Genel Energy : Half-Year Results

August 06, 2020 at 02:14 am EDT

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6 August 2020

Genel Energy plc

Unaudited results for the period ended 30 June 2020

Genel Energy plc ('Genel' or 'the Company') announces its unaudited results for the six months ended 30 June 2020.

Bill Higgs, Chief Executive of Genel, said:

"Genel's robust business model, which is designed to provide resilience in a challenging environment, has demonstrated its value as the Company negotiates the headwinds facing the sector in 2020. Our low-cost production and the capital flexibility within our development programme have enabled us to preserve the strength of our balance sheet even while investing in growth. Given the lower oil price and overdue payments, the fact that we still expect to end 2020 in a net cash position - even after dividend distributions and making the investment to bring Sarta to production this year - is a testament to our resilience, and we have today confirmed an interim dividend of 5¢ per share."

Results summary ($ million unless stated)
	H1 2020	H1 2019	FY 2019
Production (bopd, working interest)	32,100	37,400	36,250
Revenue	88.4	194.3	377.2
EBITDAX1	65.1	167.3	321.8
Depreciation and amortisation	(82.6)	(74.8)	(158.5)
Exploration expense	(1.3)	(0.6)	(1.2)
Impairment of oil and gas assets	(286.3)	-	(29.8)
Impairment of trade receivables	(34.9)	-	-
Operating (loss) / profit	(340.0)	91.9	132.3
Underlying (loss) / profit2	(32.2)	76.6	134.9
Cash flow from operating activities	85.5	142.3	272.9
Capital expenditure	58.5	72.2	158.1
Free cash flow3	6.5	56.7	99.0
Dividends paid	41.3	27.4	27.4
Cash4	355.3	353.3	390.7
Total debt	300.0	300.0	300.0
Net cash5	57.2	55.8	92.8
Basic EPS (¢ per share)	(128.9)	27.2	37.8
Underlying EPS (¢ per share)2	(11.7)	27.4	49.0
Average Brent oil price ($/bbl)	40	65	64

EBITDAX is operating (loss) /profit adjusted for the add back of depreciation and amortisation ($82.6 million), exploration expense ($1.3 million), impairment of property, plant and equipment ($242.0 million), impairment of intangible assets ($44.3 million) and impairment of trade receivables ($34.9 million).
Underlying EPS is underlying profit (page 9) divided by weighted average number of shares
Free cash flow is reconciled on page 10
Cash reported at 30 June 2020 excludes $3.1 million of restricted cash, and takes into account the dividend paid in June
Reported cash less IFRS debt (page 10)

Highlights

Cash of $355 million at 30 June 2020 ($353 million at 30 June 2019)
Net cash of $57 million at 30 June 2020 (net cash of $56 million at 30 June 2019)

$110 million received from the Kurdistan Regional Government ('KRG') in H1 2020

Updated payment mechanism introduced in April, under which the KRG committed to settling

monthly sales invoices by the middle of the following month

$121 million remains outstanding in relation to oil sales from November 2019 to February 2020 - discussions continue with the KRG over settlement arrangements

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Despite the monies outstanding, the fall in oil price and non-payment of the override, $6.5 million of free cash flow was generated in H1 2020 due to Genel's low-costs and resilient business model allowing flexible expenditure
o Production cost of $2.9/bbl in H1 2020
o Capital expenditure of $58.5 million in H1 as spending cut due to the external environment o G&A costs of $6.6 million, a reduction of c.30% year-on-year, as activity is rephased
Production of 32,100 bopd in H1 2020, due in part to the impact of COVID-19, coupled with payment uncertainty, resulting in reduced drilling activity at the Tawke PSC
o Production averaged 33,000 bopd in July 2020, following fast tracking of activity at the Tawke PSC against an improved backdrop
Continued focus on safety: zero lost time incidents and zero losses of primary containment in the period
Impairments of $286 million largely due to reduction in Brent oil price forecast
Interim dividend of 5¢ per share confirmed (2019: 5¢ per share)

Outlook

Genel's low-cost production, flexible capital investment programme, and robust balance sheet makes it resilient to lower oil prices, and the Company expects to retain a net cash position at the end of 2020 at the prevailing oil price, while still investing in key growth assets
Capex of c.$45 million expected in H2, with c.50% to be spent on moving Sarta to production in Q4, where work has continued despite the challenges resulting from COVID-19
Genel continues discussions with the KRG regarding the recovery of the $121 million receivable

Enquiries:
Genel Energy	+44 20 7659 5100
Andrew Benbow, Head of Communications
Vigo Communications	+44 20 7390 0230
Patrick d'Ancona

There will be a presentation for analysts and investors today at 0900 BST, 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. The information contained herein has not been audited and may be subject to further review.

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CEO STATEMENT

No natural resources company has been immune from the impacts of COVID-19 and the resulting collapse in demand and fall in the oil price. In the face of this material change in circumstances, we focused on controlling what is within our power to control in the near-term, while continuing to build the business fit for a future of fewer and better natural resources projects in the long-term. In this regard our business model positions us well both now, as we have a strong balance sheet and limited fixed capital expenditure, and for the future.

We have a business model designed for tough times, and we moved quickly to rebase our spending appropriately for the external environment, reducing our full-year capital expenditure forecast by c.$75 million to just over $100 million, and continuing to focus on managing costs elsewhere in the business.

Given the external environment, we continued to allocate capital to those areas that can provide the greatest returns and deliver shareholder value. Due to the oil price and lack of certainty over the deferred receivable and override payments, investing at Taq Taq is not currently a priority, and work at Tawke has the ability to rapidly scale up as the external environment improves. Despite the reduction in investment, production from Tawke has been in line with internal expectations, and the significant increase in production in July is an encouraging illustration of what can be achieved once investment resumes.

The key focus of capital allocation in 2020 has been Sarta, where work is continuing along a critical path to production in Q4. Genel is already the only multi-licence producer in the KRI, and further diversifying production by bringing Sarta into production with its tremendous growth potential is a milestone that we are all looking forward to reaching.

It is a testament to our balance sheet and careful financial management that, even with $121 million outstanding from the KRG for production in November 2019 to February 2020 and override payments unpaid, we are able to continue allocating capital to direct returns to shareholders, and our interim dividend of 5¢ per share has been retained.

While the mechanism through which the receivable from the KRG will be recovered has yet to be finalised, we are confident that a solution that works for both parties will be found, as has been done in the past, and our discussions with the KRG continue.

ESG

As the external environment has deteriorated due to COVID-19, it has not lessened our focus on ESG. The safety of our workforce and contractors remains a key priority, and we are pleased to continue our record of not having a lost-time injury since 2015. We are also working hard on improving our ESG activities, and better communicating the things that we already do well.

We recognise that we have a long way to go, but are proud of our track record in the KRI, where we have aimed to have a positive impact ever since our operations started almost 15 years ago. In this time, we have funded and successfully delivered 245 social investment and community projects, spending almost $60 million.

In the first half of the year we have become a member of both Transparency International UK and TRACE, and become a signatory of the United Nations Global Compact, supporting our aim of being a socially responsible contributor to the global energy mix. Our sustainability report, due in September, will provide further detail and enhanced disclosure on all ESG aspects.

