Genel Energy PLC

Half-Year Results

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

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


3 August 2021

Genel Energy plc

Unaudited results for the period ended 30 June 2021

 

Genel Energy plc ('Genel' or 'the Company') announces its unaudited results for the six months ended 30 June 2021.

 

Bill Higgs, Chief Executive of Genel, said:

"Genel continues to deliver on its strategy and demonstrate the merits of its business model. Capital investment made last year, despite the low oil price and over $150 million of deferred payments, has meant this period has benefitted from the addition of oil from Sarta and increased production from Peshkabir, with production having increased in line with guidance. This high-margin production will generate sufficient cash flow in 2021 to more than cover investment in growth and the increased dividend, and we are set to end the year in a net cash position.

 

Our appraisal campaign at our exciting growth assets Sarta and Qara Dagh is now well underway, and we look forward to the results of three of these high-potential wells later this year. Given the cash generation of the business, our strong balance sheet, and the resilience of our business model, we are fulfilling our aim of paying a progressive dividend by increasing the interim payment."

 

Results summary ($ million unless stated)

 

H1 2021

H1 2020

FY 2020

Average Brent oil price ($/bbl)

65

40

42

Production (bopd, working interest)

 32,760

32,100

 31,980

Revenue

 151.5

88.4

 159.7

EBITDAX1

 123.1

65.1

 114.6

  Depreciation and amortisation

 (81.8)

(82.6)

 (153.7)

  Exploration expense

-

(1.3)

(2.2)

  Impairment of oil and gas assets

-

(286.3)

(286.3)

  Impairment of receivables

-

(34.9)

(36.9)

Operating profit / (loss)

41.3

(340.0)

(364.5)

Cash flow from operating activities

91.1

85.5

129.4

Capital expenditure

58.2

58.5

109.7

Free cash flow2

22.2

6.5

(4.4)

Cash

266.4

355.3

354.5

Total debt

280.0

300.0

280.0

Net (debt) / cash3

(2.2)

57.2

6.2

Basic EPS (¢ per share)

9.3

(128.9)

(152.0)

Dividends declared for the period (¢ per share)

6

5

15

 

 

 

 

  1. EBITDAX is operating profit / (loss) adjusted for the add back of depreciation and amortisation, exploration expense, impairment of property, plant and equipment, impairment of intangible assets and impairment of receivables
  2. Free cash flow is reconciled on page 10
  3. Reported cash less IFRS debt (page 11)

 

Highlights

  • Strong cash generation from low-cost oil production:
    • Net production averaged 32,760 bopd in H1 2021, slightly above the average in the prior year and in line with guidance (H1 2020: 32,100 bopd)
    • Low production cost of $3.7/bbl, oil price increase, and restart of the override helped deliver an overall margin from our production assets of $111 million
    • Free cash flow for the period was $22 million, despite the Kurdistan Regional Government ('KRG') changing its payment schedule from one to two months in arrears, moving c.$30 million that was due in H1 into July
    • $123 million of cash proceeds were received in H1 2021 (H1 2020: $110 million)
  • Investing in growth:
    • Our high-potential drilling campaign is well underway, with the QD-2 well at Qara Dagh having spud in April, and the Sarta-5 well in June
    • $58 million of capital expenditure in H1 2021, with activity accelerating in H2
  • Financial strength to underpin a material and progressive dividend:
    • Cash of $266 million, with net debt of $2.2 million
    • Due to the rise in the oil price boosting expected cash generation, and Management's confidence in Genel's future prospects, interim dividend increased to 6¢ per share (H1 2020: 5¢ per share) 
  • A socially responsible contributor to the global energy mix:
    • Zero lost time injuries ('LTI') and zero tier one loss of primary containment ('LOPC') events at Genel and TTOPCO operations. Now no LTIs since 2015, with over 14 million work hours since the last incident, and no LOPCs since 2017
    • Second GRI compliant Sustainability Report issued today

 

Outlook

  • Production guidance for 2021 of slightly above the 2020 average of 31,980 bopd maintained
  • 2021 capital expenditure guidance maintained at $150 million to $200 million, with the expectation that expenditure will now be around the middle of this range, following delays in approvals from the KRG and ongoing challenges relating to COVID-19 causing some planned activity to move to Q1 2022
  • High-impact appraisal results to come in 2021:
    • Results from the QD-2 and Sarta-5 wells are expected around the end of Q3 2021
    • The Sarta-1D well is set to spud in coming days
    • Sarta-6 well is scheduled to get underway immediately following the completion of drilling at Sarta-5
  • Genel expects to generate free cash flow in 2021 and end the year in a net cash position, despite material investment in growth

 

Enquiries:

 

Genel Energy

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

 

Genel is pleased to announce the appointment of Jefferies as Joint Corporate Broker to the Company, effective immediately. Jefferies will work alongside J.P. Morgan Cazenove, Genel's current Joint Corporate Broker.

 

This announcement includes inside information.

 

Disclaimer

This announcement contains certain forward-looking statements that are subject to the usual risk factors and uncertainties associated with the oil & gas exploration and production business. Whilst the Company believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. Accordingly, no reliance may be placed on the figures contained in such forward looking statements. The information contained herein has not been audited and may be subject to further review.

 

 

CEO STATEMENT

We have a business model that is designed to be resilient in tough times, and to thrive when times are good. 2020 was a challenging year, but our resilience allowed us to continue strategic execution that paved the way for an exciting year in 2021. While the increase in the oil price has therefore been very welcome, boosting our revenues and cash generation, it does not change our strategy. This remains simple - increase low-cost production, invest in growth, and pay a material and progressive dividend. We continue to deliver on this strategy.

 

Executing our strategy

In line with guidance, our production has increased slightly year-on-year. This has been driven by the addition of a fourth producing field at Sarta, as we further strengthen our position as the most diversified producer in the Kurdistan Region of Iraq ('KRI'). Production at the Tawke PSC also remains robust, with Peshkabir in particular continuing to perform very well.

 

Our commitment to rigorously controlling our costs, coupled with the material recovery in the oil price, helped us to generate free cash flow of over $20 million in the first half of 2021. Our low-cost production is highly cash-generative, providing the financial strength to then invest in exciting growth areas, as we seek to fulfil our goal of creating material shareholder value.

 

Our strong financial performance would have been stronger still without the KRG changing its payment schedule in May, which resulted in only five monthly payments being received. While this amendment, and the change to the receivable recovery payment method, is frustrating, it marks a deferral of payment rather than a removal, and we are in discussions with the KRG regarding the pace of Genel's receivable recovery payments. At present, the KRG sees the IOC debts as interest free, and we are working to determine if there is a more equitable solution. In May, the KRG committed to reviewing the payment mechanism, and we look forward to hearing from them in this regard.

 

We are also attempting to work with the KRG to drive forward the development of Bina Bawi. This remains a potentially valuable project to Genel, and of national significance to the KRI, where we want to develop our existing licence to the benefit of local and national stakeholders. The resources in place are such that its development is of strategic importance, and we continue to attempt to drive forward this project, and explore all avenues to create shareholder value.

 

Investing in growth

Sarta and Qara Dagh have the potential to create significant value and are priority projects for Genel. The strength of our balance sheet and confidence in consistent payments mean that we are able to invest significantly in these projects this year.

 

At Sarta, while pilot production has not reached the levels that we had hoped in H1, it is providing valuable information regarding the future development of the field while generating meaningful cash to support the funding of the appraisal campaign. The three well programme is a key focus this year, and we look forward to the results of the campaign, which is now underway following the spudding of Sarta-5. The wells will help give us an understanding of the potential of the field, as we work with Chevron to ascertain the optimal field development plan.

 

Good progress is also being made with the QD-2 well, which has been drilling since April, and we eagerly await results in around two months' time.

 

A socially responsible contributor to the global energy mix

COVID-19 has, in many ways, heightened our sustainability ambitions, and as we expand our operations we continue to support the communities in which we operate through investment in social projects, providing direct local employment and fostering wider economic opportunities for companies in the KRI. 28 local companies are currently providing services to our operations.

 

Our 2020 equity-based carbon intensity figure of 13 kg CO2e/bbl was well below the industry average of c.20 kg CO2e/bbl, and while new production at Sarta will increase this in 2021, our focus on an asset life-cycle approach helps us deliver a carbon footprint that aligns with the Paris Agreement 1.5 degree pathway and leads to net zero by 2050. The reinjection of gas from Peshkabir into the Tawke field has already materially reduced our emissions, and Ministerial approval has been granted for the Sarta field development plan including dispensation for flaring during early development, with plans in place to invest in a longer-term GHG emission reduction project at the field.

