GENL Genel Energy Plc

6 August 2024

Genel Energy plc - Unaudited results for the period ended 30 June 2024

 

Paul Weir, Chief Executive of Genel, said:

“We have continued to progress our priority workstreams, each of which can be transformational for the business, whilst maintaining our balance sheet strength by strict discipline on spend and capital allocation. 

 

Cash generative production continues from our flagship Tawke licence, where domestic sales demand has shown resilient consistency in the past 6 months and some recent price improvement.  We have efficiently closed down our unprofitable operated licences in the Kurdistan Region of Iraq (‘KRI’) and minimised our in-country footprint, while keeping people safe and continuing to act as a trusted partner to all our stakeholders. Significant cost reductions have been made across all aspects of the business wherever appropriate, and our organisational spend in the second half of the year will reduce further. The business has the potential to deliver significant shareholder value, well above the current market value of the business. The Tawke PSC is a world class asset with a long life ahead of it, and when exports restart can deliver over $100 million of entitlement free cash flow per annum to Genel, more than double the current level.

 

In association with our industry peers and other stakeholders, we continue to lobby regional and federal governments to break the current political impasse so that international exports of Kurdistan oil can resume in a manner that properly rewards IOCs that have chosen to invest in Kurdistan.  While progress is sporadic, recent participation by stakeholders in tripartite talks demonstrate that negotiations continue and support the view that a negotiated solution can be found.  

 

We continue to prioritise the acquisition of new assets to materially diversify our cash generation and reinvigorate our organic portfolio. Adding new assets to achieve geographical diversification is a strategic objective, but we will only buy an asset on terms that are clearly beneficial for our shareholders.

 

Regarding the London-seated Miran and Bina Bawi oil and gas assets arbitration, the written and evidentiary stages have now concluded. The timing of the award is not certain, but is expected before the end of 2024. Our view on the merits of our case remains unchanged since the arbitration process was initiated by the KRG in 2021.”

 

Results summary ($ million unless stated)

	H1 2024	H1 2023	FY 2023
Average Brent oil price ($/bbl)	84	80	82
Production (bopd, working interest)	19,510	13,440	12,410
Revenue	37.6	48.0	84.8
Opex	(8.2)	(14.7)	(21.3)
EBITDAX1	11.1	22.9	32.8
Operating loss	(15.8)	(11.2)	(19.2)
Cash flow from operations	36.4	39.2	55.1
Capital expenditure	15.9	47.5	68.0
Free cash flow2	8.5	(35.1)	(71.0)
Cash	370.4	425.0	363.4
Total debt	248.0	273.0	248.0
Net cash3	125.5	158.2	119.7
Basic LPS (¢ per share)	(7.9)	(14.6)	(22.0)

 

1. EBITDAX is operating loss adjusted for the add back of depreciation and amortisation, net write-off/impairment of oil and gas assets and net ECL/reversal of ECL receivables
2. Free cash flow is reconciled on page 6
3. Reported cash less debt reported under IFRS (page 6)

 

Summary

• We continue to sell domestically with the route to exports suspended
• Consistent production from the Tawke PSC, with minimal investment, has delivered average working interest production of 19,510 bopd in H1 2024 (H1 2023: 11,740 bopd)
• Domestic sales price has averaged $34/bbl for the period (2023: $35/bbl), with the last two months priced at $37/bbl, with all cash due for domestic sales received before the end of the period
• Net cash of $126 million (31 December 2023: $120 million)
  • Significant cash balance of $370 million (31 December 2023: $363 million)
  • Bond debt of $248 million (31 December 2023: $248 million)
• A socially responsible contributor to the global energy mix:
  • Zero lost time injuries ('LTI') and zero tier one loss of primary containment events at Genel and TTOPCO operations
  • Three million work hours since the last LTI 

 

Outlook

• Continued consistent production from the Tawke PSC at similar levels to the first half
• Organisational spend around $3 million per month
• Interest income $1-2 million per month, with one bond interest payment of $11.5 million due in October 
• Our cash generation has been above expectations in the first half of the year, and we reiterate our previous guidance that we expect closing net cash balance at the end of the year to be well above $100 million
• We continue to seek progression towards building a business that delivers resilient, reliable, repeatable and diversified cash flows that support a dividend programme by:
  • maintaining a strong balance sheet
  • working, together with our peers, towards the restart of exports and access to international pricing
  • seeking diversification of our income through the purchase of new assets
• The process for the London-seated international arbitration regarding Genel’s claim for substantial compensation from the KRG following the termination of the Miran and Bina Bawi PSCs has now been concluded, with closing submissions exchanged in May and reply reports exchanged in June. It is now for the panel to deliberate and then make an award. The timing of the award is not certain but is expected before the end of the year.
• Reverse tender offer to buy back bond announced today