OPERATING REVIEW

The impact of COVID-19 led to a significant reduction in activity in 2020. By this point of the year, we were expecting to have continued an active drilling programme at Tawke and Peshkabir, to be drilling at Qara Dagh, and for Sarta to be advancing towards production. The fall in the oil price and the delay in receipt of payments from the KRG, resulted in an appropriate reduction in expenditure at the Tawke PSC, while the direct impact of COVID-19 on supply chains and the movement of people into the KRI forced us to

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notify the KRG of the occurrence of a force majeure event preventing the Company from being able to perform its contractual obligations as scheduled at Qara Dagh.

Work has continued at Sarta, our key capital allocation priority in 2020, and despite the challenges faced initial production is still expected later this year.

Production

In line with internal expectations given the updated work plan.

	Gross	Net	Gross	Net
(bopd)	production	production	production	production
	H1 2020	H1 2020	H1 2019	H1 2019
Tawke	59,790	14,950	71,700	17,920
Peshkabir	48,790	12,200	54,950	13,740
Taq Taq	11,260	4,950	13,150	5,780
Total	119,840	32,100	139,800	37,440

PRODUCING ASSETS

Tawke PSC (25% working interest)

Gross production from the Tawke licence averaged 108,580 bopd during the first half of 2020, and 102,000 bopd during the second quarter of the year, as the operator halted development activity to preserve cash at a time of historically low and uncertain oil prices.

In June 2020, following the stabilisation of oil prices and export payments, activity was fast tracked at the Tawke licence and production quickly increased by 15,000 bopd month-on-month to raise average July 2020 production to 115,000 bopd.

The Peshkabir-to-Tawke gas reinjection project (the first enhanced oil recovery project in the KRI) was commissioned in June, and aims to unlock additional oil reserves at Tawke while significantly reducing gas flaring and CO2 emissions at Peshkabir.

Taq Taq (44% working interest, joint operator)

Production at Taq Taq averaged 11,260 bopd in H1, in line with expectations given the activity plan. As has been the case for some time, activity at Taq Taq is focused on maximising cash generation and, given the oil price, the TT-35 well, which completed in April, was the only well in the 2020 drilling programme. This well initially added c.600 bopd to production, but is no longer producing, following a mechanical issue.

Activity at the field will remain appropriate for the external environment and aligned with our capital allocation priorities, and it is not expected that there will be any further drilling activity in 2020.

PRE-PRODUCTION ASSETS

Sarta (30% working interest)

Despite the significant operational challenges caused by COVID-19, including the closure of borders impacting supply chains and the movement of people into the KRI, work has continued at Sarta, and first oil remains on target for Q4 this year. Civil construction work at the field is materially complete, with remaining work now focussing on the completion and commissioning of the 20,000 bopd capacity early- production facility.

Production will begin following the recompletion of the Sarta-2 well, re-entry of the Sarta-3 well, and commissioning of the facility through which oil will be produced and processed ahead of tanker loading and transport to the export pipeline at Khurmala.

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With first oil now in sight, plans are well underway for the next stage of the phase 1A pilot development, an appraisal programme which aims to fully utilise the facility capacity and convert more of the 253 MMbbls of gross resources assigned by ERCE to the Mus-Adaiyah-Butmah reservoirs into reserves. A three well campaign is scheduled for 2021, with environmental baselining underway ahead of construction of the well pads, in line with the previously announced schedule. The first of these wells, S-6, is expected to spud in Q1 and will be followed immediately by the S-1D well. While focussing on the primary Mus- Adaiyah-Butmah reservoirs these wells are also set to target additional reservoir intervals, a cost-efficient way to maximise the gathering of information which will help inform the Company's view of the wider potential of Sarta.

In order to minimise the time between appraisal success and monetisation the field partners are investigating a range of options for oil production from these 2021 wells.

Qara Dagh (40% working interest, operator)

Due to ongoing uncertainty caused by COVID-19, Genel notified the KRG of the occurrence of a force majeure event preventing the Company from being able to perform its contractual obligations as scheduled. Work continues to take place to ensure that Genel is in the best possible position to start to drill the QD-2 well once external conditions improve and the force majeure event ceases. This has included the securing of an amendment to the rig contract with Parker, in expectation of the future lifting of the force majeure event, while from a community engagement perspective emergency food aid has been provided to vulnerable groups within the Qara Dagh community, and the construction of firebreaks in nearby agricultural land have been funded.

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

As previously stated, Genel received documentation from the KRG in mid-April, and then further documents were received in June. This documentation did not adequately reflect the commercial concepts and risk sharing that were expected for the development of Bina Bawi's gas and oil resources.

Discussions are now taking place with the KRG at the highest level as Genel seeks to progress the development of Bina Bawi.

African exploration

A farm-out process relating to the highly prospective SL10B13 block (100% working interest and operator) in Somaliland began in Q4 2019 and while conditions for farm-out have been challenging in the first half of 2020, a number of companies continue to engage with the Company with respect to the opportunity.

Regarding Morocco, and the Lagzira block (75% working interest and operator), despite the logistical challenges posed by COVID-19 having caused some delay to the completion of the 3D seismic processing project being carried out by Western Geco, Genel continues to work towards a future farm-out campaign aimed at bringing a partner onto the licence prior to considering further commitments.

FINANCIAL REVIEW

Overview

The impact of COVID-19 has been significant. The resulting drop in oil demand exacerbated the fall in oil price this year, which deteriorated from around $60/bbl at the start of 2020 to a low of under $20/bbl in April. Although the oil price has since improved, there remains significant uncertainty as to how COVID- 19 and its aftermath will impact economies, oil demand and therefore oil price over the near and mid- term. This has caused significant economic pressure on the KRG's finances, pressure that has manifested itself in two ways: firstly, the deferral of payments owed by the KRG for sales made in the four months from November 2019 to February 2020 inclusive, amounting to $121 million; secondly, the non-payment of the Tawke override royalty from 1 March 2020.

It is clear that macro-economic uncertainty will extend into 2021 and likely beyond, creating a challenging backdrop against which to progress our business and seek to deliver on our commitment to run a business

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that is resilient to downside scenarios, is cash generative, and delivers growth when other oil and gas companies cannot.

All of the above means that the Company's business model, developed over the past few years to be profitable at low prices and resilient at very low prices, has been tested on its ability to:

Progress value creative growth projects in a challenging environment;
Demonstrate material flexibility in capital allocation, supporting the generation of free cash flow even at low oil prices;
Pay a dividend.

Our assessment is that our business model has stood up well to the challenge. Much of the hard work done in previous years has positioned us well: costs have had previous scrutiny so required optimisation rather than a radical overhaul; and asset development plans had been set up within a high capital flexibility model that mitigates financial risk, optimises cash generation and expedites capital return and payback, so we were able to adapt plans to the external environment.