 

We strongly believe that fulfilling our purpose requires that Genel not only be measured by what we achieve, but also by the way in which we achieve it. As part of our efforts to further strengthen our ESG performance, Genel continues its commitment to the UN Sustainable Development Goals and UN Global Compact's 10 Principles on human rights, labour standards, the environment, and anti-corruption. More about all aspects of our ESG performance can be read in our comprehensive 2020 Sustainability Report, which has been issued today and is available on our website.

 

Outlook and dividend

Given the level of activity expected in H2, with increased drilling also expected at the Tawke field pending approval from the MNR, capital expenditure is heavily biased towards the second half of the year. Despite this increase in spending and the ongoing expansion of our operating capability, and with the one month deferral in payments meaning we expect 11 monthly payments this year, we are forecasting ending the year in a net cash position at the expected forward oil price. The strength of this financial platform remains central to our strategy.

 

With the oil price currently remaining robust, and our confidence in our portfolio and ability to grow the company, we have increased the interim dividend by 1¢ to 6¢ per share.

 

 

OPERATING REVIEW

The first half of 2021 has seen Genel operations in the KRI expand significantly. Genel has a long history of working in the KRI, although the QD-2 well is the first sole operated well that Genel has undertaken. With Genel also transitioning to the operatorship at Sarta, there has been a step-change in our operational capability on the ground. It is a testament to the team in place, and the positive working culture that has been created, that we have continued to work efficiently and without any lost time injuries or Tier 1 containment losses in the period.

 

Production

Production in H1 2021 has increased by 2% on the prior year period, in line with guidance, following the addition of production at Sarta and the robust performance of Peshkabir.

 

(bopd)

Gross production

H1 2021

Net production

H1 2021

Gross production

H1 2020

Net production

H1 2020

Tawke

48,970

12,240

59,790

14,950

Peshkabir

62,170

15,540

48,790

12,200

Taq Taq

6,490

2,860

11,260

4,950

Sarta

7,080

2,120

-

-

Total

124,710

32,760

119,840

32,100

 

PRODUCING ASSETS

Tawke PSC (25% working interest)

Gross operated Tawke licence production averaged 110,300 bopd in Q2 2021, of which the Peshkabir field contributed 63,000 bopd and the Tawke field 47,300 bopd.

 

Five new wells are scheduled at Peshkabir in 2021. The first is in production, two more are being completed and are expected in service soon and two more will be drilled in the remainder of the year, contributing to the field's 2021 production.

 

With no new wells having come on production at the Tawke field in more than a year, the natural production decline has been partially offset by pressure support from reinjection of over 20 million cubic feet of gas per day from the Peshkabir field in addition to workovers and interventions of existing wells.

 

Subject to final contract approval from the Ministry of Natural Resources, Genel expects five Tawke wells, three of which will be side tracks, to be drilled before year end.

 

Sarta (30% working interest)

The Sarta licence has significant potential, and work done in 2021 will help us understand the extent of this potential. Our estimation of reserves and resources at year-end 2021 will be updated following the assessment of three key inputs - ongoing analysis of existing data, pilot production, and the three high-impact appraisal wells being drilled.

 

A detailed re-evaluation of the seismic depth conversion and associated reinterpretation by Chevron, adopted by the joint venture for well planning purposes, has resulted in a significant upwards revision to the gross rock volume associated with the field. This will form the basis for future reserves and resources audit work.

 

Production from the Sarta pilot project continues to provide invaluable dynamic data from which we can plan future activities, and averaged over 7,000 bopd in H1 2021. June saw the highest average monthly production in the year to date, 8,400 bopd, following the maximisation of uptime in the month. Of this production, the Sarta-2 well produced c.6,400 bopd, and the Sarta-3 well c.2,000 bopd, with the latter having been partially plugged back to manage water ingress from the Adaiyah production stream, the origin of which is yet to be determined. With production temporarily limited to the thinner, less volumetrically significant Mus reservoir, a fall in pressure in June across both wells resulted in Genel and the operator, Chevron, reassessing the optimal way to produce these wells ahead of the addition of production from Sarta-1D, a well set to access production from the entire Adaiyah reservoir section for the first time and via a smart completion. Reservoir surveillance work at the start of the year had already proved strong communication between the Mus reservoir in Sarta-2 and the Mus reservoir in Sarta 3 over a short distance of c.3 km, together representing a portion of the container more limited than our expected extent of the Mus reservoir.

 

In order to analyse Mus pressure data and provide valuable learnings for longer-term field production, the Sarta-3 well was taken off line at the end of June for data gathering purposes. Since then, Mus pressure decline at the Sarta-2 well has in response slowed considerably, potentially indicative of secondary pressure support and associated oil influx.

 

To prudently manage the reservoir and associated production from the Pilot facility until Sarta-1D comes online around the end of the year, the joint venture partners plan to continue to manage the offtake from the Mus. This period offers multiple invaluable pilot data gathering opportunities to inform the longer term Sarta development plans.

 

The 2021 appraisal drilling campaign, which is targeting a material portion of the 250 MMbbls of contingent resources in the Jurassic, is now underway and is not impacted by the early results from the pilot production.

 

Preparations for Sarta-1D and the construction of a flowline linking it to the facility are well underway. The Viking Rig is mobilising to the location ahead of spud in the coming days, and clearing for the flowline is nearing completion. The Sarta-5 well spud in June, with results expected in late Q3/early Q4. This will be followed immediately by Sarta-6 with the same rig, with results now expected by late Q1 2022. In a success case, Sarta-6 will be bought onto production in short order via a flowline back to the facility, while Sarta-5 will be produced via a standalone temporary facility given its distance from the existing facility.

 

Taq Taq (44% working interest, joint operator)

Production at Taq Taq averaged 6,490 bopd in H1, in line with expectations. Activity at Taq Taq is focused on maximising cash generation and no further work is scheduled at the field prior to 2022.

 

PRE-PRODUCTION ASSETS

Qara Dagh (40% working interest, operator)

Genel's high-potential drilling campaign began with the spud of the QD-2 well in April 2021. This well is appraising the crest of a 50 km long structure at Qara Dagh, around 10 km from the location of the QD-1 well, which flowed light oil in 2011. The well is currently at a depth of c.2,300 metres. Results are anticipated around the end of Q3 2021.

 

Our social investment programme is continuing, working with local companies to deliver projects that respond to the requirements of local communities. To date a local primary school has been renovated and secondary school refurbished, a football pitch constructed, a road restored, and clean water provided to local villages. There are also over 300 local people employed at Qara Dagh, and contracts awarded to 24 local companies.

 

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

Genel continues to drive engagement with the KRG at the highest level, as we seek a resolution that will allow progress to be made towards the development of Bina Bawi.

 

The Company remains excited by the potential that Bina Bawi presents, with development of the asset having the ability to create material value for both Genel and the KRG. The size of the resource base makes it a strategically important project that could make a significant difference to the region and its energy mix. It has, however, proved difficult to engage the KRG under the PSC in order to obtain the necessary approvals to proceed and every effort has been, and is being, made to obtain these approvals so that the project can be progressed in the near-term.

 

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

 

African exploration

A farm-out process relating to the highly prospective SL10B13 block (100% working interest and operator) in Somaliland is ongoing, and there remains active engagement with potential partners with respect to the opportunity.

 

Genel continues to work towards a farm-out campaign aimed at bringing a partner onto the Lagzira licence offshore Morocco (75% working interest and operator).

 

FINANCIAL REVIEW

Overview

The rapid recovery in the oil price so far this year has been quicker and greater than expected, which has had a material positive impact on the revenue and cash generation of our production business. Whereas through much of 2020 we were flexing our business model to protect the business in a downside environment, the past six months have seen us use our flexibility to capitalise on the material improvement in the external environment.

 

If as expected this oil price strength is sustained through the year, it will reward our determination in the second half of 2021 to return to drilling activity as quickly as possible on the Tawke PSC and to take Sarta to first oil, despite the challenging operating conditions and uncertain oil price outlook at the time.

