3

(32.7)

(37.7)

Depreciation and amortisation of oil assets

3

(153.3)

(157.1)

Gross (loss) / profit

 

(26.3)

182.4

 

 

 

 

Exploration expense

3

(2.2)

(1.2)

Impairment of intangible assets

3-8

(44.3)

-

Impairment of property, plant and equipment

3-9

(242.0)

(29.8)

Impairment of receivables

10

(36.9)

-

General and administrative costs

3

(12.8)

(19.1)

Operating (loss) / profit

 

(364.5)

132.3

 

 

 

 

 

 

 

 

Operating (loss) / profit is comprised of:

 

 

 

EBITDAX

 

114.6

321.8

Depreciation and amortisation

3

(153.7)

(158.5)

Exploration expense

3

(2.2)

(1.2)

Impairment of intangible assets

3-8

(44.3)

-

Impairment of property, plant and equipment

3-9

(242.0)

(29.8)

Impairment of receivables

 

10

(36.9)

-

 

 

 

 

Finance income

5

2.0

6.6

Bond interest expense

5

(31.5)

(30.0)

Other finance expense

5

(22.7)

(4.3)

(Loss) / Profit before income tax

 

(416.7)

104.6

Income tax expense

6

(0.2)

(0.7)

(Loss) / Profit and total comprehensive (expense) / income

 

(416.9)

103.9

 

 

 

 

Attributable to:

 

 

 

Owners of the parent

 

(416.9)

103.9

 

 

(416.9)

103.9

 

 

 

 

(Loss) / earnings per ordinary share

 

¢

¢

Basic

7

(152.0)

37.8

Diluted

7

(152.0)

37.0

Underlying1

 

41.8

116.9

 

 

 

 

 

1 Underlying EPS is EBITDAX divided by weighted average number of ordinary shares

 

 

Consolidated balance sheet

At 31 December 2020

 

 

Note

2020

2019

 

 

$m

$m

Assets

 

 

 

Non-current assets

 

 

 

Intangible assets

8

699.4

775.6

Property, plant and equipment

9,19

395.7

636.9

Trade and other receivables

10

 52.1

-

 

 

1,147.2

1,412.5

Current assets

 

 

 

Trade and other receivables

10

48.9

157.4

Restricted cash

11

-

3.0

Cash and cash equivalents

11

354.5

390.7

 

 

403.4

551.1

 

 

 

 

Total assets

 

1,550.6

1,963.6

 

 

 

 

Liabilities

 

 

 

Non-current liabilities

 

 

 

Trade and other payables

12-19

(100.4)

(118.8)

Deferred income

13

(19.7)

(26.7)

Provisions

14

(45.9)

(37.4)

Interest bearing loans

15

(267.7)

(297.9)

 

 

(433.7)

(480.8)

Current liabilities

 

 

 

Trade and other payables

12-19

(99.0)

(91.7)

Deferred income

13

(7.5)

(5.0)

Interest bearing loans

15

(80.6)

-

 

 

(187.1)

(96.7)

 

 

 

 

Total liabilities

 

(620.8)

(577.5)

 

 

 

 

 

 

 

 

Net assets

 

929.8

1,386.1

 

 

 

 

Owners of the parent

 

 

 

Share capital

17

43.8

43.8

Share premium account

 

3,991.9

4,033.4

Accumulated losses

 

(3,105.9)

(2,691.1)

Total equity

 

929.8

1,386.1

 

 

 

 

 

 

 

Consolidated statement of changes in equity

For the year ended 31 December 2020

 

 

 

 

Note

Share capital

$m

Share premium

$m

Accumulated losses

$m

Total equity

$m

At 1 January 2019

 

43.8

4,074.2

(2,786.6)

1,331.4

 

 

 

 

 

 

Profit and total comprehensive income

 

-

-

103.9

103.9

Share-based payments

20

-

-

5.1

5.1

Purchase of shares to satisfy share awards

 

-

-

(8.2)

(8.2)

Purchase of treasury shares

 

-

-

(5.3)

(5.3)

Dividends provided for or paid1

18

-

(40.8)

-

(40.8)

 

 

 

 

 

 

At 31 December 2019 and 1 January 2020

 

43.8

4,033.4

(2,691.1)

1,386.1

 

 

 

 

 

 

Loss and total comprehensive expense

 

 -  

 -  

 (416.9)

 (416.9)

Share-based payments

20

-

-

 5.5

 5.5

Purchase of shares for employee share awards

 

 -  

 -  

 (3.4)

 (3.4)

Dividends provided for or paid1

18

 -  

 (41.5)  

 -  

 (41.5)  

 

 

 

 

 

 

At 31 December 2020

 

 43.8

 3,991.9

 (3,105.9)

 929.8

 

 

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

 

 

 

 

Consolidated cash flow statement

For the year ended 31 December 2020

 

 

Note

2020

2019

 

 

$m

$m

Cash flows from operating activities

 

 

 

(Loss) / Profit for the year

 

(416.9)

103.9

Adjustments for:

 

 

 

   Net finance expense

5

52.2

27.7

   Taxation

6

 0.2  

0.7

   Depreciation and amortisation

3

 153.7

158.5

   Exploration expense

3

 2.2

1.2

   Impairments

3

323.2

29.8

   Other non-cash items

3

(3.7)

(2.4)

Changes in working capital:

 

 

 

   Decrease / (Increase) in trade receivables

 

 15.8

(55.4)

   Decrease / (Increase) in other receivables

 

 0.6

(0.2)

   Increase in trade and other payables

 

0.4

3.3

Cash generated from operations

 

 127.7

267.1

Interest received

5

 2.0

6.6

Taxation paid

 

(0.3)

(0.8)

Net cash generated from operating activities

 

129.4

272.9

 

 

 

 

Cash flows from investing activities

 

 

 

Purchase of intangible assets

 

 (24.2)

(26.5)

Purchase of property, plant and equipment

 

 (85.5)

(123.8)

Movement in restricted cash

11

3.0

7.0

Net cash used in investing activities

 

(106.7)

(143.3)

 

 

 

 

Cash flows from financing activities

 

 

 

Dividends paid to company's shareholders, including expenses

18

(55.3)

(29.0)

Purchase of own shares

 

(3.4)

(13.5)

Bond refinancing: part-settlement and new issuance

15

28.9

-

Other

 

(3.3)

(0.6)

Interest paid

 

(25.8)

(30.0)

Net cash used in financing activities

 

(58.9)

(73.1)

 

 

 

 

Net (decrease) / increase in cash and cash equivalents

 

(36.2)

56.5

Foreign exchange loss on cash and cash equivalents

 

-

(0.1)

Cash and cash equivalents at 1 January

11

390.7

334.3

Cash and cash equivalents at 31 December

11

354.5

390.7

Post-year end payments1

15

(81.0)

(13.6)

Cash and cash equivalents after post-year end payments

 

273.5

377.1

 

1 On 8 January 2021, shortly after the balance sheet date, the Company paid $81.0 million to settle $77.1 million of old bonds reducing its gross debt balance to $280 million, with $267.7 million reported under IFRS in the balance sheet. In the prior year, an interim dividend payment of $13.6 million was made on 8 January 2020, which has been shown as a comparative.

 

Notes to the consolidated financial statements

 

1. Summary of significant accounting policies

 

  1. Basis of preparation

Genel Energy Plc - registration number: 107897 (the Company) is a public limited company incorporated and domiciled in Jersey with a listing on the London Stock Exchange. The address of its registered office is 12 Castle Street, St Helier, Jersey, JE2 3RT.

 

The consolidated financial statements of the Company have been prepared in accordance with International Financial Reporting Standards as adopted by the European Union and interpretations issued by the IFRS Interpretations Committee (together 'IFRS'); are prepared under the historical cost convention except as where stated; and comply with Company (Jersey) Law 1991. The significant accounting policies are set out below and have been applied consistently throughout the period.

 

The Company prepares its financial statements on a historical cost basis, unless accounting standards require an alternate measurement basis. Where there are assets and liabilities calculated on a different basis, this fact is disclosed either in the relevant accounting policy or in the notes to the financial statements.

 

Items included in the financial information of each of the Company's entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US dollars to the nearest million ($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 20 and 23.