 

Enquiries:

 

Genel Energy Luke Clements, CFO	+44 20 7659 5100
Vigo Consulting Patrick d’Ancona	+44 20 7390 0230

 

Genel will host a live presentation on the Investor Meet Company platform on Tuesday 6 August at 1000 BST. The presentation is open to all existing and potential shareholders. Questions can be submitted at any time during the live presentation. Investors can sign up to Investor Meet Company for free and add to meet Genel Energy PLC via: https://www.investormeetcompany.com/genel-energy-plc/register-investor 

 

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. While 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

Despite a strong operational performance in the period, with production performance consistent, realised price per barrel improving a little and activity milestones and cost reduction targets reached ahead of time, the business continues to feel the effects of the prolonged suspension of exports and the lack of access to international oil prices.

 

We continue to sell domestically at a price heavily discounted to the fundamental value of our product meaning our cash generation and organic delivery of shareholder value is materially impaired, with the Tawke PSC currently generating less than half of the entitlement free cash flow that current production levels would produce at export prices. Against that backdrop, the Company has limited appetite to risk capital in order to increase the volumes of oil sold at below market value, and consequently no new wells have been drilled in the period.

 

Despite this lack of investment, the Tawke PSC has again demonstrated that it is a world class asset with many years to run, consistently averaging around 80,000 bopd gross production in the period with a globally competitive operating cost of c.$2/bbl.

 

Against this combination of low realised price per barrel in the domestic market and the continued uncertainty on timing of export restart, we have continued to optimise spend across the business. As activity has ended or reduced, we have scaled back the organisation, absorbing work elsewhere or realising efficiency benefits from system and process improvements, while maintaining the capability necessary to support achievement our business objectives.

 

Regarding the resumption of exports, we saw signs of progress in January with reports of positive conversations taking place between the KRG and the Federal Government of Iraq (‘FGI’), but this then fell away. Around the end of May, we again saw signs of some new impetus to meet and find the terms that would support restart. More recently still there have been important meetings between regional and federal government leaders and we remain hopeful of an acceptable negotiated solution.

 

We remain of the view therefore that the export pipeline will reopen and we again note past communications to IOCs by both the Federal Government of Iraq and the Prime Minister of the Kurdistan Region of Iraq that the prevailing commercial terms will be respected and that all amounts owed will be paid.

 

We have a clear business model and plan, a strong balance sheet and a high quality and lean team working on the delivery of that plan.

 

We have a dedicated and experienced team in place analysing opportunities that will take the business in the right direction by adding near-term income, diversifying our portfolio to deliver reliable and repeatable cash flows. We remain disciplined and careful – although diversification is a priority, it is not a necessity for this Company to deliver material shareholder value. We will not transact a deal that is not good for shareholders.

 

On the London-seated arbitration regarding the Miran and Bina Bawi oil and gas asset, the written and evidentiary stage of the London-seated arbitration following the termination of the Miran and Bina Bawi PSCs has now concluded. The evidential hearing was held in February and the exchange of closing submissions in May and reply report submissions in June. We now await an award on liability and quantum, whose timing is uncertain but continues to be expected before the end of 2024. Our view of the merits of the case remains unchanged from when the dispute commenced under the PSCs in Q4 2021.

 

 

 

OPERATING REVIEW

 

KURDISTAN

With the ongoing suspension of the export pipeline meaning that the only market available is domestic sales, which are at heavily discounted prices, the Company has worked with its partners to minimise both operational spend and risking of capital, with no new wells drilled so far this year.

 

Gross production for the first half of 2024 was 78,050 bopd, well below what we would expect to produce if exports were available, but significantly higher than the first half last year, which produced minimal volumes after the pipeline was shut at the end of March. 