 

Peshkabir is currently producing over 10,000 bopd more than its average production in 2020, and although Sarta production is currently relatively low, because of its early stage in PSC economics its barrels are valuable. Sarta revenue per barrel of $39/bbl in the period is higher than Tawke and Peshkabir, which both benefit from the override payment that broadly doubles profitability.

 

Revenue at the half year of $152 million is close to full year revenue last year, with margin per barrel increasing from $6/bbl in 2020 to $19/bbl, benefitting from the resumption of the override, which contributed $9/bbl.

 

EBITDAX of $123 million is greater than the full year EBITDAX last year. Production asset margin of $111 million reflects the high cash generation of our production and results in free cash flow before investment in growth of $62 million. On an annualised basis this represents over 20% of our current market capitalisation.  Production asset margin is provided to show the performance of our production assets. Free cash flow before investment in growth is provided to show the cash generated by the business in the period that is consequently available for allocation to where it best serves the business.

 

The KRG has commenced payment of the $159 million owed for unpaid sales made from November 2019 to February 2020. Although only $14 million has been received to date and we have not yet had any dialogue relating to the amended payment mechanism that the KRG committed to in June, consistent payments of amounts due is encouraging.

 

Unfortunately, the benefit of the receipt of amounts owed for deferred receivable has been offset by the KRG unilaterally moving payment terms from one month in arrears to two months in arrears, which has impacted our free cash flow in the period by $30 million.

 

Despite the change to payment terms explained above, our resulting free cash flow generation from production assets has more than covered our investment in growth at Sarta and Qara Dagh and the final dividend meaning that the only material change in cash in the period has been the $81 million repayment of bonds that was reported at year-end. The bonds were called in December 2020 and settled in early January 2021.

 

Capital expenditure of $58 million in the first half of the year was split evenly between production capex, principally at Tawke, and growth capex at Sarta and Qara Dagh. Overall our free cash flow in the first half of 2021 was $22 million, up $16 million on the prior period despite the $30 million impact of the change in payment terms.

 

(all figures $ million)

H1 2021

H1 2020

FY 2020

Brent average oil price

$65/bbl

$40/bbl

$42/bbl

Revenue

151.5

88.41

159.71

Production costs

(21.7)

(16.8)

(32.7)

Producing asset capex

(19.3)

(35.7)

(56.5)

Production asset margin

110.5

35.9

70.51

G&A (excl. depreciation and amortisation)

(6.7)

(6.5)

(12.4)

Net cash interest2

(13.1)

(13.4)

(23.8)

Working capital

1.4

7.8

(6.9)

Change in payment days3

(30.4)

11.6

21.8

Free cash flow before investment in growth

61.7

35.4

49.2

Pre-production capex

(38.9)

(22.8)

(53.2)

Working capital and other

(0.6)

(6.1)

(0.4)

Free cash flow

22.2

6.5

(4.4)

Deferred receivables (note 10) plus suspended override1

145.0

130.4

158.6

 

1 Nominal value of deferred receivables is $107.2 million (H1 2020: $120.8 million, FY 2020: $120.8 million). FY2020 revenue does not include $37.8 million (H1 2020: $9.6 million) of invoiced override revenue where payment was suspended from March 2020 to December 2020 (see note 1).

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

3 In March 2020, KRG changed payments terms from 3 months in arrears to 1 month in arrears, improving free cash flow for H1 2020 and FY 2020. In May 2021, KRG changed payment terms from 1 month in arrears to 2 months in arrears, adversely impacting free cash flow in H1 2021.

 

The focus of our business model remains unchanged:

  • Progress value creative, high priority growth projects in a challenging environment with a focus on near term cash generation;
  • Demonstrate material flexibility in capital allocation, supporting the generation of free cash flow
  • Pay a sustainable and progressive dividend.

 

Our resilience and financial strength positions us well to take advantage of an unpredictable environment. Company liquidity at the half year was $266 million, with the resilience of our business model and proactive management action protecting the balance sheet through the low oil price of last year and through a period of material investment in growth this year. This leaves the Company well-funded to progress and develop Sarta and Qara Dagh if there is drilling success this year, as well as progressing Bina Bawi gas and oil if there is commercial success in discussions with the KRG.

 

Capital expenditure

We guided capital expenditure of $150-200 million. At the half year, capital expenditure of $58 million has been spent principally on wells at Peshkabir and preparation for the four appraisal wells at Sarta and Qara Dagh. The appraisal campaign targets conversion of resources to reserves and has potential for material value delivery. The second half will therefore see a material increase in capital expenditure, which we expect to be covered by free cash flow.

 

Dividend

The material improvement in oil price, resumption of the override, and commencement of payment of amounts owed for deferred receivables provides the Company with a strong cash flow generation outlook.

 

The Company has generated $62 million of free cash flow before investment in growth in the period, despite the $30 million adverse impact of the change in payment terms. This demonstrates a highly cash generative business with material upside even before consideration of incremental production that may come from that investment in growth in the second half of the year.

 

Against this backdrop the Board has approved an increase in the interim dividend from 5 cents to 6 cents, representing just under $3 million per annum, and reaffirms its commitment to the dividend being sustainable and progressive.

 

Financial priorities

The table below summarises our progress against the 2021 financial priorities of the Company as set out at our 2020 results.

 

FY2021 financial priorities

Progress

  • Maintain our financial strength and continue protecting the balance sheet

 

Strong liquidity balance, broadly liquidity neutral for the period after settlement of debt, broadly net debt neutral position at half-year expected to return to net cash by the end of the year

  • Maximise NPV by prioritising highest value investment in assets with ongoing or near-term cash and value generation
  • Tawke PSC drilling well underway, with the Operator seeking to expand the 2021 work programme
  • Sarta and Qara Dagh appraisal programme underway and, despite delays in obtaining approvals from the MNR, expected to deliver meaningful results in the year
  • We continue to seek to progress Bina Bawi in the right way under the right conditions
  • Deliver 2021 work programme on time and on budget
  • 2021 activity broadly in line, although some delays on obtaining approvals may mean some activity happens a little later than planned
  • 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
  • c.$100 million of investment in growth in 2021 demonstrates our commitment to improving on these objectives and building a diverse, resilient reserves base with longevity

 

 

Financial results for the year

Income statement

(all figures $ million)

H1 2021

H1 2020

FY 2020

Production (bopd, working interest)

32,760

32,100

31,980

Profit oil

57.6

24.0

55.4

Cost oil

43.3

47.6

84.9

Override royalty

50.6

16.8

19.4

Revenue

151.5

88.4

159.7

Production costs

(21.7)

(16.8)

(32.7)

G&A (excl. depreciation and amortisation)

(6.7)

(6.5)

(12.4)

EBITDAX

123.1

65.1

114.6

Depreciation and amortisation

(81.8)

(82.6)

(153.7)

Impairment

-

(321.2)

(323.2)

Exploration expense

-

(1.3)

(2.2)

Net finance expense

(15.7)

(14.7)

(52.2)

Income tax expense

-

-

(0.2)

Profit / (Loss)

25.6

(354.7)

(416.9)

 

Working interest production of 32,760 bopd increased (H1 2020: 32,100 bopd), with revenue rising from $88 million to $152 million, principally caused by the higher Brent oil price and resumed override from January onwards.

 

Production costs of $22 million increased from the prior year (H1 2020: $17 million), with cost per barrel $3.7/bbl in H1 2021 (H1 2020: $2.9/bbl). Both increases have been caused by the addition of Sarta, which commenced production in December 2020. We expect that the overall operating cost per barrel at the Sarta field will reduce to around $5/bbl once production has increased to around the facility capacity - the Sarta plant is currently operating at less than 50%. This compares favourably to revenue per barrel of $38/bbl.

 

General and administration costs were $7 million (H1 2020: $7 million), of which corporate cash costs were $6 million (H1 2020: $5 million).

 

The increase in revenue resulted in a similar increase to EBITDAX, which was $123 million (H1 2020: $65 million). EBITDAX is presented in order for the users of the financial statements to understand the cash profitability of the Company, which excludes the impact of costs attributable to exploration activity, which tend to be one-off in nature, and the non-cash costs relating to depreciation, amortisation and impairments.

 

Depreciation of $59 million (H1 2020: $52 million) and Tawke intangibles amortisation of $23 million (H1 2020: $31 million) were broadly in line with last period in total.