 

Going concern

The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combination of oil price, discount rates, production volumes, payments, capital and operational spend scenarios. The Company has reported liquidity after settlement of bonds post year-end of $273.5 million, with no debt maturing until the second half of 2025 and significant headroom on both the equity ratio and minimum liquidity covenant. Our business model has demonstrated its resilience in 2020, when oil price was low and 4 months of payments with a value of $120.8 million that were due in the year were not received, by delivering a small free cash out flow after investing significantly in bringing Sarta to first production. The strength of the balance sheet is expected to be maintained through 2021, with Sarta adding a new income stream and diversifying production risk, and capital activity in the year focused on expanding the sources of income of the business further. Our low-cost assets with flexibility on commitment of capital means that we are resilient to oil prices as low as the levels reached last year, with the KRG also demonstrating its ability to pay consistently in times of financial stress. In addition, specifically for the purposes of the going concern, management have modelled a downside scenario, recognising the impact of the COVID19 pandemic, which includes a significant reduction in oil price from current levels combined with a reduction in production. As a result, the Directors have assessed that the Company's forecast liquidity provides adequate headroom over its forecast expenditure for the 12 months following the signing of the annual report for the period ended 31 December 2020 and consequently that the Company is considered a going concern.

 

Foreign currency

Foreign currency transactions are translated into the functional currency of the relevant entity using the exchange rates prevailing at the dates of the transactions or at the balance sheet date where items are re-measured. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of comprehensive income within finance income or finance costs.

 

Consolidation

The consolidated financial statements consolidate the Company and its subsidiaries. These accounting policies have been adopted by all companies.

 

Subsidiaries

Subsidiaries are all entities over which the Company has control. The Company controls an entity when it is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Company. They are deconsolidated from the date that control ceases. Transactions, balances and unrealised gains on transactions between companies are eliminated.

 

Joint arrangements and associates

Arrangements under which the Company has contractually agreed to share control with another party, or parties, are joint ventures where the parties have rights to the net assets of the arrangement, or joint operations where the parties have rights to the assets and obligations for the liabilities relating to the arrangement. Investments in entities over which the Company has the right to exercise significant influence but has neither control nor joint control are classified as associates and accounted for under the equity method.

 

The Company recognises its assets and liabilities relating to its interests in joint operations, including its share of assets held jointly and liabilities incurred jointly with other partners.

 

Acquisitions

The Company uses the acquisition method of accounting to account for business combinations. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured at their fair values at the acquisition date. The Company recognises any non-controlling interest in the acquiree at fair value at time of recognition or at the non-controlling interest's proportionate share of net assets. Acquisition-related costs are expensed as incurred.

 

Farm-in/farm-out

Farm-out transactions relate to the relinquishment of an interest in oil and gas assets in return for services rendered by a third party or where a third party agrees to pay a portion of the Company's share of the development costs (cost carry). Farm-in transactions relate to the acquisition by the Company of an interest in oil and gas assets in return for services rendered or cost-carry provided by the Company.

 

Farm-in/farm-out transactions undertaken in the development or production phase of an oil and gas asset are accounted for as an acquisition or disposal of oil and gas assets. The consideration given is measured as the fair value of the services rendered or cost-carry provided and any gain or loss arising on the farm-in/farm-out is recognised in the statement of comprehensive income. A profit is recognised for any consideration received in the form of cash to the extent that the cash receipt exceeds the carrying value of the associated asset.

 

Farm-in/farm-out transactions undertaken in the exploration phase of an oil and gas asset are accounted for on a no gain/no loss basis due to inherent uncertainties in the exploration phase and associated difficulties in determining fair values reliably prior to the determination of commercially recoverable proved reserves. The resulting exploration and evaluation asset is then assessed for impairment indicators under IFRS 6.

 

  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

The significant judgements that the directors have made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognised in the financial statements include; i) IFRS 15 criteria have not been met for override revenue; ii) the Bina Bawi and Miran projects will progress which are explained in the context of the significant estimates below.

 

Significant estimates

The following are the critical estimates that the directors have made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognised in the financial statements.

 

Estimation of hydrocarbon reserves and resources and associated production profiles and costs

Estimates of hydrocarbon reserves and resources are inherently imprecise and are subject to future revision. The Company's estimation of the quantum of oil and gas reserves and resources and the timing of its production, cost and monetisation impact the Company's financial statements in a number of ways, including: testing recoverable values for impairment; the calculation of depreciation, amortisation and assessing the cost and likely timing of decommissioning activity and associated costs. This estimation also impacts the assessment of going concern and the viability statement.

 

Proved and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company's assets. The Company estimates its reserves using standard recognised evaluation techniques. Assets assessed as having proven and probable reserves are generally classified as property, plant and equipment as development or producing assets and depreciated using the units of production methodology. The Company considers its best estimate for future production and quantity of oil within an asset based on a combination of internal and external evaluations and uses this as the basis of calculating depreciation and amortisation of oil and gas assets and testing for impairment.

 

Hydrocarbons that are not assessed as reserves are considered to be resources and the related assets are classified as exploration and evaluation assets. These assets are expenditures incurred before technical feasibility and commercial viability is demonstrable. Estimates of resources for undeveloped or partially developed fields are subject to greater uncertainty over their future life than estimates of reserves for fields that are substantially developed and being depleted and are likely to contain estimates and judgements with a wide range of possibilities. These assets are considered for impairment under IFRS 6.

 

Once a field commences production, the amount of proved reserves will be subject to future revision once additional information becomes available through, for example, the drilling of additional wells or the observation of long-term reservoir performance under producing conditions. As those fields are further developed, new information may lead to revisions.

 

Assessment of reserves and resources are determined using estimates of oil and gas in place, recovery factors and future commodity prices, the latter having an impact on the total amount of recoverable reserves.

 

Change in accounting estimate

The Company has updated its estimated reserves and resources with the accounting impact summarised below under estimation of oil and gas asset values.

 

Estimation of oil and gas asset values

Estimation of the asset value of oil and gas assets is calculated from a number of inputs that require varying degrees of estimation. Principally oil and gas assets are valued by estimating the future cash flows based on a combination of reserves and resources, costs of appraisal, development and production, production profile and future sales price and discounting those cash flows at an appropriate discount rate.

 

Future costs of appraisal, development and production are estimated taking into account the level of development required to produce those reserves and are based on past costs, experience and data from similar assets in the region, future petroleum prices and the planned development of the asset. However, actual costs may be different from those estimated.

 

Discount rate is assessed by the Company using various inputs from market data, external advisers and internal calculations. A post tax nominal discount rate of 13% derived from the Company's weighted average cost of capital (WACC) is used when assessing the impairment testing of the Company's oil assets at year-end. Risking factors are also used alongside the discount rate when the Company is assessing exploration and appraisal assets.

 

In addition, estimation of the recoverable amounts of the Bina Bawi and Miran cash generating units ('CGU's), which are classified under IFRS as exploration and evaluation intangible assets and consequently carry the inherent uncertainty explained above, include the key assessment that the projects will progress. Progression of the project is outside of the control of management and is dependent on the progress of government discussions regarding supply of gas and sanctioning of development of both of the midstream for gas and the upstream for oil. The KRG and the Company have been focusing on progressing the Bina Bawi asset first, with success on Bina Bawi likely to inform both of the likely structure, midstream and downstream solution for Miran.  Lack of progress on Bina Bawi could result in significant delays in value realisation and consequently a materially lower asset value for both assets. Under the existing production sharing contracts ('PSC') for both Bina Bawi and Miran, the KRG had a right (not an obligation) effective from 30 April 2020 and 31 May 2020 respectively to take steps to terminate the PSCs if no new Gas Lifting Agreement(s) was in place. Whilst the Company does not accept that any such right arose, or could now be exercised, the Company has in any event been informed by the KRG that, while negotiations are ongoing, it will not seek to serve notice of an intention to terminate the Bina Bawi PSC. Discussions are ongoing.

Change in accounting estimate - Discount rate for assessing recoverable amount of producing assets

Following the significant change in the macro geo-political, economic and industry environment, for the period ended 30 June 2020 the Company has updated the discount rate used for assessing the recoverable amount of its producing assets from 12.5% to 13.0%. At the half year this had a negative impact on the recoverable amount of the Tawke CGU and the Taq Taq CGU. The results of the assessments combining with other factors are explained below. The Company disclosed the sensitivities on net present values in note 9. At the year-end the discount rate is unchanged from the half year at 13.0%.

 

Change in accounting estimate - Tawke asset and Tawke RSA (receivable settlement agreement) carrying value; Taq Taq carrying value

At the half year, as a result of lower oil prices and lower levels of investment than were forecasted in the preparation of the financial statements for the year-ended 31 December 2019 were finalised, together with the higher discount rate explained above, management assessed that there were impairment indicators for both Tawke and Taq Taq. Management performed impairment assessments and assessed their recoverable values on a fair value less cost to sell basis, resulting in an impairment of $210.4 million for the Tawke; $44.3 million for the Tawke RSA; and $31.6 million for the Taq Taq asset respectively. There were no impairment indicators at the end of the year, and in particular, the oil price outlook has improved since the half year as disclosed below.