 

 

(bopd)	Gross production Domestic sales Q1 2024	Gross production Domestic sales Q2 2024	Gross production Domestic sales H1 2024	WI production Domestic sales H1 2024	WI production Exports H1 2023
Tawke	76,310	79,780	78,050	19,510	11,740
Taq Taq	-	-	-	-	1,220
Sarta*	-	-	-	-	480
Total	76,310	79,780	78,050	19,510	13,440

*Having served notice of surrender of the Company’s interest in the Sarta PSC, that surrender took effect on 30 November 2023.

 

Tawke PSC (Tawke and Peshkabir fields)

The Tawke PSC has delivered a significant increase in production compared to the first half of last year, which suffered from there being no production between the export pipeline being suspended on 27 March 2023 and the end of the period. Despite drilling no new wells this year, gross production from the Tawke PSC has been maintained at consistent levels, opening the year at 87,870 bopd, closing the half year at 81,800 bopd and averaging 78,050 bopd. This has been achieved by careful and diligent subsurface and operations management, with June also benefitting from wells that were drilled during the period of shutdown in the second quarter of last year being put on production.

 

Sales price has averaged $34/bbl over the course of the period compared to average Brent of $84/bbl, improving slightly in recent months to around $37/bbl.

 

The Company has generated revenue of $38 million from Tawke entitlement in the period.

 

The asset has delivered the robust production throughout the period and is expected to continue to do so. We will work with the operator to evaluate appropriate and capital efficient investment in order to ensure the production levels meet our needs.

 

The Operator continues to work diligently and expertly, continuously evolving the long-term field development plan for the two fields on the Tawke PSC. Upon reopening of the export pipeline, which reflects our contractual right to access international prices, reinstatement of an active drilling programme could see Tawke PSC production generating over $100 million of free cash flow annually for the Company.

 

Taq Taq

Taq Taq has been on care and maintenance since May last year, because the revenue it would generate at the established domestic sales prices would not adequately cover the operating costs. We have continued to drive cost reductions with the appointment of a new general manager, our monthly spend is now down to below $500,000.

 

Somaliland -SL10B13

As we continue to work towards the complete framework required to support drilling the Toosan-1 exploration well, we were pleased to have agreed an extension of the licence until the middle of 2026.

 

We continue to work on optimisation of the well plan to reduce cost and maximise efficiency of the well delivery process. In the meantime, our in-country team continues to work closely with our local communities, a highlight of which has been the provision of mobile medical services to over 800 patients a week during H1 2024. Given the success of the project a 2nd phase, through to the end of the year, has been initiated. 

 

Somaliland - Odewayne

We continue to work with our partners to characterise the prospectivity of the block, with subsurface studies ongoing. We are also continuing to invest in the communities, and in February 2024 delivered educational supplies to 1,000 primary and secondary school children across the block.

 

Morocco

The farm-out campaign on the Lagzira block (75% working interest and operator) is ongoing. We continue to progress the block Minimum Work Program, focussed on seismic reprocessing and subsurface studies to further define the prospectivity and potential of the block.

 

 

FINANCIAL RESULTS

The ongoing closure of the Iraq-Türkiye pipeline resulted in no export sales being made in the period, with all production sold domestically in Kurdistan.

 

(all figures $ million)	H1 2024	H1 2023	FY 2023
Brent average oil price ($/bbl)	84	80	82
Field level realised price per barrel ($/bbl)	34	60	47
Average price per working interest barrel ($/bbl)	11	19	19
Working interest production (bopd)	19,510	13,440	12,410
Cost oil	18.4	28.8	58.6
Profit oil	19.2	17.4	25.4
Override royalty	-	1.8	0.8
Revenue	37.6	48.0	84.8
Production costs	(8.2)	(14.7)	(21.3)
Production capex	(13.4)	(39.7)	(55.2)
Production business netback	16.0	(6.4)	8.3
Other operating costs and capex	(4.7)	(8.3)	(16.4)
G&A (excl. non-cash)	(14.2)	(9.0)	(25.5)
Net cash interest1	(2.3)	(2.2)	(4.2)
Net expense from discontinued operations	(0.9)	(3.5)	(11.6)
Working capital and other	14.6	(5.7)	(21.6)
Free cash flow	8.5	(35.1)	(71.0)
Dividend paid	-	(33.5)	(33.5)
Purchases of own shares	(1.5)	-	(1.8)
Purchases of own bonds	-	(1.0)	(24.9)
Net change in cash	7.0	(69.6)	(131.2)
Opening cash	363.4	494.6	494.6
Cash	370.4	425.0	363.4
Debt reported under IFRS	(244.9)	(266.8)	(243.7)
Net cash	125.5	158.2	119.7

 

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

 

Average production of 19,510 bopd is higher than the comparative period (H1 2023: 13,440 bopd) because of no production in Q2 2023. All production this year has been sold domestically at an average price of $34/bbl, compared to the comparative period when production was exported at an average price of $60/bbl. As a result of the lower realised price per barrel, revenue of $37.6 million is lower than revenue of $48.0 million reported last year.