The table below summarises our financial performance in the first half of 2020 (all figures $ million unless stated):

	H1 2020	H1 2019	FY 2019
Brent average oil price	$40/bbl	$65/bbl	$64/bbl
Revenue	88.4	194.3	377.2
Opex	(16.8)	(18.1)	(37.7)
G&A (excl. depreciation and amortisation)	(6.5)	(8.9)	(17.7)
EBITDAX	65.1	167.3	321.8
Producing asset capex	(35.7)	(53.3)	(115.1)
Net cash interest1	(13.4)	(12.6)	(23.4)
Surplus before growth capex and dividend	16.0	101.4	183.3
Development capex	(11.5)	(11.3)	(22.1)
Exploration and appraisal capex	(11.3)	(7.6)	(20.9)
(Deficit) / Surplus	(6.8)	82.5	140.3
Working capital and other	13.3	(25.8)	(41.3)

Free cash flow	6.5	56.7	99.0

1 Net cash interest is bond interest payable less bank interest income (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
The capital needs for Sarta first oil had already been optimised in line with our business plan (low capital need, early cash generation), meaning that even in this financial environment, we have been able to continue to allocate capital to the project
Force majeure declared at Qara Dagh, but we have continued to invest where possible to position the project for a rapid and efficient restart once force majeure is lifted and operating conditions permit

The overall result is that revenue generated in the period more than cover our costs, resulting in a surplus of $16.0 million before investment in growth. Our investment in growth projects, principally Sarta and Qara Dagh, reduced that surplus to a deficit for the period of $6.8 million, with working capital movements turning that deficit into a positive free cash flow of $6.5 million. This has enabled the Company to preserve its balance sheet strength, reporting net cash of $355 million. Despite not receiving $120.8 million due in the period, this is a reduction of only $22 million from the post-interim dividend cash number reported at 31 December 2019 of $377 million.

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Accounting impairments

Despite the business model proving to be resilient in the first half, there has been a significant reduction in both near-term and long-term oil price forecasts, with the change from the assumptions used for the previous reporting period summarised in the table below:

$/bbl	2020	2021	2022	2023	2024
Forecast	40	43	50	55	60
Year-end forecast	65	67	68	72	73

The decrease in oil price, and to a significantly lesser extent the increase in discount rate and deferral of some barrels into future periods as a result of reduced activity, has resulted in a significant decrease in the net present value of the Company's oil and gas assets. This has resulted in a total impairment of $286.3 million.

In addition, there has been an impairment of $34.9 million to the $120.8 million nominal value of receivables owed by the KRG for sales made in the four months from November 2019 to February 2020. The net present value has been estimated for accounting purposes based on the initial communication from the KRG, which indicates repayment would commence once oil price is above $50/bbl. However, the mechanism for, and pace of, repayment has not yet been agreed, and Genel expects to receive the nominal balance owed of $120.8 million in full.

Resilient financial strength - well positioned to take advantage of an unpredictable environment

With cash of $355 million, producing asset cash flows that cover corporate and bond interest costs and fund pre-production investment, and Sarta expected to be on production by the end of the year, the Company is well positioned for 2021.

Genel will be ready to capitalise if the macro-environment starts to improve, with a business that is already cash generative when investing in pre-production growth projects and with a material receivable balance expected to be recovered in line with the improvement in oil price. In a downside scenario our business model and financial strength provides us with an opportunity to take advantage both organically and inorganically: with potential to drill Qara Dagh at a lower cost than might have been expected, and the potential to acquire new assets that may become available due to the financial stress on less resilient businesses.

Capital allocation and growth

As set out above, our business model supports the preservation of our financial strength and has led us to generate cash even in a period with a low oil price and irregular receipts of payments. Looking forward, due to COVID-19 and the related oil price uncertainty, there remains a lack of clarity on the mechanism for the recovery of the $121 million of monies owed and the timing of the resumption of Tawke override payments. There is therefore uncertainty over the timing and value of very material cash inflows that were previously included in our base case near to mid-term liquidity planning scenarios.

This emphasises the considerable extent to which our business model has been tested and how durable it has proved to be. However, the quantum of the uncertainty over timing of receipt of monies that we are contractually due is significant and means that there is a very wide range of liquidity outcomes ahead of us. The level of capital that is appropriate for the Company to commit to its capital allocation priorities depends on its confidence in the quantum and timing of future cash flows, and Genel constantly reviews its capital allocation plans, aiming to deliver the greatest returns and to preserve balance sheet strength.

The Company has a portfolio that contains assets with material value creation possibilities, with discovered resource with the potential to add incremental value to the share price greater than the current market capitalisation of the Company. The higher our confidence in receipts, and dependent on operating conditions, the more pace can be brought to the development of these projects in the event that commercial, technical and operational conditions support investment.

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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 sustainable and material dividend, and $41 million was distributed to shareholders. The dividend remains a core part of our business model, which is focused on growth and the protection of financial strength. The financial strength of our business and the flexibility in our cost base enabled us to reaffirm the final dividend at our full-year 2019 results, and we have retained our interim dividend of 5¢ per share.

Financial priorities and outlook

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	• Net cash expected to be maintained at year-
through existing market conditions	end at current oil price

• Continued focus on capital allocation,	• Despite COVID-19 bringing material challenges:
with prioritisation of highest value	progression towards Sarta first oil in 2020 and
investment in assets with ongoing or	investment in Qara Dagh appraisal, once force
near-term cash and value generation	majeure removed, remain our key capital
	allocation priorities

• Delivery of a 2020 work programme on	• A recut 2020 work programme and budget
time and on budget, that is appropriate	preserving liquidity and reducing costs
to the external environment	• We are reducing spend on controllable inputs
• Continued focus on identifying and	• Management continues to seek growth
developing additional assets that offer	opportunities that fit the Company's capital
potential for significant value to the	structure and business model
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

Our capital allocation philosophy remains the same, despite the recent fall in oil price - invest in those projects with the potential to create most shareholder value, targeting those assets that fit the criteria set out previously.

In light of the likely macro volatility and uncertainty that lies ahead, in order to maximise our ability to move quickly and deploy capital to take advantage of prevailing conditions, the Board has decided to reverse its previous decision to comply with premium listing rules. The principal impact of this is that the Company will no longer apply chapter 10 of the Listing Rules with respect to classifying transactions (such as acquisitions and disposals) and so will have the benefit of being able to execute transactions more efficiently, a significant advantage in the current environment. See note 13 for more information.

We will continue to be disciplined in our capital allocation and invest in areas that can deliver most shareholder value. Rigorous cost management will be maintained across all operations, ensuring spend is sufficient to take advantage of the growth opportunities in the portfolio, and to maximise (net present) value of the portfolio.

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A summary of the financial results for the year is provided below.