 

Change in accounting estimate - Taq Taq and Tawke depreciation

Management has reassessed the depreciation rate per barrel during the second half, principally as a result of lower estimate of future production and costs for Taq Taq, increased future cost estimate for Tawke and the impact of HY impairments on both assets. Change in future cost estimates do not materially impact NPV as a result of cost recovery which is explained further in the sensitivity to capital expenditure disclosure in note 9. The adjusted depreciation rate results in a depreciation expense that is $6 million higher for Taq Taq and $4 million higher for Tawke than if the previous depreciation rate per barrel was used.

 

Estimation of future oil price and netback price

The estimation of future oil price has a significant impact throughout the financial statements, primarily in relation to the estimation of the recoverable value of property, plant and equipment and intangible assets. It is also relevant to the assessment of going concern and the viability statement.

 

The Company's forecast of average Brent oil price for future years is based on a range of publicly available market estimates and is summarised in the table below, with the 2025 price then inflated at 2% per annum.

 

$/bbl

2020

2021

2022

2023

2024

Actual / Forecast

42

55

55

60

60

HY 2020 forecast

40

43

50

55

60

Prior year forecast

65

67

68

72

73

 

The netback price is used to value the Company's revenue, trade receivables and its forecast cash flows used for impairment testing and viability. It is the aggregation of realised oil price less transportation and handling costs. The Company does not have direct visibility on the components of the netback price realised for its oil because sales are managed by the KRG, but invoices are currently raised for payments on account using a netback price agreed with the KRG.

 

Estimation of the recoverable value of trade receivables

At the end of March, in line with other International Oil Companies (IOCs) in Kurdistan, the KRG informed the Company that payments owed for sales made in the four months from November 2019 to February 2020 would be deferred. For Genel this amounted to $120.8 million.

 

For the period ended 30 June 2020, the Company estimated recovery of these overdue amounts, which resulted in an impairment of $34.9 million.

 

In December 2020, the KRG announced a reconciliation model for payment of the receivable relating to the unpaid invoices, whereby for each dollar above a monthly dated Brent average of $50/bbl, 50 cents per working interest barrel shall be paid towards monies owed.

 

In order to assess the recoverable amount of overdue trade receivables at 31 December 2020,  the Company has compared the carrying value of trade receivables with the present value of the estimated future cash flows based on the KRG's communications, and using estimations of future oil prices and production scenarios.  Under IFRS9, the Company has used a forward-looking impairment model based on a lifetime expected credit loss (ECL) assessment. The model calculates the net present value of outstanding receivables using the effective interest rate for the period in which the revenue was recognised, which was 13%. The expected credit loss is the weighted average of these scenarios and is recognised in the income statement.  The result of the Company's assessment was no change to the reported receivable balance, with the impairment of $34.9 million maintained. The accounting and valuation of the receivable will be an output of clarity on the mechanism and that it is working effectively, oil price and production. The Company has provided the detailed disclosures required by IFRS 9 ECL assessment in note 10.

 

Recognition of revenue generated by the override royalty, arising from the RSA

Since 2017 when the RSA was signed, the Company has received override revenue from Tawke sales. At the end of March, the KRG informed the Company that this override income was suspended for a minimum period up to December 2020. Because management did not have visibility on how or when this contractual right would be received,  it has assessed that the criteria for revenue recognition under IFRS15, specifically on payment terms and collectability, have not been met, and consequently no override revenue has been recognised from 1 March 2020. The total amount of override revenue for the period between 1 March 2020 to 31 December 2020 that has not been recognised is $37.8 million.

 

 

1.3 Accounting policies

The accounting policies adopted in preparation of these financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2019, adjusted for transitional requirements where necessary, further explained under revenue and changes in accounting policies headings.

 

Revenue

Revenue for oil sales is recognised when the control of the product is deemed to have passed to the customer, in exchange for the consideration amount determined by the terms of the contract. For exports the control passes to the customer when the oil enters the export pipe, for domestic sales this is when oil is collected by truck by the customer.

 

Revenue is earned based on the entitlement mechanism under the terms of the relevant PSC; overriding royalty income ('ORRI'), which is earned on 4.5% of gross field revenue from the Tawke licence until July 2022; and royalty income. Entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred on an asset, and profit oil, which is the mechanism through which profits are shared between the Company, its partners and the KRG. The Company pays capacity building payments on profit oil entitlement earned on the Sarta and Taq Taq licences, which becomes due for payment once the Company has received the relevant proceeds. Profit oil revenue is always reported net of any capacity building payments that will become due. On the Tawke licence, the Company also receives override revenue ("ORRI"), which is calculated as 4.5% of Tawke PSC field revenue. The override began in August 2017 and is due to end in July 2022.

 

The Company's oil sales are made to the KRG which is the counterparty of the PSCs and are valued at a netback price, which is calculated from the estimated realised sales price for each barrel of oil sold, less selling, transportation and handling costs and estimates to cover additional costs. A netback adjustment is used to estimate the price per barrel that is used in the calculation of entitlement and is explained further in significant accounting estimates and judgements.

 

The payment terms for the Company's sales are due within 30 days. The Company does not expect to have any contracts where the period between the transfer of oil to the customer and the payment exceeds one year. Therefore, the transaction price is not adjusted for the time value of money.

 

The Company is not able to measure the tax that has been paid on its behalf and consequently revenue is not reported gross of income tax paid.

 

Intangible assets

Exploration and evaluation assets

Oil and gas assets classified as exploration and evaluation assets are explained under Oil and Gas assets below.

 

Tawke RSA

Intangible assets include the Receivable Settlement Agreement ('RSA') effective from 1 August 2017, which was entered into in exchange for trade receivables due from KRG for Taq Taq and Tawke past sales. The RSA was recognised at cost and is amortised on a units of production basis in line with the economic lives of the rights acquired.

Other intangible assets

Other intangible assets that are acquired by the Company are stated at cost less accumulated amortisation and less accumulated impairment losses. Amortisation is expensed on a straight-line basis over the estimated useful lives of the assets of between 3 and 5 years from the date that they are available for use.

 

Property, plant and equipment

Producing and Development assets

Oil and gas assets classified as producing and development assets are explained under Oil and Gas assets below.

 

Other property, plant and equipment

Other property, plant and equipment are principally the Company's leasehold improvements and other assets and are carried at cost, less any accumulated depreciation and accumulated impairment losses. Costs include purchase price and construction cost. Depreciation of these assets is expensed on a straight-line basis over their estimated useful lives of between 3 and 5 years from the date they are available for use.

 

Oil and gas assets

Costs incurred prior to obtaining legal rights to explore are expensed to the statement of comprehensive income.

 

Exploration, appraisal and development expenditure is accounted for under the successful efforts method. Under the successful efforts method only costs that relate directly to the discovery and development of specific oil and gas reserves are capitalised as exploration and evaluation assets within intangible assets so long as the activity is assessed to be de-risking the asset and the Company expects continued activity on the asset into the foreseeable future. Costs of activity that do not identify oil and gas reserves are expensed.

 

All licence acquisition costs, geological and geophysical costs and other direct costs of exploration, evaluation and development are capitalised as intangible assets or property, plant and equipment according to their nature. Intangible assets comprise costs relating to the exploration and evaluation of properties which the directors consider to be unevaluated until assessed as being 2P reserves and commercially viable.

 

Once assessed as being 2P reserves they are tested for impairment and transferred to property, plant and equipment as development assets. Where properties are appraised to have no commercial value, the associated costs are expensed as an impairment loss in the period in which the determination is made. Development assets are classified under producing assets following the commercial production commencement. 

 

Development expenditure is accounted for in accordance with IAS 16 - Property, plant and equipment. Producing assets are depreciated once they are available for use and are depleted on a field-by-field basis using the unit of production method. The sum of carrying value and the estimated future development costs are divided by total barrels to provide a $/barrel unit depreciation cost. Changes to depreciation rates as a result of changes in forecast production and estimates of future development expenditure are reflected prospectively.

 

The estimated useful lives of property, plant and equipment and their residual values are reviewed on an annual basis and changes in useful lives are accounted for prospectively. The gain or loss arising on the disposal or retirement of an asset is determined as the difference between the sales proceeds and the carrying amount of the asset and is recognised in the statement of comprehensive income for the relevant period.