 

Production costs of $8 million decreased from the prior period (H1 2023: $15 million), primarily as a result of there being no production from Taq Taq and optimisation of costs at Tawke. Cost per barrel of $2.3/bbl is an improvement from last year (H1 2023: $6.2/bbl).

 

Production capex has significantly reduced to $13 million (H1 2023: $40 million) as a result of significantly reduced activity as a result of the pipeline closure.

 

Cash general and administration costs were $14 million, an increase from last year (H1 2023: $9 million) primarily as a result of arbitration costs.

 

Interest income of $9 million (H1 2023: $11 million) and bond interest expense of $12 million (H1 2023: $13 million) decreased in line with cash and bond balances. Other finance expense of $3 million (H1 2023: $3 million) related to non-cash discount unwinding on provisions.

 

Following the termination of Sarta PSC in 2023, income statement figures of Sarta PSC have been disclosed as discontinued operation. Further details are provided in note 7 to the financial statements.

 

EBITDAX and cash flow

(all figures $ million)	H1 2024	H1 2023	FY 2023
EBITDAX	11.1	22.9	32.8
Working capital	25.3	16.3	22.3
Operating cash flow	36.4	39.2	55.1
Producing asset cost recovered capex	(12.1)	(37.9)	(66.6)
Development capex	(1.7)	(16.0)	(22.2)
Exploration and appraisal capex	(2.2)	(6.1)	(9.7)
Interest and other	(11.9)	(14.3)	(27.6)
Free cash flow	8.5	(35.1)	(71.0)

 

The decrease in revenue of $10 million resulted in a similar decrease to EBITDAX, which was $11 million (H1 2023: $23 million). EBITDAX is presented in order to illustrate the cash operating profitability of the Company and 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, impairments and write-offs.

 

Free cash flow is presented in order to illustrate the free cash generated for equity. Free cash flow was $9 million (H1 2023: $35 million outflow) with an overall increase due to the cash and carry basis of local sales and optimised spend.

 

Cash and debt

Cash of $370 million increased from the start of the year (31 December 2023: $363 million). The Company monitors its cash position, cash forecasts and liquidity on a regular basis. The Company holds surplus cash in treasury bills, time deposits or liquidity funds 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.

 

The nominal value of bond debt remained unchanged at $248 million, with reported net cash of $126 million (31 December 2023: $120 million). The bond debt matures in October 2025 and has two financial covenant maintenance tests:

 

Financial covenant	Test	H1 2024
Equity ratio (Total equity/Total assets)	> 40%	52%
Minimum liquidity	> $30 million	$370 million

Net assets

Net assets at 30 June 2024 were $414 million (31 December 2023: $434 million) and consist primarily of oil and gas assets of $321 million (31 December 2023: $331 million), net trade receivables of $93 million (31 December 2023: $93 million) and net cash of $126 million (31 December 2023: $120 million).

 

Going concern

The Directors have assessed that the Company’s forecast liquidity provides adequate headroom over debt maturity and forecast expenditure for the 17 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2024 and consequently that the Company is considered a going concern.

 

The Company is in a net cash position with sufficient funds to repay the bond that matures in October 2025 if required.

 

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: KRI Regional Oil & Gas Sector Risk, notably the current closure of the Iraq-Türkiye pipeline; Commercial Terms & Payment for Kurdish Sales, lack of oil export payments, as well as the recovery of the $107 million outstanding gross receivable; Development & Recovery of Oil Reserves; Arbitration; Reserves Replacement & Additions; New Business Activity; Capital Structure & Financing; Attract & Maintain Organisational Capability; Environmental, Social & Governance Expectations; Regulatory & Compliance Failure; and Health & Safety risks. Further detail on many of these risks was provided in the 2023 Annual Report.