Financial results for the period

Income statement

(all figures $ million)	H1 2020	H1 2019	FY 2019
Production (bopd, working interest)	32,100	37,400	36,250

Profit oil	24.0	64.6	117.2
Cost oil	47.6	69.4	147.2
Override royalty	16.8	60.3	112.8

Revenue	88.4	194.3	377.2
Operating costs	(16.8)	(18.1)	(37.7)
G&A (excl. depreciation and amortisation)	(6.5)	(8.9)	(17.7)
EBITDAX	65.1	167.3	321.8
Depreciation and amortisation	(82.6)	(74.8)	(158.5)
Net interest	(14.7)	(15.5)	(27.7)
Income tax expense	-	(0.4)	(0.7)
Underlying (loss) / profit	(32.2)	76.6	134.9
Impairment	(321.2)	-	(29.8)
Exploration expense	(1.3)	(0.6)	(1.2)

(Loss) / Profit	(354.7)	76.0	103.9

Working interest production of 32,100 bopd decreased year-on-year (H1 2019: 37,400 bopd), principally as a result of lower average production from Peshkabir, with the decrease in revenue from $194.3 million

to $88.4 million, principally caused by:
-	Lower Brent	$62 million
- Lower capex resulting in lower cost oil	$21 million
-	Lower production	$10 million
- Override unpaid from March onwards	$10 million

Production costs of $16.8 million decreased from last period (H1 2019: $18.1 million) as a result of scaled back activity in producing assets. Production cost per barrel increased from $2.7/bbl to $2.9/bbl due to decreased production. General and administration costs were $6.6 million (H1 2019: $9.5 million), of which corporate cash costs were $4.9 million (H1 2019: $6.6 million). The reduction from the prior period is a result of optimisation of costs and increased operational activity, principally at Sarta and Qara Dagh. The decrease in revenue resulted in EBITDAX of $65.1 million (H1 2019: $167.3 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. Underlying profit is presented in order to understand the profitability of the recurring business, excluding the impact of items that tend to be one off in nature, such as impairment and exploration expenditure.

Depreciation of $51.6 million (H1 2019: $39.7 million) and Tawke intangibles amortisation of $30.9 million

(H1 2019: $34.5 million) increased as a result of a combination of decrease in production profile and

higher estimated future costs on the Tawke PSC (depreciation/bbl: $8.6/bbl (H1 2019: $5.8/bbl), noting that these costs are fully recoverable.

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 2 (H1 2019: nil).

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Bond interest expense of $15.0 million was in line with the prior period. Finance income of $1.6 million (H1 2019: $2.4 million) was bank interest income. Other finance expense of $1.3 million (H1 2019: $2.9 million) included a non-cash discount unwind expense on liabilities.

In relation to taxation, under the terms of the KRI production sharing contracts, corporate income tax due is paid on behalf of the Company by the KRG from the KRG's own share of revenues, resulting in no corporate income tax payment required or expected to be made by the Company. Tax presented in the income statement was related to taxation of the service companies (H1 2020: nil, H1 2019: $0.4 million).

Capital expenditure

Capital expenditure is the aggregation of spend on production assets ($35.7 million) and pre-production assets ($22.8 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 $58.5 million, predominantly focused on production assets and the Sarta PSC ($11.5 million) and Qara Dagh ($4.4 million):

(all figures $ million)	H1 2020	H1 2019	FY 2019
Cost recovered production capex	35.7	53.3	115.1
Pre-production capex - oil	11.5	11.3	22.1
Pre-production capex - gas	5.9	5.6	11.9
Other exploration and appraisal capex	5.4	2.0	9.0
Capital expenditure	58.5	72.2	158.1

Cash flow, cash, net cash and debt

Gross proceeds received was $110.0 million (H1 2019: $167.5 million), of which $22.9 million (H1 2019: $54.2 million) was received for the override royalty.

(all figures $ million)	H1 2020	H1 2019	FY 2019
Brent average oil price	$40/bbl	$65/bbl	$64/bbl
Operating cash flow	85.5	142.3	272.9
Producing asset cost recovered capex	(38.1)	(48.7)	(105.1)
Development capex	(11.6)	(9.4)	(18.7)
Exploration and appraisal capex	(13.7)	(12.2)	(26.5)
Restricted cash	(0.1)	-	7.0
Interest and other	(15.5)	(15.3)	(30.6)

Free cash flow	6.5	56.7	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 flow before dividend was $6.5 million, with an overall decrease in cash of $35.4 million in the period (H1 2019: $19.0 million increase).

(all figures $ million)	H1 2020	H1 2019	FY 2019
Free cash flow	6.5	56.7	99.0
Dividend paid (incl. expenses)	(41.3)	(29.0)	(29.0)
Purchase of shares	(0.7)	(8.7)	(13.5)
Other	0.1	-	(0.1)

Net change in cash	(35.4)	19.0	56.4
Opening cash	390.7	334.3	334.3

Closing cash	355.3	353.3	390.7
Debt reported under IFRS	(298.1)	(297.5)	(297.9)
Net cash / (debt)	57.2	55.8	92.8

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Closing cash of $355.3 million and net cash of $57.2 million (H1 2019: $55.8 million) exclude restricted

cash of $3.1 million (H1 2019: $10.0 million). Net cash is reported in order for users of the financial statements to understand how much cash remains if the Company paid its debt obligations from its available cash on the period end date.

Reported IFRS debt was $298.1 million (31 December 2019: $297.9 million), comprised of $300 million of bond debt less amortised costs. The bond pays a 10.0% coupon and matures in December 2022. A reconciliation of debt and cash is provided in note 11 to the financial statements.

The bond has three financial covenant maintenance tests:

Financial covenant	Test	H1 2020
Net debt / EBITDAX	< 3.0	(0.3)
Equity ratio (Total equity/Total assets)	> 40%	64%
Minimum liquidity	> $30m	$355m

Net assets

Net assets at 30 June 2020 were $1,005.7 million (31 December 2019: $1,386.1 million) and consist

primarily of oil and gas assets of $1,107.5 million (31 December 2019: $1,412.5 million), trade receivables

of $90.2 million (31 December 2019: $150.2 million) and net cash of $57.2 million (31 December 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

Interim dividend distribution of $13.6 million was paid in January 2020, and a final dividend distribution of $27.7 million in June 2020 (June 2019: $27.4 million).

The Board is recommending no change in the interim dividend of 5¢ per share (2019: 5¢ per share), a

total distribution of c.$13.6 million. Total dividends declared in 2020 amount to $41.3 million (2019: $40.8

million), representing 15¢ per share (2019: 15¢ per share). The payment timetable for the interim dividend is below:

Ex-dividenddate: 12 November 2020
Record Date: 13 November 2020
Payment Date: 11 December2020

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 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.

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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 2019 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 2019. A list of current directors is maintained on the Genel Energy plc website: www.genelenergy.com

By order of the Board

Bill Higgs

CEO

5 August 2020

Esa Ikaheimonen

CFO

5 August 2020

Disclaimer

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Condensed consolidated statement of comprehensive income

For the period ended 30 June 2020

		6 months	6 months	Year
		to 30 June	to 30 June	to 31 Dec
		2020	2019	2019
	Note	$m	$m	$m
Revenue	3	88.4	194.3	377.2
Production costs	4	(16.8)	(18.1)	(37.7)
Depreciation and amortisation of oil assets	4	(82.5)	(74.2)	(157.1)
Gross (loss) / profit		(10.9)	102.0	182.4
Exploration expense	4	(1.3)	(0.6)	(1.2)
Impairment of intangible assets	4,8	(44.3)	-	-
Impairment of property, plant and equipment	4,9	(242.0)	-	(29.8)
Impairment of trade receivables	4,10	(34.9)	-	-
General and administrative costs	4	(6.6)	(9.5)	(19.1)
Operating (loss) / profit		(340.0)	91.9	132.3