 

Where exploration licences are relinquished or exited for no consideration or costs incurred are neither de-risking nor adding value to the asset, the associated costs are expensed to the income statement.

 

Impairment testing of oil and gas assets is considered in the context of each cash generating unit. A cash generating unit is generally a licence, with the discounted value of the future cash flows of the CGU compared to the book value of the relevant assets and liabilities. As an example, the Tawke CGU is comprised of the Tawke RSA intangible asset, property, plant and equipment (relating to both the Tawke field and the Peshkabir field) and the associated decommissioning provision.

 

Subsequent costs

The cost of replacing part of an item of property and equipment is recognised in the carrying amount of the item if it is probable that the future economic benefits embodied within the part will flow to the Company, and its cost can be measured reliably. The net book value of the replaced part is expensed. The costs of the day-to-day servicing and maintenance of property, plant and equipment are recognised in the statement of comprehensive income.

 

Business combinations

The recognition of business combinations requires the allocation of the excess of the purchase price of acquisitions over the net book value of assets acquired to the assets and liabilities of the acquired entity. The Company makes judgements and estimates in relation to the fair value allocation of the purchase price.

 

The fair value exercise is performed at the date of acquisition. Owing to the nature of fair value assessments in the oil and gas industry, the purchase price allocation exercise and acquisition date fair value determinations require subjective judgements based on a wide range of complex variables at a point in time. The Company uses all available information to make the fair value determinations.

 

In determining fair value for acquisitions, the Company utilises valuation methodologies including discounted cash flow analysis. The assumptions made in performing these valuations include assumptions as to discount rates, foreign exchange rates, commodity prices, the timing of development, capital costs, and future operating costs. Any significant change in key assumptions may cause the acquisition accounting to be revised.

 

Financial assets and liabilities

Classification

The Company assesses the classification of its financial assets on initial recognition at amortised cost, fair value through other comprehensive income or fair value through profit and loss. The Company assesses the classification of its financial liabilities on initial recognition at either fair value through profit and loss or amortised cost.

 

Recognition and measurement

Regular purchases and sales of financial assets are recognised at fair value on the trade-date - the date on which the Company commits to purchase or sell the asset. Trade and other receivables, trade and other payables, borrowings and deferred contingent consideration are subsequently carried at amortised cost using the effective interest method.

 

Trade and other receivables

Trade receivables are amounts due from crude oil sales, sales of gas or services performed in the ordinary course of business. If payment is expected within one year or less, trade receivables are classified as current assets otherwise they are presented as non-current assets. Trade receivables are recognised initially at fair value and subsequently measured at amortised cost using the effective interest method, less provision for impairment.

 

Under the Tawke, Taq Taq and Sarta PSCs, payment for entitlement is due within 30 days. The Company's assessment of impairment model based on expected credit loss is explained below under financial assets.

 

Cash and cash equivalents

In the consolidated balance sheet and consolidated statement of cash flows, cash and cash equivalents includes cash in hand, deposits held on call with banks, other short-term highly liquid investments and includes the Company's share of cash held in joint operations.

 

Interest-bearing borrowings

Borrowings are recognised initially at fair value, net of any discount in issuance and transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the statement of comprehensive income over the period of the borrowings using the effective interest method.

 

Fees paid on the establishment of loan facilities are recognised as transaction costs of the loan to the extent that it is probable that some or all of the facility will be drawn down. In this case, the fee is deferred until the draw-down occurs. To the extent there is no evidence that it is probable that some or all of the facility will be drawn down, the fee is capitalised as a pre-payment for liquidity services and amortised over the period of the facility to which it relates.

 

Borrowings are presented as long or short-term based on the maturity of the respective borrowings in accordance with the loan or other agreement. Borrowings with maturities of less than twelve months are classified as short-term. Amounts are classified as long-term where maturity is greater than twelve months. Where no objective evidence of maturity exists, related amounts are classified as short-term.

 

 

 

Trade and other payables

Trade and other payables are recognised initially at fair value. Subsequent to initial recognition they are measured at amortised cost using the effective interest method.

 

Offsetting

Financial assets and liabilities are offset and the net amount reported in the balance sheet when there is a legally enforceable right to offset the recognised amounts and there is an intention to settle on a net basis or realise the asset and settle the liability simultaneously.

 

Provisions

Provisions are recognised when the Company has a present obligation as a result of a past event, and it is probable that the Company will be required to settle that obligation. Provisions are measured at the Company's best estimate of the expenditure required to settle the obligation at the balance sheet date, and are discounted to present value where the effect is material. The unwinding of any discount is recognised as finance costs in the statement of comprehensive income.

 

Decommissioning

Provision is made for the cost of decommissioning assets at the time when the obligation to decommission arises. Such provision represents the estimated discounted liability for costs which are expected to be incurred in removing production facilities and site restoration at the end of the producing life of each field. A corresponding cost is capitalised to property, plant and equipment and subsequently depreciated as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure attributable to changes in the estimates of the cash flow or the current estimate of the discount rate used are reflected as an adjustment to the provision.

 

Impairment

Oil and gas assets

The carrying amounts of the Company's oil and gas assets are reviewed at each reporting date to determine whether there is any indication of impairment. If any such indication exists then the asset's recoverable amount is estimated. The recoverable amount of an asset or cash generating unit is the greater of its value in use and its fair value less costs of disposal. For value in use, the estimated future cash flows arising from the Company's future plans for the asset are discounted to their present value using a nominal post tax discount rate that reflects market assessments of the time value of money and the risks specific to the asset. For fair value less costs of disposal, an estimation is made of the fair value of consideration that would be received to sell an asset less associated selling costs (which are assumed to be immaterial). Assets are grouped together into the smallest group of assets that generates cash inflows from continuing use that are largely independent of the cash inflows of other assets or groups of assets (cash generating unit).

 

The estimated recoverable amount is then compared to the carrying value of the asset. Where the estimated recoverable amount is materially lower than the carrying value of the asset an impairment loss is recognised. Non-financial assets that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.

 

Property, plant and equipment and intangible assets

Impairment testing of oil and gas assets is explained above. When impairment indicators exist for other non-financial assets, impairment testing is performed based on the higher of value in use and fair value less costs of disposal. The Company assets' recoverable amount is determined by fair value less costs of disposal.

 

Financial assets

Impairment of financial assets is assessed under IFRS 9 with a forward-looking impairment model based on expected credit losses (ECLs). The standard requires the Company to book an allowance for ECLs for its financial assets. The Company has assessed its trade receivables as at 31 December 2020 for ECLs. Further explanation is provided in significant accounting judgements and estimates.

 

A financial asset is assessed at each reporting date to determine whether there is any objective evidence that it is impaired. A financial asset is considered to be impaired if objective evidence indicates that one or more events have had a negative effect on the estimate of future cash flows of that asset. An impairment loss in respect of a financial asset measured at amortised cost is calculated as the difference between its carrying amount, and the present value of the estimated future cash flows discounted at the original effective interest rate. All impairment losses are recognised as an expense in the statement of comprehensive income. An impairment loss is reversed if the reversal can be related objectively to an event occurring after the impairment loss was recognised.

Share capital

Ordinary shares are classified as equity.

 

When share capital recognised as equity is repurchased, the amount of the consideration paid, which includes directly attributable costs, is net of any tax effects and is recognised as a deduction in equity. Repurchased shares are classified as treasury shares and are presented as a deduction from total equity. When treasury shares are subsequently sold or reissued, the amount received is recognised as an increase in equity and the resulting surplus or deficit of the transaction is transferred to/from retained earnings.

 

Employee benefits

Short-term benefits

Short-term employee benefit obligations are expensed to the statement of comprehensive income as the related service is provided. A liability is recognised for the amount expected to be paid under short-term cash bonus or profit-sharing plans if the Company has a present legal or constructive obligation to pay this amount as a result of past service provided by the employee and the obligation can be estimated reliably.

 

Share-based payments

The Company operates equity-settled share-based compensation plans. The expense required in accordance with IFRS2 is recognised in the statement of comprehensive income over the vesting period of the award. The expense is determined by reference to option pricing models, principally Monte Carlo and adjusted Black-Scholes models.

 

At each balance sheet date, the Company revises its estimate of the number of options that are expected to become exercisable. Any revision to the original estimates is reflected in the statement of comprehensive income with a corresponding adjustment to equity immediately to the extent it relates to past service and the remainder over the rest of the vesting period.