 

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 2023. A list of current directors is maintained on the Genel Energy plc website: www.genelenergy.com

 

By order of the Board

 

Paul Weir

CEO

5 August 2024

 

Luke Clements

CFO

5 August 2024

 

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 2024

 

		Unaudited 6 months to 30 June 2024	Unaudited 6 months to 30 June 2023	Audited Year to 31 Dec 2023
	Note	$m	$m	$m
Revenue	3	37.6	48.0	84.8
Production costs	4	(8.2)	(14.7)	(21.3)
Depreciation and amortisation of oil assets	4	(25.7)	(24.7)	(43.9)
Gross profit		3.7	8.6	19.6
Exploration expense	4	(1.1)	(0.3)	(0.1)
Other operating costs		(2.2)	(0.5)	(3.6)
Net write-off of intangible assets	4	-	-	1.2
Net expected credit loss (‘ECL’) of receivables	4	-	(9.1)	(9.1)
General and administrative costs	4	(16.2)	(9.9)	(27.2)
Operating loss		(15.8)	(11.2)	(19.2)
Operating loss is comprised of:
EBITDAX		11.1	22.9	32.8
Depreciation and amortisation	4	(25.8)	(24.7)	(44.0)
Exploration expense	4	(1.1)	(0.3)	(0.1)
Net write-off of intangible assets	4	-	-	1.2
Net ECL of receivables	4	-	(9.1)	(9.1)
Finance income	5	9.2	10.5	20.6
Bond interest expense	5	(11.5)	(12.7)	(24.8)
Net other finance expense	5	(2.9)	(2.6)	(4.9)
Loss before income tax		(21.0)	(16.0)	(28.3)
Income tax expense	6	-	-	(0.2)
Loss and total comprehensive expense from continuing operations		(21.0)	(16.0)	(28.5)
Loss from discontinued operations	7	(0.9)	(24.7)	(32.8)
Loss and total comprehensive expense		(21.9)	(40.7)	(61.3)
Attributable to:
Owners of the parent		(21.9)	(40.7)	(61.3)
		(21.9)	(40.7)	(61.3)
Loss per ordinary share		¢	¢	¢
From continuing operations:
Basic	8	(7.6)	(5.7)	(10.2)
Diluted	8	(7.6)	(5.7)	(10.2)
From continuing and discontinued operations:
Basic	8	(7.9)	(14.6)	(22.0)
Diluted	8	(7.9)	(14.6)	(22.0)
Basic LPS excluding impairments1	8	(7.9)	(4.3)	(11.9)

1Basic LPS excluding impairment is loss and total comprehensive expense adjusted for the add back of net write-off of intangible assets and net ECL of receivables divided by weighted average number of ordinary shares.

 

Previous period’s figures have been restated for discontinued operation disclosure in relation to Sarta PSC (note 7).

 

Condensed consolidated balance sheet

At 30 June 2024

 

		Unaudited 30 June 2024	Unaudited 30 June 2023	Audited 31 Dec 2023
	Note	$m	$m	$m
Assets
Non-current assets
Intangible assets	9	83.8	80.4	84.7
Property, plant and equipment	10	237.1	249.2	246.5
Trade and other receivables	11	66.5	-	66.5
		387.4	329.6	397.7
Current assets
Trade and other receivables	11	30.2	100.6	34.0
Cash and cash equivalents		370.4	425.0	363.4
		400.6	525.6	397.4
Total assets		788.0	855.2	795.1
Liabilities
Non-current liabilities
Trade and other payables		(0.4)	(0.8)	(0.5)
Deferred income		(9.0)	(5.9)	(8.2)
Provisions		(44.1)	(53.7)	(45.2)
Interest bearing loans	12	(244.9)	(266.8)	(243.7)
		(298.4)	(327.2)	(297.6)
Current liabilities
Trade and other payables		(70.1)	(64.9)	(57.6)
Deferred income		(6.0)	(6.5)	(6.0)
		(76.1)	(71.4)	(63.6)
Total liabilities		(374.5)	(398.6)	(361.2)
Net assets		413.5	456.6	433.9
Owners of the parent
Share capital		43.8	43.8	43.8
Share premium account		3,863.9	3,863.9	3,863.9
Accumulated losses		(3,494.2)	(3,451.1)	(3,473.8)
Total equity		413.5	456.6	433.9

 

 

Condensed consolidated statement of changes in equity

For the period ended 30 June 2024

 

 