Operating (loss) / profit is comprised of:
EBITDAX		65.1	167.3	321.8
Depreciation and amortisation	4	(82.6)	(74.8)	(158.5)
Exploration expense	4	(1.3)	(0.6)	(1.2)
Impairment of intangible assets	4,8	(44.3)	-	-
Impairment of property, plant and equipment	4,9	(242.0)	-	(29.8)
Impairment of trade receivables	4,10	(34.9)	-	-

Finance income	5	1.6	2.4	6.6
Bond interest expense	5	(15.0)	(15.0)	(30.0)
Other finance expense	5	(1.3)	(2.9)	(4.3)
(Loss) / Profit before income tax		(354.7)	76.4	104.6
Income tax expense	6	-	(0.4)	(0.7)
(Loss) / Profit and total comprehensive (expense) / income		(354.7)	76.0	103.9
Attributable to:
Shareholders' equity		(354.7)	76.0	103.9
		(354.7)	76.0	103.9
(Loss) / Profit per ordinary share		¢	¢	¢
Basic	7	(128.9)	27.2	37.8
Diluted	7	(128.9)	27.1	37.4
Underlying1		(11.7)	27.4	49.0

1. Underlying profit is reconciled on page 9

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Condensed consolidated balance sheet

At 30 June 2020

		30 June	30 June	31 Dec
		2020	2019	2019
	Note	$m	$m	$m
Assets

Non-current assets
Intangible assets	8	716.0	796.1	775.6
Property, plant and equipment	9	391.5	641.2	636.9
		1,107.5	1,437.3	1,412.5
Current assets
Trade and other receivables	10	98.3	125.6	157.4
Restricted cash		3.1	10.0	3.0
Cash and cash equivalents		355.3	353.3	390.7
		456.7	488.9	551.1

Total assets		1,564.2	1,926.2	1,963.6
Liabilities
Non-current liabilities
Trade and other payables		(124.7)	(120.8)	(118.8)
Deferred income		(26.8)	(28.1)	(26.7)
Provisions		(39.0)	(34.7)	(37.4)
Borrowings	11	(298.1)	(297.5)	(297.9)
		(488.6)	(481.1)	(480.8)
Current liabilities
Trade and other payables		(66.9)	(65.3)	(91.7)
Deferred income		(3.0)	(6.2)	(5.0)

		(69.9)	(71.5)	(96.7)

Total liabilities		(558.5)	(552.6)	(577.5)

Net assets		1,005.7	1,373.6	1,386.1
Owners of the parent
Share capital		43.8	43.8	43.8
Share premium account		4,005.4	4,046.6	4,033.4
Accumulated losses		(3,043.5)	(2,716.8)	(2,691.1)
Total equity		1,005.7	1,373.6	1,386.1

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Condensed consolidated statement of changes in equity For the period ended 30 June 2020

At 1 January 2019

Profit and total comprehensive income

Share-based payments

Purchase of shares to satisfy share awards

Purchase of treasury shares

Dividend payment

At 30 June 2019

At 1 January 2019

Profit and total comprehensive income

Share-based payments

Purchase of shares to satisfy share awards

Purchase of treasury shares

Dividends provided for or paid1

At 31 December 2019 and 1 January 2020

Loss and total comprehensive expense Share-based payments

Purchase of shares for employee share awards Dividends provided for or paid1

At 30 June 2020

Share	Share	Accumulated	Total
capital	premium	losses	equity
$m	$m	$m	$m
43.8	4,074.2	(2,786.6)	1,331.4
-	-	76.0	76.0
-	-	2.5	2.5
-	-	(8.2)	(8.2)
-	-	(0.5)	(0.5)
-	(27.6)1	-	(27.6)

43.8	4,046.6	(2,716.8)	1,373.6
43.8	4,074.2	(2,786.6)	1,331.4
-	-	103.9	103.9
-	-	5.1	5.1
-	-	(8.2)	(8.2)
-	-	(5.3)	(5.3)
-	(40.8)	-	(40.8)

43.8	4,033.4	(2,691.1)	1,386.1
-	-	(354.7)	(354.7)
-	-	3.0	3.0
-	-	(0.7)	(0.7)
-	(28.0)	-	(28.0)

43.8	4,005.4	(3,043.5)	1,005.7

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).

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Condensed consolidated cash flow statement

For the period ended 30 June 2020

		30 June	30 June	31 Dec
		2020	2019	2019
	Note	$m	$m	$m
Cash flows from operating activities
(Loss) / Profit and total comprehensive (expense) / income		(354.7)	76.0	103.9
Adjustments for:
Net finance expense	5	14.7	15.5	27.7
Taxation	6	-	0.4	0.7
Depreciation and amortisation	4	82.6	74.8	158.5
Exploration expense	4	1.3	0.6	1.2
Impairment of intangible assets	4	44.3	-	-
Impairment of property, plant and equipment	4	242.0	-	29.8
Impairment of receivables	4	34.9	-	-
Other non-cash items		(0.3)	(1.4)	(2.4)
Changes in working capital:
Decrease / (Increase) in trade receivables		22.0	(21.8)	(55.4)
Decrease / (Increase) in other receivables		0.1	-	(0.2)
(Decrease) / Increase in trade and other payables		(2.7)	(3.7)	3.3
Cash generated from operations		84.2	140.4	267.1
Interest received	5	1.6	2.4	6.6
Taxation paid		(0.3)	(0.5)	(0.8)
Net cash generated from operating activities		85.5	142.3	272.9
Cash flows from investing activities
Purchase of intangible assets		(13.7)	(12.2)	(26.5)
Purchase of property, plant and equipment		(49.7)	(58.1)	(123.8)
Movement in restricted cash		(0.1)	-	7.0
Net cash used in investing activities		(63.5)	(70.3)	(143.3)
Cash flows from financing activities
Dividends paid to company's shareholders, including expenses		(41.3)	(29.0)	(29.0)
Purchase of shares for employee share trust		(0.7)	(8.2)	(8.2)
Purchase of treasury shares		-	(0.5)	(5.3)
Lease payments		(0.5)	(0.3)	(0.6)
Interest paid		(15.0)	(15.0)	(30.0)
Net cash used in financing activities		(57.5)	(53.0)	(73.1)
Net (decrease) / increase in cash and cash equivalents		(35.5)	19.0	56.5
Foreign exchange gain / (loss) on cash and cash equivalents		0.1	-	(0.1)
Cash and cash equivalents at 1 January		390.7	334.3	334.3
Cash and cash equivalents at 31 December		355.3	353.3	390.7

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Notes to the condensed 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 2020 and six months ended 30 June 2019 are unaudited and have been prepared in accordance with the Disclosure and Transparency Rules of the Financial Conduct Authority and with IAS 34 'Interim Financial Reporting' as adopted by the European Union and were approved for issue on 6 August 2020. 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 2019, which have been prepared in accordance with IFRS as adopted by the European Union. The annual financial statements for the period ended 31 December 2019 were approved by the board of directors on 18 March 2020. The report of the auditors was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under the Companies (Jersey) Law 1991. The financial information for the year to 31 December 2019 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. As a result, the Directors have assessed that the Company's forecast liquidity provides adequate headroom over its forecast expenditure for the 12 months from the date of signing the half-year condensed consolidated financial statements for the period ended 30 June 2020 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 2019.