 

Bond interest expense of $13 million (H1 2020: $15 million) decreased due to lower debt and lower coupon rate.

 

In relation to taxation, under the terms of the KRI production sharing contracts, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. Tax presented in the income statement was related to taxation of the service companies (H1 2021: nil, H1 2020: nil).

 

Capital expenditure

Capital expenditure is the aggregation of spend on production assets ($19 million) and pre-production assets ($39 million) and is reported to provide investors with an understanding of the quantum and nature of capital investment. Capital expenditure for the period was $58 million, predominantly focused on production assets and the Sarta PSC ($15 million) and Qara Dagh ($21 million):

 

(all figures $ million)

H1 2021

H1 2020

FY 2020

Cost recovered production capex

 19.3

35.7

 56.5

Pre-production capex - oil

 15.3

11.5

 30.0

Pre-production capex - gas

 1.3

5.9

 10.0

Other exploration and appraisal capex

 22.3

5.4

 13.2

Capital expenditure

 58.2

58.5

 109.7

 

Cash flow, cash, net cash and debt

Gross proceeds received totalled $123 million (H1 2020: $110 million), of which $29 million (H1 2020: $23 million) was received for the override royalty and $14 million for receivable recovery.

 

(all figures $ million)

H1 2021

H1 2020

FY 2020

Brent average oil price

$65/bbl

$40/bbl

$42/bbl

EBITDAX

123.1

65.1

114.6

Working capital

(32.0)

20.4

14.8

Operating cash flow

91.1

85.5

129.4

Producing asset cost recovered capex

(21.1)

(38.1)

(60.2)

Development capex

(16.0)

(11.6)

(25.3)

Exploration and appraisal capex

(16.8)

(13.7)

(24.2)

Restricted cash

-

(0.1)

3.0

Interest and other

(15.0)

(15.5)

(27.1)

Free cash flow

22.2

6.5

(4.4)

 

Free cash flow is presented in order to show the reader the free cash generated for equity. Free cash flow was $22 million (H1 2020: $7 million), with an overall decrease in cash of $88 million in the year (H1 2020: $35 million decrease) after payment of the FY2020 final dividend and $81 million settlement of the remaining 2022 bond debt, which was called in December 2020.

 

 

(all figures $ million)

H1 2021

H1 2020

FY 2020

Free cash flow

22.2

6.5

(4.4)

Dividend paid (incl. expenses)

(29.0)

(41.3)

(55.3)

Purchase of own shares

(0.3)

(0.7)

(3.4)

Bond refinancing

(81.0)

-

28.9

Other

-

0.1

(2.0)

Net change in cash

(88.1)

(35.4)

(36.2)

Opening cash

354.5

390.7

390.7

Closing cash

266.4

355.3

354.5

Debt reported under IFRS

(268.6)

(298.1)

(348.3)

Net (debt) / cash

(2.2)

57.2

6.2

 

The 2025 bonds have two financial covenant maintenance tests:

 

Financial covenant

Test

H1 2021

Equity ratio (Total equity/Total assets)

> 40%

63%

Minimum liquidity

> $30m

$266 million

 

 

 

Net assets

Net assets at 30 June 2021 were $929 million (31 December 2020: $930 million) and consist primarily of oil and gas assets of $1,073 million (31 December 2020: $1,095 million), trade receivables of $120 million (31 December 2020: $94 million) and net debt of $2 million (31 December 2020: $6 million net cash).

 

Liquidity / cash counterparty risk management

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

 

Dividend

A final dividend distribution of $29 million was made in June 2021 (June 2020: $28 million).

 

The interim dividend is increasing to 6¢ per share (2020: 5¢ per share), a total distribution of $17 million. Total dividends declared in 2021 amount to $46 million (2020: $41 million), representing 16¢ per share (2020: 15¢ per share). The payment timetable for the interim dividend is below:

 

The payment timetable for the interim dividend is below:

  • Ex-dividend date: 11 November 2021
  • Record Date: 12 November 2021
  • Payment Date: 10 December 2021

 

Going concern

The Directors have assessed that the Company's forecast liquidity provides adequate headroom over forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2021 and consequently that the Company is considered a going concern. In assessing going concern, the Directors have assessed that prolonged prevalence of COVID-19 may have a further negative impact on the oil price and in turn revenues, operational activity and receipt of amounts owed. The Company's low run rate costs, flexible capital programme, and strong cash position provide appropriate mitigation of the reduction of cash inflows that COVID-19 may cause for the going concern basis to remain appropriate.

 

 

Principal risks and uncertainties

The Company is exposed to a number of risks and uncertainties that may seriously affect its performance, future prospects or reputation and may threaten its business model, future performance, solvency or liquidity. The following risks are the principal risks and uncertainties of the Company, which are not all of the risks and uncertainties faced by the Company: the development and recovery of oil reserves; reserve replacement; commercialisation of the KRI gas business; M&A activity; the KRI natural resources industry and regional risk; a deterioration in the external environment caused by COVID-19; corporate governance failure; capital structure and financing; local community support; the environmental impact of oil and gas extraction; and health and safety risks. Further detail on many of these risks was provided in the 2020 Annual Report. Since year-end, the environmental impact of oil and gas extraction has been added to the risk register, reflecting the increased focus on ESG issues, along with the impact of COVID-19.

 

Statement of directors' responsibilities

The directors confirm that these condensed interim financial statements have been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and that the interim management report includes a true and fair review of the information required by DTR 4.2.7 and DTR 4.2.8, namely:

 

  • an indication of important events that have occurred during the first six months and their impact on the condensed set of financial statements, and a description of the principal risks and uncertainties for the remaining six months of the financial year; and
  • material related-party transactions in the first six months and any material changes in the related-party transactions described in the last annual report.

 

The directors of Genel Energy plc are listed in the Genel Energy plc Annual Report for 31 December 2020. A list of current directors is maintained on the Genel Energy plc website: www.genelenergy.com

 

By order of the Board

 

Bill Higgs

CEO

3 August 2021

 

Esa Ikaheimonen

CFO

3 August 2021

 

Disclaimer

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

 

 

 

Condensed consolidated statement of comprehensive income

For the period ended 30 June 2021

 

 

 

6 months to 30 June 2021

6 months to 30 June 2020

Year

to 31 Dec 2020

 

Note

$m

$m

$m

 

 

 

 

 

Revenue

3

151.5

88.4

159.7

 

 

 

 

 

Production costs

4

(21.7)

(16.8)

(32.7)

Depreciation and amortisation of oil assets

4

(81.7)

(82.5)

(153.3)

Gross profit / (loss)

 

48.1

(10.9)

(26.3)

 

 

 

 

 

Exploration expense

4

-

(1.3)

(2.2)

Impairment of intangible assets

4-8

-

(44.3)

(44.3)

Impairment of property, plant and equipment

4-9

-

(242.0)

(242.0)

Impairment of receivables

10

-

(34.9)

(36.9)

General and administrative costs

4

(6.8)

(6.6)

(12.8)

Operating profit / (loss)

 

41.3

(340.0)

(364.5)

 

 

 

 

 

 

 

 

 

 

Operating profit / (loss) is comprised of:

 

 

 

 

EBITDAX

 

123.1

65.1

114.6

Depreciation and amortisation

4

(81.8)

(82.6)

(153.7)

Exploration expense

4

-

(1.3)

(2.2)

Impairment of intangible assets

4-8

-

(44.3)

(44.3)

Impairment of property, plant and equipment

4-9

-

(242.0)

(242.0)

Impairment of receivables

 

10

-

(34.9)

(36.9)

 

 

 

 

 

Finance income

5

0.1

1.6

2.0

Bond interest expense

5

(13.2)

(15.0)

(31.5)

Other finance expense

5

(2.6)

(1.3)

(22.7)

Profit / (Loss) before income tax

 

25.6

(354.7)

(416.7)

Income tax expense

6

-

-

(0.2)

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

 

25.6

(354.7)

(416.9)

 

 

 

 

 

Attributable to:

 

 

 

 

Owners of the parent

 

25.6

(354.7)

(416.9)

 

 

25.6

(354.7)

(416.9)

 

 

 

 

 

Earnings / (Loss) per ordinary share

 

¢

¢

¢

Basic

7

9.3

(128.9)

(152.0)

Diluted

7

9.2

(128.9)

(152.0)

 

 

 

 

 

           

 

 

Condensed consolidated balance sheet

At 30 June 2021

 