 

Finance income and finance costs

Finance income comprises interest income on cash invested, foreign currency gains and the unwind of discount on any assets held at amortised cost. Interest income is recognised as it accrues, using the effective interest method.

 

Finance expense comprises interest expense on borrowings, foreign currency losses and discount unwind on any liabilities held at amortised cost. Borrowing costs directly attributable to the acquisition of a qualifying asset as part of the cost of that asset are capitalised over the respective assets.

 

Taxation

Under the terms of KRI PSC's, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. It is not known at what rate tax is paid, but it is estimated that the current tax rate would be between 15% and 40%. If this was known it would result in a gross up of revenue with a corresponding debit entry to taxation expense with no net impact on the income statement or on cash. In addition, it would be necessary to assess whether any deferred tax asset or liability was required to be recognised. Current tax expense is incurred on profits of service companies.

 

Segmental reporting

IFRS 8 requires the Company to disclose information about its business segments and the geographic areas in which it operates. It requires identification of business segments on the basis of internal reports that are regularly reviewed by the CEO, the chief operating decision maker, in order to allocate resources to the segment and assess its performance.

 

Related parties

Parties are related if one party has the ability, directly or indirectly, to control the other party or exercise significant influence over the party in making financial or operational decisions. Parties are also related if they are subject to common control. Transactions between related parties are transfers of resources, services or obligations, regardless of whether a price is charged and are disclosed separately within the notes to the consolidated financial information.

 

  

New standards

The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2020. Amendments to References to the Conceptual Framework in IFRS Standards, Amendments to IAS 1 and IAS 8: Definition of Material, Amendments to IFRS 9, IAS 39 and IFRS17: Interest Rate Benchmark Reform, Amendments to IFRS 3 Business Combinations, Amendment to IFRS 16 Leases Covid-19-Related Rent Concessions (1 Jun 2020). Nothing has been early adopted, and these standards are not expected to have a material impact on the Company's results or financials statement disclosures in the current or future reporting periods.

 

The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and have not yet been endorsed by the EU: IFRS 17 Insurance contracts (effective 1 Jan 2023), Amendments to IAS 1 Presentation of Financial Statements: Classification of Liabilities as Current or Non-current (1 Jan 2022), Amendments to IFRS 3 Business Combinations; IAS 16 Property, Plant and Equipment; IAS 37 Provisions, Contingent Liabilities and Contingent Assets; Annual Improvements 2018-2020 (1 Jan 2022), Amendments to IFRS 4 Insurance Contracts - deferral of IFRS19 (1 Jan 2021), Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 Interest Rate Benchmark Reform - Phase 2 (1 Jan 2021).

 

 

 

2. Segmental information

 

The Company has two reportable business segments: Production and Pre-production. Capital allocation decisions for the production segment are considered in the context of the cash flows expected from the production and sale of crude oil. The production segment is comprised of the producing fields on the Tawke PSC (Tawke and Peshkabir), the Taq Taq PSC (Taq Taq) and the Sarta PSC (Sarta) which are located in the KRI and make sales predominantly to the KRG. The pre-production segment is comprised of discovered resource held under the Qara Dagh PSC, the Bina Bawi PSC and the Miran PSC (all in the KRI) and exploration activity, principally located in Somaliland and Morocco. Sarta asset was transferred from pre-production to production following the production commencement close to the end of the year, whereas capital expenditure incurred for the development of the field until production commenced is reported under pre-production segment. 'Other' includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

 

 

For the period ended 31 December 2020

 

 

Production

 

Pre-production

 

Other

Total

 

$m

$m

$m

$m

Revenue from contracts with customers

155.0

 -  

 -  

 155.0

Revenue from other sources

 4.7

 -  

 -  

 4.7

Cost of sales

 (186.0)

 -  

 -  

 (186.0)

Gross loss

 (26.3)

 -  

 -  

 (26.3)

 

 

 

 

 

Exploration expense

 -  

 (2.2)

 -  

 (2.2)

Impairment of intangible asset

 (44.3)

 -  

 -  

 (44.3)

Impairment of property, plant and equipment

 (242.0)

 -  

 -  

 (242.0)

Impairment of receivables

 (34.9)

 -  

(2.0)  

 (36.9)

General and administrative costs

 -  

 -  

 (12.8)

 (12.8)

Operating loss 

 (347.5)

 (2.2)

 (14.8)

 (364.5)

 

 

 

 

 

Operating loss is comprised of

 

 

 

 

EBITDAX

 127.0

 -

 (12.4)

 114.6

Depreciation and amortisation

 (153.3)

 -

 (0.4)

 (153.7)

Exploration expense

 -  

 (2.2)

 -  

 (2.2)

Impairment of intangible assets

 (44.3)

 -  

 -  

 (44.3)

Impairment of property, plant and equipment

 (242.0)

 -  

 -  

 (242.0)

Impairment of receivables

 (34.9)

-

(2.0)

 (36.9)

 

 

 

 

 

Finance income

 -  

 -  

 2.0

2.0

Bond interest expense

 -  

 -  

 (31.5)

 (31.5)

Other finance expense

 (1.6)

 (0.3)

 (20.8)

 (22.7)

Loss before income tax

 (349.1)

 (2.5)

 (65.1)

 (416.7)

 

 

 

 

 

 

 

 

 

 

Capital expenditure

 56.5

 53.2

 -  

 109.7

Total assets

 672.5

 539.0

 339.1

 1,550.6

Total liabilities

 (146.3)

 (98.2)

 (376.3)

 (620.8)

 

 

 

 

 

 

 

 

 

 

Revenue from contracts with customers includes $14.7 million (2019: $104.3 million) arising from the ORRI, which is explained further in note 1. The ORRI was suspended from March 2020 to December 2020 and consequently no revenue has been recognised relating to this period.

 

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

 

 

 

 

 

For the period ended 31 December 2019

 

 

 

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)

 

 

 

 

 

 

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


3. Cost of sales

 

2020

2019

 

$m

$m

Operating costs

 (32.6)

(37.7)

Trucking costs

(0.1)

-

Production cost

(32.7)

(37.7)

Depreciation of oil and gas property, plant and equipment

 (98.7)

(88.8)

Amortisation of oil and gas intangible assets

 (54.6)

(68.3)

Cost of sales

 (186.0)

(194.8)

 

 

 

Exploration expense

(2.2)

(1.2)

Impairment of intangible assets (note 8)

(44.3)

-

Impairment of property, plant and equipment (note 9)

(242.0)

(29.8)

Impairment of receivables (note 10)

(36.9)

-

 

 

 

 

 

 

Corporate cash costs

(9.6)

(13.3)

Other operating expenses

(1.8)

(0.8)

Corporate share-based payment expense

(1.0)

(3.6)

Depreciation and amortisation of corporate assets

(0.4)

(1.4)

General and administrative expenses

(12.8)

(19.1)

 

 

 

Exploration expense relates to spend and accruals for costs or obligations relating to licences where there is ongoing activity or that have been, or are in the process of being, relinquished.

 

Trucking costs are not cost-recoverable and relate to the Sarta licence only, where production is in its early stages.

 

 

Fees payable to the Company's auditors:

 

2020

2019

 

 

$m

$m

 

Audit of consolidated and subsidiary financial statements

(0.6)

(0.7)

 

Tax and advisory services

(0.6)

(0.2)

 

Total fees

(1.2)

(0.9)

 

 

 

 

       

 

4. Staff costs and headcount

 

 

2020

2019

 

$m

$m

Wages and salaries

(21.9)

(18.6)

Contractors costs

(7.7)

(1.6)

Social security costs

(2.0)

(1.6)

Share based payments

(5.8)

(5.8)

 

(37.4)

(27.6)

 

Staff costs include cost of contractors.

 

Average headcount was:

 

2020 number

2019 number

Turkey

56

62

KRI

21

18

UK

33

24

Somaliland

17

17

Contractors

38

28

 

165

149

 

 

5. Finance expense and income 

 

2020

2019

 

$m

$m

Bond interest paid

 (25.8)

(30.0)

Bond interest accrued

(5.7)

-

Accelerated cost of bond settlement (see note 15)

(19.4)

-

Other finance expense (non-cash)

 (3.3)

(4.3)

Finance expense

(54.2)

(34.3)

 

 

 

Bank interest income

2.0

6.6

Finance income

2.0

6.6

 

 

 

Net finance expense

(52.2)

(27.7)

 

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

 

 

6. Income tax expense

 

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

 

 

7. (Loss) / earnings per share

 

Basic

Basic (loss) / earnings per share is calculated by dividing the (loss) / profit attributable to owners of the parent by the weighted average number of shares in issue during the period.