				Share capital $m		Share premium $m	Accumulated losses $m	Total equity $m
At 1 January 2023				43.8		3,897.4	(3,413.4)	527.8
Loss and total comprehensive expense			-		-		(40.7)	(40.7)
Contributions by and distributions to owners
Share-based payments				-		-	3.0	3.0
Dividends provided for or paid1				-		(33.5)	-	(33.5)
At 30 June 2023 (Unaudited)				43.8		3,863.9	(3,451.1)	456.6
At 1 January 2023				43.8		3,897.4	(3,413.4)	527.8
Loss and total comprehensive expense				-		-	(61.3)	(61.3)
Contributions by and distributions to owners
Share-based payments				-		-	2.7	2.7
Purchase of own shares for employee share plan				-		-	(1.8)	(1.8)
Dividends provided for or paid1				-		(33.5)	-	(33.5)
At 31 December 2023 (Audited) and 1 January 2024				43.8		3,863.9	(3,473.8)	433.9
Loss and total comprehensive expense				-		-	(21.9)	(21.9)
Contributions by and distributions to owners
Share-based payments				-		-	3.0	3.0
Purchase of own shares for employee share plan				-		-	(1.5)	(1.5)
At 30 June 2024 (Unaudited)				43.8		3,863.9	(3,494.2)	413.5

 

 

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 2024

 

	Note	Unaudited 30 June 2024	Unaudited 30 June 2023	Audited 31 Dec 2023
		$m	$m	$m
Cash flows from operating activities
Loss for the period / year		(21.9)	(40.7)	(61.3)
Adjustments for:
Net finance expense	5	5.2	5.0	9.4
Taxation	6	-	-	0.2
Depreciation and amortisation		25.8	26.7	46.7
Exploration expense	4	1.1	0.3	0.1
Net impairments, write-offs	4	-	29.4	28.1
Other non-cash items (royalty income & share-based payment cost)		1.8	(0.9)	0.8
Changes in working capital:
Decrease in trade and other receivables		1.8	13.3	14.4
Increase / (decrease) in trade and other payables		13.5	(4.3)	(3.7)
Cash generated from operations		27.3	28.8	34.7
Interest received	5	9.2	10.5	20.6
Taxation paid		(0.1)	(0.1)	(0.2)
Net cash generated from operating activities		36.4	39.2	55.1
Cash flows from investing activities
Payments of intangible assets		(2.2)	(6.1)	(9.7)
Payments of property, plant and equipment		(13.8)	(53.9)	(88.8)
Net cash used in investing activities		(16.0)	(60.0)	(98.5)
Cash flows from financing activities
Dividends paid to company’s shareholders		-	(33.5)	(33.5)
Purchase of own shares		(1.5)	-	(1.8)
Bond repayment	12	-	(1.0)	(24.9)
Lease payments		(0.4)	(1.7)	(2.8)
Interest paid		(11.5)	(12.6)	(24.8)
Net cash used in financing activities		(13.4)	(48.8)	(87.8)
Net increase / (decrease) in cash and cash equivalents		7.0	(69.6)	(131.2)
Cash and cash equivalents at the beginning of the period / year		363.4	494.6	494.6
Cash and cash equivalents at the end of the period / year		370.4	425.0	363.4

 

 

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 26 New Street, St Helier, Jersey, JE2 3RA .

 

The half-year condensed consolidated financial statements for the six months ended 30 June 2024 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 5 August 2024. 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 2023, which have been prepared in accordance with IFRS as adopted by the European Union. The same accounting policies and methods of computation are followed in the interim financial report as compared with the 31 December 2023 annual financial statements. The annual financial statements for the year ended 31 December 2023 were approved by the board of directors on 25 March 2024. 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 2023 has been extracted from the audited accounts.

 

Items included in the financial information of each of the Company's entities are measured using the currency of the primary economic environment in which the entity operates (the functional currency). The consolidated financial statements are presented in US dollars to the nearest million ($ million) rounded to one decimal place, except where otherwise indicated.

 

Going concern

The Company regularly evaluates its financial position, cash flow forecasts and its compliance with financial covenants by considering multiple combinations of oil price, discount rates, production volumes, payments, capital and operational spend scenarios.

 

The Company has reported cash of $370 million, with its debt of $248 million maturing in the second half of 2025 and significant headroom on both the equity ratio and minimum liquidity financial covenants.