 

 

30 June 2021

30 June 2020

31 Dec 2020

 

Note

$m

$m

$m

Assets

 

 

 

 

Non-current assets

 

 

 

 

Intangible assets

8

704.9

716.0

699.4

Property, plant and equipment

9

367.6

391.5

395.7

Trade and other receivables

10

 31.4

68.3

 52.1

 

 

1,103.9

1,175.8

1,147.2

Current assets

 

 

 

 

Trade and other receivables

10

95.9

30.0

48.9

Restricted cash

 

-

3.1

-

Cash and cash equivalents

 

266.4

355.3

354.5

 

 

362.3

388.4

403.4

 

 

 

 

 

Total assets

 

1,466.2

1,564.2

1,550.6

 

 

 

 

 

Liabilities

 

 

 

 

Non-current liabilities

 

 

 

 

Trade and other payables

 

(103.7)

(124.7)

(100.4)

Deferred income

 

(16.5)

(26.8)

(19.7)

Provisions

 

(47.6)

(39.0)

(45.9)

Interest bearing loans

11

(268.6)

(298.1)

(267.7)

 

 

(436.4)

(488.6)

(433.7)

Current liabilities

 

 

 

 

Trade and other payables

 

(93.2)

(66.9)

(99.0)

Deferred income

 

(7.5)

(3.0)

(7.5)

Interest bearing loans

11

-

-

(80.6)

 

 

(100.7)

(69.9)

(187.1)

 

 

 

 

 

Total liabilities

 

(537.1)

(558.5)

(620.8)

 

 

 

 

 

 

 

 

 

 

Net assets

 

929.1

1,005.7

929.8

 

 

 

 

 

Owners of the parent

 

 

 

 

Share capital

 

43.8

43.8

43.8

Share premium account

 

3,962.9

4,005.4

3,991.9

Accumulated losses

 

(3,077.6)

(3,043.5)

(3,105.9)

Total equity

 

929.1

1,005.7

929.8

 

 

 

 

 

 

Condensed consolidated statement of changes in equity

For the period ended 30 June 2021

 

 

 

 

 

 

 

Share capital

$m

Share premium

$m

Accumulated losses

$m

Total equity

$m

At 1 January 2020

 

43.8

4,033.4

(2,691.1)

1,386.1

Loss and total comprehensive expense

 

-

-

(354.7)

(354.7)

Share-based payments

 

-

-

3.0

3.0

Purchase of shares for employee share awards

 

-

-

(0.7)

(0.7)

Dividends provided for or paid1

 

-

(28.0)

-

(28.0)

At 30 June 2020

 

43.8

4,005.4

(3,043.5)

1,005.7

 

 

 

 

 

 

At 1 January 2020

 

43.8

4,033.4

(2,691.1)

1,386.1

Loss and total comprehensive expense

 

 - 

 - 

 (416.9)

 (416.9)

Share-based payments

 

-

-

 5.5

 5.5

Purchase of shares for employee share awards

 

 - 

 - 

 (3.4)

 (3.4)

Dividends provided for or paid1

 

 - 

 (41.5) 

 - 

 (41.5) 

At 31 December 2020 and 1 January 2021

 

 43.8

 3,991.9

 (3,105.9)

 929.8

 

 

 

 

 

 

Profit and total comprehensive income

 

 - 

 - 

 25.6

 25.6

Share-based payments

 

-

-

 3.0

 3.0

Purchase of shares for employee share awards

 

 - 

 - 

 (0.3)

 (0.3)

Dividends provided for or paid1

 

 - 

 (29.0) 

 - 

 (29.0) 

At 30 June 2021

 

 43.8

 3,962.9

 (3,077.6)

 929.1

 

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

 

 

 

 

Condensed consolidated cash flow statement

For the period ended 30 June 2021

 

 

 

30 June 2021

30 June 2020

31 Dec

2020

 

Note

$m

$m

$m

Cash flows from operating activities

 

 

 

 

Profit / (Loss) for the year

 

25.6

(354.7)

(416.9)

Adjustments for:

 

 

 

 

  Net finance expense

5

15.7

14.7

52.2

  Taxation

6

 - 

-

 0.2 

  Depreciation and amortisation

 

 83.0

82.6

 153.7

  Exploration expense

4

 -

1.3

 2.2

  Impairments

4

-

321.2

323.2

  Other non-cash items

 

(2.9)

(0.3)

(3.7)

Changes in working capital:

 

 

 

 

  (Increase) / Decrease in trade receivables

 

 (25.9)

22.0

 15.8

  Decrease in other receivables

 

 -

0.1

 0.6

  (Decrease) in trade and other payables

 

(4.3)

(2.7)

0.4

Cash generated from operations

 

 91.2

84.2

 127.7

Interest received

5

 -

1.6

 2.0

Taxation paid

 

(0.1)

(0.3)

(0.3)

Net cash generated from operating activities

 

91.1

85.5

129.4

 

 

 

 

 

Cash flows from investing activities

 

 

 

 

Purchase of intangible assets

 

 (16.8)

(13.7)

 (24.2)

Purchase of property, plant and equipment

 

 (37.1)

(49.7)

 (85.5)

Movement in restricted cash

 

-

(0.1)

3.0

Net cash used in investing activities

 

(53.9)

(63.5)

(106.7)

 

 

 

 

 

Cash flows from financing activities

 

 

 

 

Dividends paid to company's shareholders, including expenses

 

(29.0)

(41.3)

(55.3)

Purchase of own shares

 

(0.3)

(0.7)

(3.4)

Bond refinancing: part-settlement and new issuance

11

(81.0)

-

28.9

Other

 

(1.7)

(0.5)

(3.3)

Interest paid

 

(13.3)

(15.0)

(25.8)

Net cash used in financing activities

 

(125.3)

(57.5)

(58.9)

 

 

 

 

 

Net decrease in cash and cash equivalents

 

(88.1)

(35.5)

(36.2)

Foreign exchange loss on cash and cash equivalents

 

-

0.1

-

Cash and cash equivalents at the beginning of the period

 

354.5

390.7

390.7

Cash and cash equivalents at the end of the period

 

266.4

355.3

354.5

 

 

Notes to the consolidated financial statements

 

1. Basis of preparation

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

 

The half-year condensed consolidated financial statements for the six months ended 30 June 2021 and six months ended 30 June 2020 are unaudited and have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority, with Article of 106 of the Companies (Jersey) Law 1991 and with IAS 34 'Interim Financial Reporting' as adopted by the European Union and were approved for issue on 3 August 2021. They do not comprise statutory accounts within the meaning of Article 105 of the Companies (Jersey) Law 1991.  The half-year condensed consolidated financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2020, which have been prepared in accordance with IFRS as adopted by the European Union. The annual financial statements for the period ended 31 December 2020 were approved by the board of directors on 17 March 2021. The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Article 113A of Companies (Jersey) Law 1991. The financial information for the year to 31 December 2020 has been extracted from the audited accounts.

 

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

 

Going concern

The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combination of oil price, discount rates, production volumes, payments, capital and operational spend scenarios. The Company has reported liquidity of $266.4 million, with no debt maturing until the second half of 2025 and significant headroom on both the equity ratio and minimum liquidity covenant. Our business model has demonstrated its resilience in 2020, when oil price was low, 4 months of payments with a value of $120.8 million that were due were not received, and override income of $38 million was not paid, by delivering a small free cash out flow after investing significantly in growth, principally bringing Sarta to first production.

 

The strength of the balance sheet is expected to be maintained through 2021 and 2022, with Sarta adding a new income stream and diversifying production risk, and capital activity in the year focused on expanding the reserves and sources of income of the business further.

 

Our low-cost assets with flexibility on commitment of capital mean that we are resilient to oil prices as low as the levels reached last year, with the KRG also demonstrating its ability to pay consistently in times of financial stress. In addition, specifically for the purposes of the going concern, management have modelled a downside scenario, recognising the impact of the COVID19 pandemic, which includes a significant reduction in oil price from current levels combined with a reduction in production. Even with these downsides there is considered to be sufficient cash in the business and still more room for flexibility if needed given nature of the discretionary capex planned.

 

Longer term, our low-cost, low-carbon assets, located in a region where oil revenues provide a material proportion of funding to the government and its people means that we are well positioned to address the appropriate challenges and demands that climate change initiatives are bringing to the sector. Given the footprint and the benefit to society generated, we see our portfolio as being well-positioned for a future of fewer and better natural resources projects, while the global energy mix continues to require hydrocarbons.