 

 

2020

2019

 

 

 

(Loss) / Profit attributable to owners of the parent ($m)

(416.9)

103.9

 

 

 

Weighted average number of ordinary shares - number 1

274,202,853

275,197,007

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

(152.0)

37.8

1 Excluding shares held as treasury shares

 

Diluted

The Company purchases shares in the market to satisfy share plan requirements so diluted earnings per share is adjusted for performance shares, restricted shares and share options not included in the calculation of basic earnings per share. Because the Company reported a loss for the year ended 31 December 2020, diluted EPS is anti-dilutive and therefore diluted EPS is the same as basic EPS:

 

 

2020

2019

 

 

 

(Loss) / Profit attributable to owners of the parent ($m)

(416.9)

103.9

 

 

 

Weighted average number of ordinary shares - number1

274,202,853

275,197,007

Adjustment for performance shares, restricted shares and share options

-

5,859,457

Weighted average number of ordinary shares and potential ordinary shares

274,202,853

281,056,464

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

(152.0)

37.0

1 Excluding shares held as treasury shares 

 

  

 

8. Intangible assets

 

Exploration and evaluation assets

 

Tawke

RSA

Other

assets

Total

 

$m

$m

$m

$m

Cost

 

 

 

 

At 1 January 2019

1,493.2

425.1

6.8

1,925.1

Additions

20.9

-

0.5

21.4

Discount unwind of contingent consideration

5.2

-

-

5.2

Other

(0.8)

-

-

(0.8)

At 31 December 2019 and 1 January 2020

1,518.5

425.1

7.3

1,950.9

 

 

 

 

 

Additions

23.2

-

0.1

23.3

Other

(0.2)

-

-

(0.2)

At 31 December 2020

 1,541.5

 425.1

 7.4

 1,974.0

 

 

 

 

 

Accumulated amortisation and impairment

 

 

 

 

At 1 January 2019

 (1,005.3)

 (94.9)

 (6.5)

 (1,106.7)

Amortisation charge for the period

 -  

 (68.3)

 (0.3)

 (68.6)

At 31 December 2019 and 1 January 2020

 (1,005.3)

 (163.2)

 (6.8)

 (1,175.3)

 

 

 

 

 

Amortisation charge for the period

 -  

 (54.6)

 (0.4)

 (55.0)

Impairment

-

 (44.3)

 -  

 (44.3)

At 31 December 2020

 (1,005.3)

 (262.1)

 (7.2)

 (1,274.6)

 

 

 

 

 

Net book value

 

 

 

 

At 31 December 2019

513.2

261.9

0.5

775.6

At 31 December 2020

 536.2

 163.0

 0.2

 699.4

 

Tawke RSA asset was impaired by $44.3 million, further explanation is provided in note 1.

 

 

 

2020

2019

Book value

 

$m

$m

Bina Bawi PSC

Discovered gas and oil, appraisal

360.5

352.9

Miran PSC

Discovered gas and oil, appraisal

123.2

120.3

Somaliland PSC

Exploration

34.7

33.8

Qara Dagh PSC

Exploration / Appraisal

17.8

6.2

Exploration and evaluation assets

 

536.2

513.2

 

 

 

 

Tawke overriding royalty

 

73.3

160.2

Tawke capacity building payment waiver

89.7

101.7

Tawke RSA assets

 

163.0

261.9

 

 

Sensitivity of the Tawke CGU is provided in note 9. The Miran intangible asset is most sensitive to timing of its commercialisation. The table below shows the indicative sensitivity of the Bina Bawi CGU net present value to changes to long term Brent, discount rate or production and reserves, assuming no change to other inputs.

 

 

 

$m

Long term Brent +/- $5/bbl

 

 

+/- 13

Discount rate +/-2.5%

 

 

+/- 101

Production and reserves +/- 10%

 

 

+/- 32

 

 

 

 

 

 

 

 

9. Property, plant and equipment

 

 

Producing assets

Development assets

Other

assets

 

Total

 

$m

$m

$m

$m

Cost

 

 

 

 

At 1 January 2019

 2,757.2

 -  

 9.6

 2,766.8

Asset acquisitions

-

49.4

-

49.4

Additions

115.1

22.1

0.3

137.5

Right-of-use assets

-

-

3.6

3.6

Net change in payable

-

(3.6)

-

(3.6)

Non-cash additions for ARO/SBP1

3.8

0.1

-

3.9

At 31 December 2019 and 1 January 2020

2,876.1

68.0

13.5

2,957.6

 

 

 

 

 

Additions

56.5

30.0

1.0

87.5

Right-of-use assets (note 19)

-

-

8.1

8.1

Net change in payable

-

(5.4)

-

(5.4)

Non-cash additions for ARO/SBP/Production bonus

2.3

8.8

-

11.1

Transfer to producing assets

101.4

(101.4)

-

-

At 31 December 2020

3,036.3

-

22.6

3,058.9

 

 

 

 

 

Accumulated depreciation and impairment

 

 

 

 

At 1 January 2019

(2,192.1)

-

(8.9)

(2,201.0)

Depreciation charge for the period

(88.8)

-

(1.1)

(89.9)

Impairment

(29.8)

-

-

(29.8)

At 31 December 2019 and 1 January 2020

(2,310.7)

-

(10.0)

(2,320.7)

 

 

 

 

 

Depreciation charge for the period

 (98.7)

-  

 (1.8)

 (100.5)

Impairment

 (242.0)

 -  

-

 (242.0)

At 31 December 2020

 (2,651.4)

 -

 (11.8)

(2,663.2)

 

 

 

 

 

Net book value

 

 

 

 

At 31 December 2019

565.4

68.0

3.5

636.9

At 31 December 2020

 384.9

 -

 10.8

 395.7

 

1 ARO: Asset retirement obligation, SBP: Share-based payment  

 

Sarta asset was transferred from development assets to producing assets following the commencement of production from the field.

 

 

 

2020

2019

Book value

 

$m

$m

Tawke PSC

Oil production

228.2

474.9

Taq Taq PSC

Oil production

56.2

90.5

Sarta PSC

Oil production/development

100.5

68.0

Producing assets

 

384.9

633.4

 

 

 

 

 

The sensitivities below provide an indicative impact on net asset value of a change in long term Brent, discount rate or production and reserves, assuming no change to any other inputs.

 

Taq Taq

CGU

$m

Tawke CGU

$m

Long term Brent +/- $5/bbl

+/- 2

+/- 16

Discount rate +/- 2.5%

+/- 3

+/- 37

Production and reserves +/- 10%

+/- 4

+/- 39

 

 

 

10. Trade and other receivables

 

2020

2019

 

$m

$m

Trade receivables - current

41.9

150.2

Trade receivables - non-current

52.1

-

Other receivables and prepayments

7.0

7.2

 

101.0

157.4

 

Under the Tawke, Taq Taq and Sarta PSCs, payment for entitlement is due within 30 days. Since February 2016, there was a track record of payments being received three months after invoicing, which was previously assessed as the operating cycle under IAS1. Since April 2020 the KRG has been settling invoices within one month of invoicing, which is now assessed as the operating cycle under IAS1.

 

 

 

Year of sale of

 

amounts overdue

 

Not due

2020

2019

Total overdue

$m

$m

$m

$m

Trade receivables at 31 December 2019 (nominal)

98.8

n/a

54.1

54.1

Trade receivables at 31 December 2020 (nominal)

       14.8

       55.4

  65.4

120.8

 

 

At 31 December 2020, $120.8 million relating to invoices from November 2019 to February 2020 was overdue and at the half year required impairment of $34.9 million as explained in note 1.

 

Movement on trade receivables in the period

2020

$m

2019

$m

Carrying value at 1 January

150.2

94.8

Revenue from contracts with customers

155.0

368.7

Cash proceeds

(173.4)

(317.4)

Offset of payables due to the KRG

(5.5)

-

Expected credit loss

(34.9)

(0.5)

Capacity building payments

2.6

4.6

Carrying value at 31 December

94.0

150.2

 

 

Recovery of the carrying value of the receivable

The Company expects to recover the full nominal value of $120.8 million receivables owed from the KRG, but the terms of recovery are not finalised. Explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 1.

 

 

Total

$m

Nominal balance to be recovered

120.8

Estimated net present value of total cash flows

85.9

 

Sensitivities

The table below shows the sensitivity of the net present value of the overdue trade receivables to oil price, assuming flat production and payment is received in line with the mechanism proposed by the KRG in December 2020.