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

Apart from those involving estimations (which are dealt with separately below), there are no significant judgements that the directors have made in the process of applying the Company's accounting policies and that has the most significant effect on the amounts recognised in the financial statements.

Significant estimates

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

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

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

Proven and probable reserves are estimates of the amount of hydrocarbons that can be economically extracted from the Company's assets. The Company estimates its reserves using standard recognised evaluation techniques. Assets assessed as proven and probable reserves are generally classified as property, plant and equipment as

P a g e | 18

development or producing assets and depreciated using the units of production methodology. The Company considers its best estimate for future production and quantity of oil within an asset based on a combination of internal and external evaluations and uses this as the basis of calculating depreciation and amortisation of oil and gas assets and testing for impairment.

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

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

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

Change in accounting estimate

The Company has updated its estimated production profiles 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 CGUs, which are classified under IFRS as exploration and evaluation intangible assets and consequently carry the inherent uncertainty explained above, include the key assessment that the projects will progress, which is outside of the control of management and is dependent on the progress of government discussions regarding supply of gas and sanctioning of development of both of the midstream for gas and the upstream for oil. 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 PSCs for both Bina Bawi and Miran, the KRG has a right (not an obligation) effective from 30 April 2020 and 31 May 2020 respectively to terminate the PSCs in the absence of new Gas Lifting Agreement(s) being in place. Extensive documentation including a new draft PSC was received in mid-April from the KRG and the Company has been informed that while negotiations are ongoing with respect to these documents it will not exercise the 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, the Company has updated the discount rate used for assessing the recoverable amount of its producing assets from 12.5% to 13.0%. This has 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.

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Change in accounting estimate - Tawke asset and Tawke RSA carrying value; Taq Taq carrying value

As a result of lower oil prices and levels of investment than were forecasted when the financial statements for the year-ended 31 December 2019 were finalised, together with the higher discount rate explained above, management has assessed that there are impairment indicators for both Tawke and Taq Taq. Management has performed its impairment assessments, 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.

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 2024 price then inflated at 2% per annum.

$/bbl	2020	2021	2022	2023	2024
Forecast	40	43	50	55	60
Year-end 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.

The trade receivable is recognised when the control of oil is transferred to the customer at the metering point, as this is the time the consideration becomes unconditional. The trade receivable reflects the Company's entitlement based on the netback price and oil transferred.

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. The initial communication received from the KRG indicated that once the oil price is around $50/bbl, a mechanism will be put in place for repayment of amounts owed. The Company has responded, with no agreement yet reached on timing or terms of repayment.

As a consequence of the deferred payments, the Company compared the carrying value of trade receivables with the present value of the estimated future cash flows mostly based on the KRG's initial communication, but it may be the timing and terms of recovery may be different. Under IFRS9, the Company has used a forward-looking impairment model based on lifetime expected credit loss (ECL) assessment. The model calculates 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 under IFRS is $34.9 million adjustment to the trade receivables. The Company provided detailed disclosures required by IFRS 9 ECL assessment in note 10.

Recognition of revenue generated by the override, arising from the Receivables Settlement Agreement (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 of nine months. Because management does not have sufficient confidence in timing or value of revenue to be received relating to the override, or to which barrels the override now relates, 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 30 June 2020 that has not been recognised is $9.6 million.

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. The adoption of these standards and amendments has had no impact on the Company's results or financial statement disclosures.

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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), Amendment to IFRS 16 Leases Covid 19-Related Rent Concessions (1 Jun 2020), Amendments to IFRS 4 Insurance Contracts - deferral of IFRS19 (1 Jan 2021).

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3. Segmental information

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

For the 6-month period ended 30 June 2020
		Pre-
	Production	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)

Revenue from contracts with customers includes $14.7 million (30 June 2019: $54.7 million, 31 December 2019: $104.3 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.

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

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For the 6-month period ended 30 June 2019

The Company has updated its segmental reporting on the basis of internal reports that are regularly reviewed by the CEO, the chief operating decision maker, in order to allocate resources to the segment and assess its performance.

		Pre-
	Production	production	Other	Total
	$m	$m	$m	$m
Revenue from contracts with customers	188.7	-	-	188.7
Revenue from other sources	5.6	-	-	5.6
Cost of sales	(92.3)	-	-	(92.3)
Gross profit	102.0	-	-	102.0
Exploration expense	-	(0.6)	-	(0.6)
General and administrative costs	-	-	(9.5)	(9.5)
Operating profit / (loss)	102.0	(0.6)	(9.5)	91.9

Operating profit / (loss) is comprised of
EBITDAX	176.2	-	(8.9)	167.3
Depreciation and amortisation	(74.2)	-	(0.6)	(74.8)
Exploration expense	-	(0.6)	-	(0.6)
Finance income	-	-	2.4	2.4
Bond interest expense	-	-	(15.0)	(15.0)
Other finance expense	(1.0)	(0.1)	(1.8)	(2.9)
Profit / (Loss) before income tax	101.0	(0.7)	(23.9)	76.4
Capital expenditure	53.3	18.9	-	72.2
Total assets	1,021.6	563.8	340.8	1,926.2
Total liabilities	(97.0)	(150.1)	(305.5)	(552.6)

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

P a g e | 23

For the 12-month period ended 31 December 2019
		Pre-
	Production	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.

P a g e | 24

4. Operating costs
	6 months to	6 months to	Year to 31
	30 June	30 June	December
	2020	2019	2019
	$m	$m	$m
Production costs	(16.8)	(18.1)	(37.7)
Depreciation of oil and gas property, plant and equipment	(51.6)	(39.7)	(88.8)
Amortisation of oil and gas intangible assets	(30.9)	(34.5)	(68.3)
Cost of sales	(99.3)	(92.3)	(194.8)

Exploration expense	(1.3)	(0.6)	(1.2)
Impairment of intangible assets (note 8)	(44.3)	-	-
Impairment of property, plant and equipment (note 9)	(242.0)	-	(29.8)
Impairment of trade receivables (note 10)	(34.9)	-	-
Corporate cash costs	(4.9)	(6.6)	(13.3)
Other operating expenses	(1.1)	(0.6)	(0.8)
Corporate share-based payment expense	(0.5)	(1.7)	(3.6)
Depreciation and amortisation of corporate assets	(0.1)	(0.6)	(1.4)
General and administrative expenses	(6.6)	(9.5)	(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.

5. Finance expense and Finance income
	6 months to	6 months to	Year to 31
	30 June	30 June	December
	2020	2019	2019
	$m	$m	$m

Bond interest payable	(15.0)	(15.0)	(30.0)
Other finance expense	(1.3)	(2.9)	(4.3)

Finance expense	(16.3)	(17.9)	(34.3)
Bank interest income	1.6	2.4	6.6

Finance income	1.6	2.4	6.6

Net finance expense	(14.7)	(15.5)	(27.7)

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

6. Income tax expense

Current tax expense is incurred on the profits of the Turkish and UK services companies. Under the terms of 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.