 

As a result, the Directors have assessed that the Company's forecast liquidity provides adequate headroom over its forecast expenditure for the 12 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2021 and consequently that the Company is considered a going concern.

 

 

2. Summary of significant accounting policies

The accounting policies adopted in preparation of these half-year condensed consolidated financial statements are consistent with those used in preparation of the annual financial statements for the year ended 31 December 2020.

 

The preparation of these half-year condensed consolidated financial statements in accordance with IFRS requires the Company to make judgements and assumptions that affect the reported results, assets and liabilities. Where judgements and estimates are made, there is a risk that the actual outcome could differ from the judgement or estimate made. The Company has assessed the following as being areas where changes in judgements or estimates could have a significant impact on the financial statements.

 

Significant judgements

The significant judgements that the directors have made in the process of applying the Company's accounting policies and that have the most significant effect on the amounts recognised in the financial statements include; i) IFRS 15 criteria have not been met for the suspended override revenue belonging to the period between 1 March 2020 to 31 December 2020; ii) the Bina Bawi and Miran projects will progress. These are explained in the context of the significant estimates below.

 

Significant estimates

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

 

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

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

 

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

 

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

 

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

 

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

 

Estimation of oil and gas asset values

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

 

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

 

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

 

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

 

Estimation of future oil price and netback price

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

 

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

 

Latest oil price forecast is materially higher than it was at HY2020. The oil price at HY2020 caused material impairment to our production assets last year.

 

$/bbl

2021

2022

2023

2024

HY2021 forecast

65

65

65

65

YE2020  forecast

55

55

60

60

HY2020 forecast

43

50

55

60

 

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

 

Estimation of the recoverable value of overdue trade receivables ("deferred receivables")

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

 

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

 

In December 2020, the KRG announced a reconciliation model for payment of the receivable relating to the unpaid invoices, whereby for each dollar above a monthly dated Brent average of $50/bbl, 50 cents per paying interest barrel shall be paid towards monies owed. In March 2021, the KRG amended this reconciliation model so that it paid 20 cents per paying interest barrel shall be paid towards monies owed.

 

In order to assess the recoverable amount of overdue trade receivables at 30 June 2021, the Company has compared the carrying value of trade receivables with the present value of the estimated future cash flows based on the KRG's communications, and using estimations of future oil prices and production scenarios.  Under IFRS9, the Company has used a forward-looking impairment model based on a lifetime expected credit loss (ECL) assessment. The model calculates the net present value of outstanding receivables using the effective interest rate for the period in which the revenue was recognised, which was 13%. The expected credit loss is the weighted average of these scenarios and is recognised in the income statement.  The result of the Company's assessment was no change to the reported receivable balance, with the impairment of $34.9 million maintained. The accounting and valuation of the receivable will be an output of clarity on the mechanism and that it is working effectively, oil price and production. The Company has provided the detailed disclosures required by IFRS 9 ECL assessment in note 10.

 

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

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

 

The KRG has communicated that override income owed will be paid by the reconciliation model explained above, which effectively subordinates the value of override income to entitlement revenue owed and would result in no payment of the monies owed for a number of years. Discussions with the KRG on a fair and equitable solution are ongoing.

 

New standards

The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2021. Amendments to IFRS 4 Insurance Contracts - deferral of IFRS19, Amendments to IFRS 9, IAS 39, IFRS 7, IFRS 4 and IFRS 16 Interest Rate Benchmark Reform - Phase 2, Amendments to IFRS 16 Leases: Covid-19-Related Rent Concessions beyond 30 June 2021. Nothing has been early adopted, and these standards are not expected to have a material impact on the Company's results or financials statement disclosures in the current or future reporting periods.

 

The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and have not yet been endorsed by the EU: IFRS 17 Insurance contracts (effective 1 Jan 2023), Amendments to IAS 1 Presentation of Financial Statements: Classification of Liabilities as Current or Non-current (1 Jan 2023), Amendments to IFRS 3 Business Combinations; IAS 16 Property, Plant and Equipment; IAS 37 Provisions, Contingent Liabilities and Contingent Assets; Annual Improvements 2018-2020 (1 Jan 2022), Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2: Disclosure of Accounting policies (1 Jan 2023), Amendments to IAS 8 Accounting policies, Changes in Accounting Estimates and Errors: Definition of Accounting Estimates (1 Jan 2023), Amendments to IAS 12 Income Taxes: Deferred Tax related to Assets and Liabilities arising from a Single Transaction (1 Jan 2023).

 

 

 

3. Segmental information

 

The Company has two reportable business segments: Production (which includes development assets) and Pre-production. Capital allocation decisions for the production segment are considered in the context of the cash flows expected from the production and sale of crude oil. The production segment is comprised of the producing fields on the Tawke PSC (Tawke and Peshkabir), the Taq Taq PSC (Taq Taq) and the Sarta PSC (Sarta) which are located in the KRI and make sales predominantly to the KRG. The pre-production segment is comprised of discovered resource held under the Qara Dagh PSC, the Bina Bawi PSC and the Miran PSC (all in the KRI) and exploration activity, principally located in Somaliland and Morocco. Sarta asset was transferred from pre-production to production following the production commencement close to 31 December 2020, whereas capital expenditure incurred for the development of the field until production commenced is reported under pre-production segment. 'Other' includes corporate assets, liabilities and costs, elimination of intercompany receivables and intercompany payables, which are non-segment items.

 

 

 

For the 6-month period ended 30 June 2021

 

 

Production

Pre-production

 

Other

Total

 

$m

$m

$m

$m

Revenue from contracts with customers

147.4

-

-

147.4

Revenue from other sources

4.1

-

-

4.1

Cost of sales

(103.4)

-

-

(103.4)

Gross profit

48.1

-

-

48.1

 

 

 

 

 

General and administrative costs

-

-

(6.8)

(6.8)

Operating profit / (loss)

48.1

-

(6.8)

41.3

 

 

 

 

 

Operating profit / (loss) is comprised of

 

 

 

 

EBITDAX

129.8

-

(6.7)

123.1

Depreciation and amortisation

(81.7)

-

(0.1)

(81.8)

 

 

 

 

 

Bond interest expense

-

-

(13.2)

(13.2)

Other finance expense

(0.8)

(0.4)

(1.3)

(2.5)

Profit / (Loss) before income tax

47.3

(0.4)

(21.3)

25.6

 

 

 

 

 

 

 

 

 

 

Capital expenditure

34.6

23.6

-

58.2

Total assets

687.8

575.3

203.1

1,466.2

Total liabilities

(137.1)

(109.8)

(290.2)

(537.1)

 

 

 

 

 

 

 

 

 

 

Revenue from contracts with customers includes $46.5 million (30 June 2020: $14.7 million, 31 December 2020: $14.7 million) arising from the 4.5% royalty interest on gross Tawke PSC revenue ending at the end of July 2022 ("the ORRI"). As explained in note 2, no revenue has been recognised regarding to the ORRI from March 2020 to December 2020.