 

Nominal receivables ($m)

Timing of repayment

Total

NPV13.0

Year 1

Year 2

Year 3

Year 4

Brent

$55/bbl

30.0

30.0

30.0

30.8

120.8

89.6

$60/bbl

60.0

60.8

-

-

120.8

100.6

$65/bbl

90.0

30.8

-

-

120.8

103.8

$70/bbl

120.8

-

-

-

120.8

106.8

 

 

 

11. Cash and cash equivalents and restricted cash

 

2020

2019

 

$m

$m

Cash and cash equivalents

 354.5

390.7

Restricted cash

-

3.0

 

354.5

393.7

 

Cash is primarily held on time deposit with major international financial institutions or in US Treasury bills.

 

 

12. Trade and other payables

 

2020

2019

 

$m

$m

Trade payables

16.7

10.3

Other payables

128.1

144.4

Accruals

54.6

55.8

 

199.4

210.5

 

 

 

Non-current

100.4

118.8

Current

99.0

91.7

 

199.4

210.5

 

 

 

Current payables are predominantly short-term in nature or are repayable on demand and, as such, for these payables there is minimal difference between contractual cash flows related to the financial liabilities and their carrying amount.  For non-current payables, liabilities are recognised at discounted fair value using the effective interest rate, with the unwind either expensed as finance cost or capitalised against the relevant asset. Other payables include a balance of $73.7 million (2019: $73.7 million) recognised at its discounted fair value using the effective interest rate, which has been added to the book value of Bina Bawi intangible asset. The nominal value of this balance is $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. It has been recognised at its discounted fair value using the effective interest rate, which has been added to the book value of the Sarta asset. Lease liabilities are included in other payables, further explanation is provided in note 19.

 

 

13. Deferred income

 

2020

2019

 

$m

$m

Non-current

19.7

26.7

Current

7.5

5.0

 

27.2

31.7

 

 

 

14. Provisions

 

2020

2019

 

$m

$m

Balance at 1 January

37.4

32.9

Interest unwind

1.5

1.3

Additions

7.0

3.2

Balance at 31 December

45.9

37.4

 

 

 

Provisions cover expected decommissioning and abandonment costs arising from the Company's assets. The decommissioning and abandonment provision are based on the Company's best estimate of the expenditure required to settle the present obligation at the end of the period inflated at 2% (2019: 2%) and discounted at 4% (2019: 4%). The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2028 and 2038.

 

 

 

 

15. Interest bearing loans and net cash

 

 

 

1 Jan 2020

 

Discount unwind

 

Buyback / Issuance

Purchase of own bonds

 

Net other changes

 

31 Dec 2020

 

$m

$m

$m

$m

$m

$m

2022 Bond 10.0% (current)

(297.9)

(0.5)

221.7

-

(3.9)

(80.6)

2025 Bond 9.25% (non-current)

-

(0.3)

(286.8)

-

-

(287.1)

Own bonds held (non-current)

-

-

-

19.4

-

19.4

Cash

390.7

-

28.9

-

(65.1)

354.5

Net cash

92.8

(0.8)

(36.2)

19.4

(69.0)

6.2

 

In October 2020, the Company issued a new $300 million senior unsecured bond with maturity in October 2025. The new bond has a fixed coupon of 9.25% per annum. In connection with the issue, the Company repurchased $222.9 million of its existing $300.0 million senior unsecured bond issue with maturity date in December 2022 at a price of 107. On 22 December 2020, the Company wrote to the Trustees confirming that they were exercising the right to call the remaining $77.1 million of the 2022 bond at the call price of 105. This settlement completed on 8 January 2021.

 

At 31 December 2020, the fair value of the nominal $77.1 million of 2022 bonds is $81.0 million and of the nominal $280.0 million of 2025 bonds held by third parties is $291.0 million (2019: $316.5 million).

 

 

1 Jan 2019

Discount unwind

Net change

in cash

31 Dec 2019

 

$m

$m

$m

$m

2022 Bond 10.0%

(297.3)

(0.6)

-

(297.9)

Cash

334.3

-

56.4

390.7

Net Cash

37.0

(0.6)

83.8

92.8

 

 

16. Financial Risk Management

 

Credit risk

Credit risk arises from cash and cash equivalents, trade and other receivables and other assets. The carrying amount of financial assets represents the maximum credit exposure. The maximum credit exposure to credit risk at 31 December was:

 

2020
$m

2019
$m

Trade and other receivables

98.3

155.3

Cash and cash equivalents

354.5

390.7

 

452.8

546.0

 

All trade receivables are owed by the KRG. Cash is deposited with the US treasury or term deposits with banks that are assessed as appropriate based on, among other things, sovereign risk, CDS pricing and credit rating.

 

Liquidity risk

The Company is committed to ensuring it has sufficient liquidity to meet its payables as they fall due. At 31 December 2020 the Company had cash and cash equivalents of $273.5 million (2019: $390.7 million) adjusted for settlement of bond debt post-year end.

 

Oil price risk

The Company's revenues are calculated from Dated Brent oil price, and a $5/bbl change in average Dated Brent would result in a (loss) / profit before tax change of circa $15 million. Sensitivity of the carrying value of its assets to oil price risk is provided in notes 8 and 9.

 

Currency risk

Other than head office costs, substantially all of the Company's transactions are denominated and/or reported in US dollars. The exposure to currency risk is therefore immaterial and accordingly no sensitivity analysis has been presented.

 

Interest rate risk

The Company reported borrowings of $348.3 million (2019: $297.9 million) in the form of a bond maturing in December 2022, with fixed coupon interest payable of 10% on the nominal value of $77.1 million and a bond maturing in October 2025, with fixed coupon interest payable of 9.25% on the nominal value of $280.0 million. Although interest is fixed on existing debts, whenever the Company wishes to borrow new debt or refinance existing debt, it will be exposed to interest rate risk. A 1% increase in interest rate payable on a balance similar to the existing debts of the Company would result in an additional cost of circa $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 $354.5 million (2019: $390.7 million).

 

 

17. Share capital

 

Total

 Ordinary Shares

 

 

At 1 January 2019 - fully paid1

280,248,198

 

 

At 31 December 2019, 1 January 2020 and 31 December 2020 - fully paid1

280,248,198

 

 

   

1 Ordinary shares include 2,577,720 (2019: 2,577,720) treasury shares. Share capital includes 3,236,109 (2019: 4,303,249) of trust shares.

 

There have been no changes to the authorised share capital since it was determined to be 10,000,000,000 ordinary shares of £0.10 per share.

 

 

18. Dividends

 

 

2020

2019

 

$m

$m

Ordinary shares

 

 

Final dividend of 10¢ per share

28.0

27.6

Interim dividend of 5¢ per share

13.5

13.2

Total dividends provided for or paid

41.5

40.8

 

 

 

Paid in cash

55.3

27.4

Movement in payable

(13.2)

13.2

Foreign exchange (expense) / income on dividend paid

(0.6)

0.2

Total dividends provided for or paid

41.5

40.8

 

 

 

 

19. Right-of-use assets / Lease liabilities

 

The Company's right-of-use assets are related to the Sarta early production facility, office, car, warehouse leases and included within property, plant and equipment. The Company has elected to apply the exemptions for short-term and low-value leases.

 

Drill rig contracts are service contracts where contractors provide the rig together with the services and the contracted personnel on a day-rate basis for the purpose of drilling exploration or development wells. The Company has no right of use of the rigs. The aggregate payments under drilling contracts are determined by the number of days required to drill each well and are capitalised as exploration or development assets as appropriate.

 

 

 

Right-of-use assets
$m

Cost

 

At 1 January 2019

 1.9

Additions

1.7

At 31 December 2019 and 1 January 2020

 3.6

Additions

8.4

Disposals due to terminations

(0.3)

At 31 December 2020

11.7

 

 

Accumulated depreciation

 

At 1 January 2019

-

Depreciation charge for the period

(0.9)

At 31 December 2019 and 1 January 2020

(0.9)

Depreciation charge for the period

(1.3)

At 31 December 2020

(2.2)

 

 

Net book value

 

At 31 December 2019

2.7

At 31 December 2020

9.5

 

 

 

 

2020

2019

Book value

 

$m

$m

Office

 

2.4

2.6

Warehouse

 

-

0.1

Production facility

 

7.1

-

Right-of-use assets

 

9.5

2.7

 

 

Lease liabilities were measured at the present value of the remaining lease payments, discounted using the lessee's incremental borrowing rate and included within trade and other payables. The weighted average lessee's incremental borrowing rate applied to the lease liabilities except Sarta early production facility was 2.5%. 4% was applied for the facility. Right-of-use assets are depreciated over the lifetime of the related lease contract. The lease terms vary from one to five years.