P a g e | 25

7. Earnings per share

Basic

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

	6 months to	6 months to	Year to 31
	30 June	30 June	December
	2020	2019	2019
(Loss) / Profit attributable to equity holders of the Company ($m)	(354.7)	76.0	103.9
Weighted average number of ordinary shares - number 1	275,197,007	279,435,346	275,197,007
Basic (loss) / earnings per share - cents per share	(128.9)	27.2	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 6-month period ended 30 June 2020, diluted EPS is anti-dilutive and therefore diluted EPS is the same as basic EPS:

	6 months to	6 months to	Year to 31
	30 June	30 June	December
	2020	2019	2019
(Loss) / Profit attributable to equity holders of the Company ($m)	(354.7)	76.0	103.9
Weighted average number of ordinary shares - number1	275,197,007	279,435,346	275,197,007
Adjustment for treasury shares	-	812,852	2,577,720
Weighted average number of ordinary shares and potential	275,197,007	280,248,198	277,774,727
ordinary shares
Diluted (loss) / earnings per share - cents per share	(128.9)	27.1	37.4

1 Excluding shares held as treasury shares

P a g e | 26

8. Intangible assets
		Exploration and	Tawke	Other
		evaluation assets	RSA	assets	Total
Cost	$m	$m	$m	$m
At 1 January 2019	1,493.2	425.1	6.8	1,925.1
Additions	7.6	-	0.4	8.0
Discount unwind of contingent consideration	4.3	-	-	4.3
At 30 June 2019	1,505.1	425.1	7.2	1,937.4
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	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
Accumulated amortisation and impairment
At 1 January 2019	(1,005.3)	(94.9)	(6.5)	(1,106.7)
Amortisation charge for the period	-	(34.5)	(0.1)	(34.6)
At 30 June 2019	(1,005.3)	(129.4)	(6.6)	(1,141.3)
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	-	(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)
Net book value
At 30 June 2019	499.8	295.7	0.6	796.1
At 31 December 2019	513.2	261.9	0.5	775.6
At 30 June 2020		528.9	186.7	0.4	716.0

Tawke RSA asset was impaired by $44.3 million, further explanation is provided in note 2.

		30 June	30 June	31 Dec
		2020	2019	2019
Book value		$m	$m	$m
Bina Bawi PSC	Discovered gas and oil, appraisal	362.5	347.4	352.9
Miran PSC	Discovered gas and oil, appraisal	121.6	117.9	120.3
Somaliland PSC	Exploration	34.1	33.4	33.8
Qara Dagh PSC	Exploration / Appraisal	10.7	1.1	6.2
Exploration and evaluation assets		528.9	499.8	513.2
Tawke overriding royalty		90.9	188.5	160.2
Tawke capacity building payment waiver	95.8	107.2	101.7
Tawke RSA assets		186.7	295.7	261.9

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

P a g e | 27

9. Property, plant and equipment

Cost

At 1 January 2019 Asset acquisitions Additions Right-of-use assets Net change in payable

Non-cash additions for ARO/share-based payments At 30 June 2019

At 1 January 2019 Asset acquisitions Additions Right-of-use assets Net change in payable

Non-cash additions for ARO/share-based payments At 31 December 2019 and 1 January 2020

Additions Right-of-use assets Net change in payable

Non-cash additions for ARO/share-based payments At 30 June 2020

Accumulated depreciation and impairment At 1 January 2019

Depreciation charge for the period

At 30 June 2019

At 1 January 2019

Depreciation charge for the period Impairment

At 31 December 2019 and 1 January 2020

Depreciation charge for the period

Impairment

At 30 June 2020

Net book value

At 30 June 2019

At 31 December 2019

At 30 June 2020

Book value

Producing	Development	Other
assets	assets	assets	Total
$m	$m	$m	$m
2,757.2	-	9.6	2,766.8
-	49.4	-	49.4
53.3	11.3	-	64.6
-	-	1.9	1.9
-	(1.9)	-	(1.9)
1.6	-	-	1.6
2,812.1	58.8	11.5	2,882.4
2,757.2	-	9.6	2,766.8
-	49.4	-	49.4
115.1	22.1	0.3	137.5
-	-	3.6	3.6
-	(3.6)	-	(3.6)
3.8	0.1	-	3.9
2,876.1	68.0	13.5	2,957.6
35.7	11.5	1.0	48.2
-	-	1.0	1.0
-	(1.8)	-	(1.8)
1.2	0.3	-	1.5
2,913.0	78.0	15.5	3,006.5
(2,192.1)	-	(8.9)	(2,201.0)
(39.7)	-	(0.5)	(40.2)
(2,231.8)	-	(9.4)	(2,241.2)
(2,192.1)	-	(8.9)	(2,201.0)
(88.8)	-	(1.1)	(89.9)
(29.8)	-	-	(29.8)
(2,310.7)	-	(10.0)	(2,320.7)
(51.6)	-	(0.7)	(52.3)
(242.0)	-	-	(242.0)
(2,604.3)	-	(10.7)	(2,615.0)
580.3	58.8	2.1	641.2
565.4	68.0	3.5	636.9
308.7	78.0	4.8	391.5
	30 June	30 June	31 Dec
	2020	2019	2019
	$m	$m	$m

Tawke PSC	Oil production	247.0	488.5	474.9
Taq Taq PSC	Oil production	61.7	91.8	90.5
Producing assets		308.7	580.3	565.4

Sarta PSC	Oil development	78.0	58.8	68.0

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

	Taq Taq CGU	Tawke CGU
	$m	$m
Long term Brent +/- $5/bbl	+/- 2	+/- 16
Discount rate +/- 2.5%	+/- 3	+/- 37
Production and reserves +/- 10%	+/- 4	+/- 39

P a g e | 28

10. Trade and other receivables

Trade receivables

Other receivables and prepayments

30 June	30 June	31 Dec
2020	2019	2019
$m	$m	$m
90.2	116.6	150.2
8.1	9.0	7.2
98.3	125.6	157.4

At 30 June 2020, $120.8 million relating to invoices from November 2019 to February 2020 was overdue and has required impairment of $34.9 million as explained in note 2. Under the Tawke and Taq Taq PSCs, payment for entitlement is due within 30 days.

Since February 2016, there has been a track record of payments being received three months after invoicing., but since April 2020 the KRG has been settling invoices within one month of invoicing, with $8.3m owed but not due at period end.

Trade receivables at 30 June 2020

Trade receivables at 30 June 2019 Trade receivables at 31 December 2019

Movement on trade receivables in the period Carrying value at 1 January

Revenue from contracts with customers Cash proceeds

Offset of payables due to the KRG Loss allowance

Capacity building payments

Carrying value at 31 December

		Year of sale of
		amounts overdue
Not due	2020	2019	Total
$m	$m	$m	$m
8.3		37.6	44.3	90.2
97.7		n/a	18.9	116.6
96.1		n/a	54.1	150.2
		30 June	30 June	31 Dec
		2020	2019	2019
		$m	$m	$m
		150.2	94.8	94.8
		86.3	188.7	368.7
		(110.0)	(167.5)	(317.4)
		(3.2)	-	-
		(34.9)	-	(0.5)
		1.8	0.6	4.6
		90.2	116.6	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 known. Explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 2.