 

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

 

 

 

 

 

For the 6-month period ended 30 June 2020

 

 

Production

Pre-production

 

Other

Total

 

$m

$m

$m

$m

Revenue from contracts with customers

86.3

-

-

86.3

Revenue from other sources

2.1

-

-

2.1

Cost of sales

(99.3)

-

-

(99.3)

Gross loss

(10.9)

-

-

(10.9)

 

 

 

 

 

Exploration expense

-

(1.3)

-

(1.3)

Impairment of intangible assets

(44.3)

-

-

(44.3)

Impairment of property, plant and equipment

(242.0)

-

-

(242.0)

Impairment of trade receivables

(34.9)

-

-

(34.9)

General and administrative costs

-

-

(6.6)

(6.6)

Operating loss

(332.1)

(1.3)

(6.6)

(340.0)

 

 

 

 

 

Operating loss is comprised of

 

 

 

 

EBITDAX

71.6

-

(6.5)

65.1

Depreciation and amortisation

(82.5)

-

(0.1)

(82.6)

Exploration expense

-

(1.3)

-

(1.3)

Impairment of intangible assets

(44.3)

-

-

(44.3)

Impairment of property, plant and equipment

(242.0)

-

-

(242.0)

Impairment of trade receivables

(34.9)

-

-

(34.9)

 

 

 

 

 

Finance income

-

-

1.6

1.6

Bond interest expense

-

-

(15.0)

(15.0)

Other finance expense

(0.9)

(0.1)

(0.3)

(1.3)

Loss before income tax

(333.0)

(1.4)

(20.3)

(354.7)

 

 

 

 

 

 

 

 

 

 

Capital expenditure

35.7

22.8

-

58.5

Total assets

617.9

618.6

327.7

1,564.2

Total liabilities

(95.2)

(150.8)

(312.5)

(558.5)

 

 

 

 

 

 

 

 

 

 

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

 

 

 

 

For the 12-month period ended 31 December 2020

 

 

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)

 

 

 

 

 

 

 

 

 

 

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

 

 

 


4. Cost of sales

 

6 months to 30 June

2021

6 months to 30 June 2020

Year to 31 December 2020

 

$m

$m

$m

Operating costs

 (21.5)

(16.8)

 (32.6)

Trucking costs

(0.2)

-

(0.1)

Production cost

(21.7)

(16.8)

(32.7)

Depreciation of oil and gas property, plant and equipment

 (58.6)

(51.6)

 (98.7)

Amortisation of oil and gas intangible assets

 (23.1)

(30.9)

 (54.6)

Cost of sales

 (103.4)

(99.3)

 (186.0)

 

 

 

 

Exploration expense

-

(1.3)

(2.2)

Impairment of intangible assets (note 8)

-

(44.3)

(44.3)

Impairment of property, plant and equipment (note 9)

-

(242.0)

(242.0)

Impairment of receivables (note 10)

-

(34.9)

(36.9)

 

 

 

 

 

 

 

 

Corporate cash costs

(6.2)

(4.9)

(9.6)

Other operating expenses

-

(1.1)

(1.8)

Corporate share-based payment expense

(0.5)

(0.5)

(1.0)

Depreciation and amortisation of corporate assets

(0.1)

(0.1)

(0.4)

General and administrative expenses

(6.8)

(6.6)

(12.8)

 

 

 

 

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

 

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

 

5. Finance expense and income 

 

6 months to 30 June

2021

6 months to 30 June

2020

Year to 31 December 2020

 

$m

$m

$m

Bond interest paid

 (13.2)

(15.0)

 (25.8)

Bond interest accrued

-

-

(5.7)

Accelerated cost of bond settlement (see note 15)

-

-

(19.4)

Other finance expense (non-cash)

 (2.6)

(1.3)

 (3.3)

Finance expense

(15.8)

(16.3)

(54.2)

 

 

 

 

Bank interest income

0.1

1.6

2.0

Finance income

0.1

1.6

2.0

 

 

 

 

Net finance expense

(15.7)

(14.7)

(52.2)

 

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

 

6. Income tax expense

 

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

 

7. Earnings / (Loss) per share

 

Basic

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

 

 

6 months to 30 June

2021

6 months to 30 June 2020

Year to 31 December 2020

 

 

 

 

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

25.6

(354.7)

(416.9)

 

 

 

 

Weighted average number of ordinary shares - number 1

275,446,155

275,197,007

274,202,853

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

9.3

(128.9)

(152.0)

1 Excluding shares held as treasury shares

 

Diluted

The Company purchases shares in the market to satisfy share plan requirements so diluted earnings per share is adjusted for performance shares, restricted shares and share options not included in the calculation of basic earnings per share. Because the Company reported a loss for the six month period ended 30 June 2020 and year ended 31 December 2020, diluted EPS is anti-dilutive and therefore diluted EPS is the same as basic EPS:

 

 

6 months to 30 June

2021

6 months to 30 June 2020

Year to 31 December 2020

 

 

 

 

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

25.6

(354.7)

(416.9)

 

 

 

 

Weighted average number of ordinary shares - number1

275,446,155

275,197,007

274,202,853

Adjustment for performance shares, restricted shares and share options

3,067,145

-

-

Weighted average number of ordinary shares and potential ordinary shares

278,513,300

275,197,007

274,202,853

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

9.2

(128.9)

(152.0)

1 Excluding shares held as treasury shares 

 

 

8. Intangible assets

 

Exploration and evaluation assets

Tawke

RSA

Other

assets

Total

Cost

$m

$m

$m

$m

At 1 January 2020

1,518.5

425.1

7.3

1,950.9

Additions

11.3

-

0.1

11.4

Discount unwind of contingent consideration

4.7

-

-

4.7

Other

(0.3)

-

-

(0.3)

At 30 June 2020

1,534.2

425.1

7.4

1,966.7

 

 

 

 

 

At 1 January 2020

1,518.5

425.1

7.3

1,950.9

Additions

23.2

-

0.1

23.3

Other

(0.2)

-

-

(0.2)

At 31 December 2020 and 1 January 2021

 1,541.5

 425.1

 7.4

 1,974.0

 

 

 

 

 

Additions

23.6

-

0.1

23.7

Discount unwind of contingent consideration

4.7

-

-

4.7

Other

0.3

-

-

0.3

At 30 June 2021

1,570.1

425.1

7.5

2,002.7

 

 

 

 

 

Accumulated amortisation and impairment

 

 

 

 

At 1 January 2020

(1,005.3)

(163.2)

(6.8)

(1,175.3)

Amortisation charge for the period

-

(30.9)

(0.2)

(31.1)

Impairment

-

(44.3)

-

(44.3)

At 30 June 2020

(1,005.3)

(238.4)

(7.0)

(1,250.7)

 

 

 

 

 

At 1 January 2020

(1,005.3)

(163.2)

(6.8)

(1,175.3)

Amortisation charge for the period

 - 

 (54.6)

 (0.4)

 (55.0)

Impairment

-

 (44.3)

 - 

 (44.3)

At 31 December 2020 and 1 January 2021

 (1,005.3)

 (262.1)

 (7.2)

 (1,274.6)

 

 

 

 

 

Amortisation charge for the period

-

(23.1)

(0.1)

(23.2)

At 30 June 2021

(1,005.3)

(285.2)

(7.3)

(1,297.8)

 

 

 

 

 

Net book value

 

 

 

 

At 30 June 2020

528.9

186.7

0.4

716.0

At 31 December 2020

 536.2

 163.0

 0.2

 699.4

At 30 June 2021

 564.8

 139.9

 0.2

 704.9

 

 

 

 

 

30 June 2021

30 June 2020

31 Dec 2020

Book value

 

$m

$m

$m

Bina Bawi PSC

Discovered gas and oil, appraisal

367.4

362.5

360.5

Miran PSC

Discovered gas and oil, appraisal

122.6

121.6

123.2

Somaliland PSC

Exploration

35.2

34.1

34.7

Qara Dagh PSC

Exploration / Appraisal

39.6

10.7

17.8

Exploration and evaluation assets

 

564.8

528.9

536.2

 

 

 

 

 

Tawke overriding royalty

 

56.2

90.9

73.3

Tawke capacity building payment waiver

83.7

95.8

89.7

Tawke RSA assets

 

139.9

186.7

163.0

 

Sensitivity of the Tawke CGU is provided in note 9. The Miran intangible asset is most sensitive to timing of its commercialisation. The table below shows the indicative sensitivity of the Bina Bawi CGU net present value to changes to long term Brent, discount rate or production and reserves, assuming no change to other inputs. None of these would result in impairment.