 

 

2020
$m

2019
$m

 

 

 

At 1 January

(3.0)

(1.9)

Additions

(8.4)

(1.7)

Disposals due to terminations

0.4

-

Payments of lease liabilities

1.3

0.6

Interest expense on lease liabilities

(0.1)

-

At 31 December (note 12)

(9.8)

(3.0)

 

 

 

Included within lease liabilities of $9.8 million (2019: $3.0 million) are non-current lease liabilities of $6.8 million (2019: $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. 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

 

 

 

 

 

 

31 December 2019

(1.0)

(0.8)

(1.4)

(3.2)

(3.0)

31 December 2020

(3.3)

(3.4)

(4.0)

(10.7)

(9.8)

20. Share based payments

 

The Company has three share-based payment plans: a performance share plan, restricted share plan and a share option plan. The main features of these share plans are set out below.

 

Key features

 

PSP

 

RSP

 

SOP

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 2020, awards were made under the performance share plan and restricted share plan, no awards were made under the share option plan, the numbers of outstanding shares under the PSP, RSP and SOP as at 31 December 2020 are set out below:

 

 

PSP

(nil cost)

 

RSP

(nil cost)

Share option plan

SOP

weighted avg. exercise price

 

Outstanding at 1 January 2019

10,148,551

1,511,298

132,334

803p

 

Granted during the year

1,930,702

850,408

-

-

 

Dividend equivalents

592,675

84,657

-

-

 

Forfeited during the year

(2,439,495)

-

-

-

 

Lapsed during the year

(241,580)

(18,251)

(12,746)

742p

 

Exercised during the year

-

(704,568)

-

-

 

Outstanding at 31 Dec 2019 and 1 Jan 2020

9,990,853

1,723,544

119,588

810p

 

Granted during the year

4,041,711

598,039

-

-

 

Dividend equivalents

641,685

120,450

-

-

 

Forfeited during the year

(1,569,870)

-

-

-

 

Lapsed during the year

(279,283)

(2,194)

(31,764)

788p

 

Exercised during the year

(2,778,121)

(280,347)

-

-

 

Outstanding at 31 December 2020

10,046,975

2,159,492

87,824

817p

 

 

 

 

 

 

               

The range of exercise prices for share options outstanding at the end of the period is 742.00p to 1,046.00p.

 

Fair value of awards granted during the year has been measured by use of the Monte-Carlo pricing model. The model takes into account assumptions regarding expected volatility, expected dividends and expected time to exercise. Expected volatility was also analysed with the historical volatility of FTSE-listed oil and gas producers over the three years prior to the date of grant. The expected dividend assumption was set at 0%. The risk-free interest rate incorporated into the model is based on the term structure of UK Government zero coupon bonds. The inputs into the fair value calculation for RSP and PSP awards granted in 2020 and fair values per share using the model were as follows:

 

 

RSP

22/06/2020

PSP

22/06/2020

Share price at grant date

 

119p

119p

Exercise price

 

-

-

Fair value on measurement date

 

119p

107p

Expected life (years)

 

1-3

3-6

Expected dividends

 

-

-

Risk-free interest rate

 

0.04%

0.04%

Expected volatility

 

64.50%

64.50%

Share price at balance sheet date

 

144p

144p

Change in share price between grant date and 31 December 2020

 

21%

21%

 

The weighted average fair value for RSP awards granted in 2020 is 119p and for PSP awards granted in 2020 is 107p.

 

The inputs into the fair value calculation for RSP and PSP awards granted in 2019 and fair values per share using the model were as follows:

 

 

 

RSP

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 2019 is 129p and for RSP awards granted in 2019 is 206p.

 

Total share-based payment charge for the year was $5.8 million (2019: $5.8 million).

 

 

21. Capital commitments

 

Under the terms of its production sharing contracts ('PSC's) and joint operating agreements ('JOA's), the Company has certain commitments that are generally defined by activity rather than spend. The Company's capital programme for the next few years is explained in the operating review and is in excess of the activity required by its PSCs and JOAs. 

 

 

22. Related parties

 

The directors have identified related parties of the Company under IAS 24 as being: the shareholders; members of the Board; and members of the executive committee, together with the families and companies, associates, investments and associates controlled by or affiliated with each of them. The compensation of key management personnel including the directors of the Company is as follows:

 

 

 

2020
$m

2019
$m

Board remuneration

 

1.0

0.7

Key management emoluments and short-term benefits

 

7.6

5.6

Share-related awards

 

2.5

0.6

 

 

11.1

6.9

 

There have been no changes in related parties since last year and no related party transactions that had a material effect on financial position or performance in the year. There are not significant seasonal or cyclical variations in the Company's total revenues.

 

 

23. Events occurring after the reporting period

 

None.

 

 

24. Subsidiaries and joint arrangements

 

The Company has four joint arrangements in relation to its producing assets Taq Taq, Tawke, Sarta and pre-production asset Qara Dagh. The Company holds 44% working interest in Taq Taq PSC and owns 55% of Taq Taq Operating Company Limited. The Company holds 25% working interest in Tawke PSC which is operated by DNO ASA. The Company holds 30% working interest in Sarta PSC which is operated by Chevron. The Company holds 40% working interest in Qara Dagh PSC which is operated by the Company.

 

For the period ended 31 December 2020 the principal subsidiaries of the Company were the following:

 

Entity name

 

Country of Incorporation

 

Ownership % (ordinary shares)

Barrus Petroleum Cote D'Ivoire Sarl1

 

Cote d'Ivoire

 

100

Barrus Petroleum Limited2

 

Isle of Man

 

100

Genel Energy Africa Exploration Limited3

 

UK

 

100

Genel Energy Finance 2 Limited4

 

Jersey

 

100

Genel Energy Finance 4 plc3

 

UK

 

100

Genel Energy Finance plc (in liquidation)5

 

UK

 

100

Genel Energy Gas Company Limited4

 

Jersey

 

100

Genel Energy Holding Company Limited4

 

Jersey

 

100

Genel Energy International Limited6

 

Anguilla

 

100

Genel Energy Miran Bina Bawi Limited3

 

UK

 

100

Genel Energy Morocco Limited3

 

UK

 

100

Genel Energy No. 6 Limited3

 

UK

 

100

Genel Energy Petroleum Services Limited3

 

UK

 

100

Genel Energy Qara Dagh Limited3

 

UK

 

100

Genel Energy Sarta Limited3

 

UK

 

100

Genel Energy Somaliland Limited3

 

UK

 

100

Genel Energy UK Services Limited3

 

UK

 

100

Genel Energy 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 12 Castle Street, St Helier, JE2 3RT, Jersey

5 Registered office is 3 Field Court, London, WC1R 5EF

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

7 Registered office is Sehit Omer Haluk Sipahioglu Sokak (Eski Noktali Sokak) No:1 Sheraton Lugal Ofisleri Daire: 21 Kavaklidere 06700, Ankara, Turkey

8 Registered office is PO Box 146, Road Town, Tortola, British Virgin Islands

9 Registered office is 3rd Floor, Geneva Place, Waterfront Drive, PO Box 3175, Road Town, Tortola, Virgin Islands, British

 

 

25. Annual report

 

Copies of the 2020 annual report will be despatched to shareholders in April 2021 and will also be available from the Company's registered office at 12 Castle Street, St Helier, Jersey JE2 3RT and at the Company's website - www.genelenergy.com.

 

 

 

26. Statutory financial statements

 

The financial information for the year ended 31 December 2020 contained in this preliminary announcement has been audited and was approved by the board on 17 March 2021. The financial information in this statement does not constitute the Company's statutory financial statements for the years ended 31 December 2020 or 2019. The financial information for 2020 and 2019 is derived from the statutory financial statements for 2019, which have been delivered to the Registrar of Companies, and 2020, which will be delivered to the Registrar of Companies and issued to shareholders in April 2021. The auditors have reported on the 2020 and 2019 financial statements; their report was unqualified and did not include a reference to any matters to which the auditors drew attention by way of emphasis without qualifying their report. The statutory financial statements for 2020 are prepared in accordance with International Financial Reporting Standards (IFRS) as adopted for use in the European Union. The accounting policies (that comply with IFRS) used by Genel Energy plc are consistent with those set out in the 2019 annual report.



ISIN: JE00B55Q3P39, NO0010894330
Category Code: FR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 95778
EQS News ID: 1176494

 
End of Announcement EQS News Service

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