	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 changes to the date on which the KRG commences repayment and the period of time over which repayment is made.

NPV13.0 of overdue					Timing of repayment start
	receivables ($m)
Immediate			1 Jan 2021			1 Jan 2022		1 Jan 2023


Periodfor	repayment			Bullet payment		120.8	113.6		100.5	89.0

		12-months		114.3		107.5	95.1		84.2


				24-months		107.7	101.3		89.7	79.3

				36-months		101.6	95.6		84.6	74.9

P a g e | 29

11. Borrowings and net cash
		Discount	Dividend	Net change
	1 Jan 2020	unwind	paid	in cash	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

The fair value of the bonds is $298.5 million (30 June 2019: $315.8 million, 31 December 2019: $316.5 million).

			Discount	Dividend	Net change
		1 Jan 2019	unwind	paid	in cash	30 June 2019
		$m	$m	$m	$m	$m
2022 Bond 10.0%	(297.3)	(0.2)	-	-	(297.5)
Cash	334.3	-	(27.4)	46.4	353.3
Net Cash	37.0	(0.2)	(27.4)	46.4	55.8
			Discount	Dividend	Net change
		1 Jan 2019	unwind	paid	in cash	31 Dec 2019
		$m	$m	$m	$m	$m
2022 Bond 10.0%	(297.3)	(0.6)	-	-	(297.9)
Cash	334.3	-	(27.4)	83.8	390.7
Net Cash		37.0	(0.6)	(27.4)	83.8	92.8

12. Capital commitments

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

13. Premium listing

In view of the fact that a premium listing is unlikely in the near-term, and in order to facilitate the creation of shareholder value through the ability to make rapid capital allocation decisions, the Company believes it is an appropriate time to step back from its previous decision to act as a premium listed company. This change will take effect after a transitional period of three months from the date of this announcement, after which the Company will no longer act as if it were premium listed and UK incorporated.

From that date, the Company will act in accordance with the requirements applicable to a standard listed company. The principal impact will be that the Company will no longer apply Chapter 10 of the Listing Rules with respect to classifying transactions (such as acquisitions and disposals) and so will have the benefit of being able to execute transactions more efficiently and competitively, a significant advantage in the current environment. Restrictions in Chapter 9 of the Listing Rules, including in relation to the terms of new equity issuances and Chapter 11 of the Listing Rules relating to related party transactions will also not be applied by the Company. Notwithstanding the change, the Company continues to be committed to a high standard of corporate governance, and will continue to comply in full with the UK Corporate Governance Code and with the Remuneration Regulations, so shareholders will still have a vote on remuneration.

P a g e | 30

Independent review report to Genel Energy plc

Report on the half-year condensed consolidated financial statements

Our conclusion

We have reviewed Genel Energy plc's half-year condensed consolidated financial statements (the "interim financial statements") in the half-year results of Genel Energy plc for the 6 month period ended 30 June 2020. Based on our review, nothing has come to our attention that causes us to believe that the interim financial statements are not prepared, in all material respects, in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

What we have reviewed

The interim financial statements comprise:

the condensed consolidated balance sheet as at 30 June 2020;
the condensed consolidated statement of comprehensive income for the period then ended;
the condensed consolidated cash flow statement for the period then ended;
the condensed consolidated statement of changes in equity for the period then ended; and
the notes to the interim financial statements.

The interim financial statements included in the half-year results have been prepared in accordance with International Accounting Standard 34, 'Interim Financial Reporting', as adopted by the European Union and the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

As disclosed in note 1 to the interim financial statements, the financial reporting framework that has been applied in the preparation of the full annual financial statements of the Group is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union.

Responsibilities for the interim financial statements and the review

Our responsibilities and those of the directors

The half-year results, including the interim financial statements, is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-year results in accordance with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority.

Our responsibility is to express a conclusion on the interim financial statements in the half-year results based on our review. This report, including the conclusion, has been prepared for and only for the company for the purpose of complying with the Disclosure Guidance and Transparency Rules sourcebook of the United Kingdom's Financial Conduct Authority and for no other purpose. We do not, in giving this conclusion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

What a review of interim financial statements involves

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 Auditing Practices Board 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.

We have read the other information contained in the half-year results and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim financial statements.

PricewaterhouseCoopers LLP

Chartered Accountants

London

5 August 2020

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Genel Energy plc published this content on 06 August 2020 and is solely responsible for the information contained therein. Distributed by Public, unedited and unaltered, on 06 August 2020 06:13:17 UTC

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Apr. 02	EXECUTIVE CHANGES: Filtronic appoints Nathaniel Edington as CEO	AN
Apr. 02	Genel Energy plc Announces Retirement of Michael Fallon to Its Board Effective; May 2024	CI

EXECUTIVE CHANGES: Filtronic appoints Nathaniel Edington as CEO	Apr. 02	AN
Genel Energy plc Announces Retirement of Michael Fallon to Its Board Effective; May 2024	Apr. 02	CI
Genel Energy "reshaped and resilient" but payout down after tough year	Mar. 26	AN
Genel Energy plc Reports Audited Production Results for the Full Year Ended December 31, 2023	Mar. 26	CI
Transcript : Genel Energy plc, 2023 Earnings Call, Mar 26, 2024	Mar. 26
Genel Energy plc Reports Earnings Results for the Full Year Ended December 31, 2023	Mar. 26	CI
Jefferies Upgrades Genel Energy to Buy from Hold, Raises PT	Feb. 21	MT
Unilever and Aviva both raised to 'buy'	Feb. 21	AN
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Glencore profit plunges as energy market normalises	Feb. 21	AN
Glencore profit plunges as energy market normalises	Feb. 21	AN
Genel Energy reshapes business after Iraq-Turkey pipeline suspension	Jan. 24	AN
Genel Energy to Seek M&A	Jan. 24	CI
Transcript : Genel Energy plc, Q4 2023 Sales/ Trading Statement Call, Jan 24, 2024	Jan. 24
Jefferies cuts Tullow; Berenberg likes Volex	Jan. 04	AN
Norway's DNO Boosts Output of Tawke Oilfield in Iraq	Dec. 19	MT
Jefferies Starts Genel Energy Coverage With Hold Rating	Nov. 16	MT
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Petra Diamonds chair to retire	Nov. 14	AN
Transcript : Genel Energy plc, Q3 2023 Sales/ Trading Statement Call, Nov 14, 2023	Nov. 14
Genel Energy plc Reports Production Results for the Third Quarter and Year to Date of 2023	Nov. 14	CI
EARNINGS AND TRADING: Wincanton profit down; James Cropper ups payout	Nov. 09	AN
Genel Energy non-executives buy GBP2.6 million in shares	23-10-18	AN
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Genel Energy oil output at Tawke "ramped up" post closure	23-10-16	AN

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CANADIAN NATURAL RESOURCES LIMITED	+21.31%	82.53B
EOG RESOURCES, INC.	+10.10%	75.79B
PIONEER NATURAL RESOURCES COMPANY	+20.20%	62.6B
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Genel Energy plc

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JE00B55Q3P39

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