 

 

 

$m

Long term Brent +/- $5/bbl

 

 

+/- 13

Discount rate +/-2.5%

 

 

+/- 101

Production and reserves +/- 10%

 

 

+/- 32

 

 

 

 

9. Property, plant and equipment

 

Producing assets

Development assets

Other

Assets

 

Total

Cost

$m

$m

$m

$m

At 1 January 2020

2,876.1

68.0

13.5

2,957.6

Additions

35.7

11.5

1.0

48.2

Right-of-use assets

-

-

1.0

1.0

Net change in payable

-

(1.8)

-

(1.8)

Non-cash additions for ARO/SBP1

1.2

0.3

-

1.5

At 30 June 2020

2,913.0

78.0

15.5

3,006.5

 

 

 

 

 

At 1 January 2020

2,876.1

68.0

13.5

2,957.6

Additions

56.5

30.0

1.0

87.5

Right-of-use assets

-

-

8.1

8.1

Net change in payable

-

(5.4)

-

(5.4)

Non-cash additions for ARO/SBP/Production bonus

2.3

8.8

-

11.1

Transfer to producing assets

101.4

(101.4)

-

-

At 31 December 2020 and 1 January 2021

3,036.3

-

22.6

3,058.9

 

 

 

 

 

Additions

34.6

-

0.2

34.8

Net change in payable

(5.0)

-

-

(5.0)

Non-cash additions for ARO/SBP

2.5

-

-

2.5

At 30 June 2021

3,068.4

-

22.8

3,091.2

 

 

 

 

 

Accumulated depreciation and impairment

 

 

 

 

At 1 January 2020

(2,310.7)

-

(10.0)

(2,320.7)

Depreciation charge for the period

(51.6)

-

(0.7)

(52.3)

Impairment

(242.0)

-

-

(242.0)

At 30 June 2020

(2,604.3)

-

(10.7)

(2,615.0)

 

 

 

 

 

At 1 January 2020

(2,310.7)

-

(10.0)

(2,320.7)

Depreciation charge for the period

 (98.7)

- 

 (1.8)

 (100.5)

Impairment

 (242.0)

 - 

-

 (242.0)

At 31 December 2020 and 1 January 2021

 (2,651.4)

 -

 (11.8)

(2,663.2)

 

 

 

 

 

Depreciation charge for the period

(58.6)

-

(1.8)

(60.4)

At 30 June 2021

(2,710.0)

-

(13.6)

(2,723.6)

 

 

 

 

 

Net book value

 

 

 

 

At 30 June 2020

308.7

78.0

4.8

391.5

At 31 December 2020

 384.9

 -

 10.8

 395.7

At 30 June 2021

 358.4

 -

 9.2

 367.6

 

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

 

Sarta asset was transferred from development assets to producing assets following the commencement of production from the field at December 2020.

 

 

30 June 2021

30 June 2020

31 Dec 2020

Book value

 

$m

$m

$m

Tawke PSC

Oil production

206.1

247.0

228.2

Taq Taq PSC

Oil production

45.6

61.7

56.2

Sarta PSC

Oil production/development

106.7

78.0

100.5

Producing assets

 

358.4

386.7

384.9

 

 

 

 

 

The sensitivities below provide an indicative impact on the net present value of a change in long term Brent, discount rate or production and reserves, assuming no change to any other inputs. None of these would result in impairment.

 

Taq Taq CGU

$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

 

30 June 2021

30 June 2020

31 Dec 2020

 

$m

$m

$m

Trade receivables - current

88.5

21.9

41.9

Trade receivables - non-current

31.4

68.3

52.1

Other receivables and prepayments

7.4

8.1

7.0

 

127.3

98.3

101.0

 

Under the Tawke, Taq Taq and Sarta PSCs, payment for entitlement is due within 30 days. Since February 2016, payments were received consistently three months in arrears, which was assessed as the operating cycle under IAS1. From March 2020, payments were received one month in arrears, which was consequently used to assess receivables that were not due at 30 June 2020 and 31 December 2020. At half year 2021, the Company is owed two months of payments, which is consequently assumed to be the operating cycle for presentation of overdue receivables at the end of the period.

 

 

Year of sale of

 

amounts overdue

 

Not due

2020

2019

Total overdue

$m

$m

$m

$m

Trade receivables at 30 June 2020 (nominal)

  8.3

  55.4

  65.4

120.8

Trade receivables at 31 December 2020 (nominal)

  14.8

  55.4

  65.4

120.8

Trade receivables at 30 June 2021 (nominal)

  55.7

  55.4

  51.8

107.2

 

Movement on trade receivables in the period

30 June 2021

$m

30 June 2020

$m

31 Dec 2020

$m

Carrying value at the beginning of the period

94.0

150.2

150.2

Revenue from contracts with customers

147.4

86.3

155.0

Cash proceeds

(122.5)

(110.0)

(173.4)

Offset of payables due to the KRG

-

(3.2)

(5.5)

Expected credit loss

-

(34.9)

(34.9)

Capacity building payments

1.0

1.8

2.6

Carrying value at the end of the period

119.9

90.2

94.0

 

Recovery of the carrying value of the receivable

The balance owed has reduced by $13.6 million from the opening balance of $120.8 to $107.2 million. This reduction is the result of four payments being received in the period: the first two under the initial mechanism announced in December and the second two made under the revised mechanism announced in May. The Company expects to recover the full nominal value of $107.2 million receivables owed from the KRG, but the terms of recovery are not finalised. Explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 2. Neither the nominal value nor the net present value include $38 million owed to the Company for override revenue earned but not received for the period March 2020 to December 2020, which was not recognised as revenue for the reasons explained in note 2.

 

 

Total

$m

Nominal balance to be recovered

107.2

Book value of overdue receivables

72.3

 

Sensitivities

The table below shows the sensitivity of the net present value of the overdue trade receivables to oil price, assuming flat production and payment is received in line with the mechanism proposed by the KRG in March 2021, which is explained in note 2.

 

Nominal receivables ($m)

Timing of repayment

Total

NPV13.0

2H 2021

2022

2023

2024

2025

2026

Brent

$60/bbl

11.5

23.0

23.0

23.0

23.0

3.7

107.2

77.0

$65/bbl

17.3

34.6

34.6

20.7

-

-

107.2

84.0

$70/bbl

23.1

46.2

37.9

-

-

-

107.2

88.1

$75/bbl

28.8

57.6

20.8

-

-

-

107.2

90.3

11. Interest bearing loans and net (debt) / cash

 

 

1 Jan

2021

Discount unwind

Buyback / Issuance

Dividend

paid

Net other changes

30 June 2021

 

$m

$m

$m

$m

$m

$m

2022 Bond 10.0% (current)

(80.6)

(0.4)

81.0

-

-

-

2025 Bond 9.25% (non-current)

(267.7)

(0.9)

-

-

-

(268.6)

Cash

354.5

-

(81.0)

(29.0)

21.9

266.4

Net (debt) / cash

6.2

(1.3)

-

(29.0)

21.9

(2.2)

 

At 30 June 2021, the fair value of the $280 million of bonds held by third parties is $274.4 million (30 June 2020: $298.5 million, 31 December 2020: $274.4 million).

 

1 Jan

2020

Discount unwind

Dividend paid

Net other changes

30 June

2020

 

$m

$m

$m

$m

$m

2022 Bond 10.0%

(297.9)

(0.2)

-

-

(298.1)

Cash

390.7

-

(41.3)

5.9

355.3

Net Cash

92.8

(0.2)

(41.3)

5.9

57.2

 

 

 

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)

19.4

-

(267.7)

Cash

390.7

-

28.9

-

(65.1)

354.5

Net cash

92.8

(0.8)

(36.2)

19.4

(69.0)

6.2

 

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

 

12. Capital commitments

 

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

 

 

INDEPENDENT REVIEW REPORT TO GENEL ENERGY PLC

Introduction

We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 which comprises the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and the notes to the interim financial statements.

We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.

Directors' responsibilities

The half-yearly financial report is the responsibility of and has been approved by the directors.  The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority and the Companies (Jersey) Law 1991.

As disclosed in note 1, the annual financial statements of the group are prepared in accordance with International Financial Reporting Standards as adopted by the European Union.  The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, ''Interim Financial Reporting'' and the requirements of the Disclosure and Transparency Rules of the Financial Conduct Authority.

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, ''Review of Interim Financial Information Performed by the Independent Auditor of the Entity'', issued by the Financial Reporting Council for use in the United Kingdom.  A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures.  A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit.  Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2021 is not prepared, in all material respects, in accordance with International Accounting Standard 34, as adopted by the European Union, and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.

Use of our report

Our report has been prepared in accordance with the terms of our engagement to assist the Company in meeting its responsibilities in respect of half-yearly financial reporting in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority and for no other purpose. No person is entitled to rely on this report unless such a person is a person entitled to rely upon this report by virtue of and for the purpose of our terms of engagement or has been expressly authorised to do so by our prior written consent. Save as above, we do not accept responsibility for this report to any other person or for any other purpose and we hereby expressly disclaim any and all such liability.

 

 

BDO LLP

Chartered Accountants

London

3 August 2021

 

BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC305127).



ISIN: JE00B55Q3P39, NO0010894330
Category Code: IR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 119001
EQS News ID: 1223461

 
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