 

The Federal Iraq Supreme Court majority decision in February 2022 regarding the Kurdistan Oil and Gas Law (2007) and the subsequent actions taken by the Federal Minister of Oil in Baghdad Commercial Court did not have a significant impact on the Company’s cash generation. However, since then, the International Chamber of Commerce in Paris ruling in favour of Iraq in the long running arbitration case against Türkiye concerning the Iraqi-Turkish pipeline agreement signed in 1973, resulted in exports through the pipeline being suspended from 25 March 2023.

 

The Company is currently selling in the domestic market at lower prices and lower volumes than are available from exports, with significantly reduced cash generation.

 

The Company forecasts that, even with continued suspension of exports, it will have a significant net cash balance for the foreseeable future.

 

As a result, the Directors have assessed that the Company’s forecast liquidity provides adequate headroom over its debt maturity and forecast expenditure for the 17 months following the signing of the half-year condensed consolidated financial statements for the period ended 30 June 2024 and consequently that the Company is considered a going concern.

 

2. Summary of material 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 2023.

 

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 estimates

The following are the critical estimates that the directors have made in the process of applying the Group and 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.

 

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 which are based on Petroleum Resources Management System 2018. 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 under IAS 36.

 

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.

 

Where the Company has updated its estimated reserves and resources any required disclosure of the impact on the financial statements is provided in the following sections.

 

Estimation of oil and gas asset values (note 9 and 10)

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, climate-related risks, pipeline reopening 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 14% 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 period end. Risking factors are also used alongside the discount rate when the Company is assessing exploration and appraisal assets.

 

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 ECL and going concern.

 

The Company’s estimate 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.

 

$/bbl	2024	2025	2026	2027	2028
HY2024 estimate	85	80	75	75	75
FY2023 estimate	80	76	74	71	70
HY2023 estimate	78	74	70	70	70

 

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 reference oil price average less transportation costs, handling costs and quality adjustments.

 

Effective from 1 September 2022, sales have been priced by the MNR under a new pricing formula based on the realised sales price for Kurdistan blend crude (‘KBT’) during the delivery month, rather than on dated Brent. The Company has not agreed on this new pricing formula and continued to invoice on Brent. 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 the latest payments were based on the netback price provided by the KRG. Therefore, the export revenue from 1 September 2022 was recognised in accordance with IFRS15 using KBT pricing, resulting in the recognition of $13 million less of revenue.

 

The export pipeline closure in March 2023 has resulted in volumes sold in the local market starting in June 2023 on a cash and carry basis at lower realised oil prices than previously achieved through export. A sensitivity analysis of netback price on producing asset values has been provided in note 10. Where relevant, for estimates of future domestic sales price we use $35/bbl.

 

Estimation of the recoverable value of deferred receivables and trade receivables (note 11)

As of 30 June 2024, the Company is owed six months of payments for the sales from October 2022 to March 2023. Management has compared the carrying value of trade receivables with the present value of the estimated future cash flows based on the prevailing discount rate at the time sales made (14%) and a number of collection scenarios. The ECL is the weighted average of these scenarios and is recognised in the income statement. The weighting is applied based on expected repayment timing. The result of this assessment is an ECL provision of $14.5 million (31 December 2023: $14.5 million). Each 1% increase in discount rate would increase the ECL by $0.9 million. Sensitivity of the ECL to different scenarios has been provided in note 11.

 

Other estimates

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

 

Decommissioning provision

Decommissioning provisions are calculated from a number of inputs such as costs to be incurred in removing production facilities and site restoration at the end of the producing life of each field which is considered as the mid-point of a range of cost estimation. These inputs are based on the Company’s best estimate of the expenditure required to settle the present obligation at the end of the period inflated at 2% (2023: 2%) and discounted at 4% (2023: 4%). 10% increase in cost estimates would increase the existing provision by c.$4 million and 1% increase in discount rate would decrease the existing provision by c.$3 million, the combined impact would be c.$1 million. The cash flows relating to the decommissioning and abandonment provisions are expected to occur between 2028 and 2036.

 

Taxation

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

 

New standards

The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2024. Amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures: Supplier Finance Arrangements (issued on 25 May 2023), Amendments to IAS 1 Presentation of Financial Statements: Classification of Liabilities as Current or Noncurrent (issued on 23 January 2020); Classification of Liabilities as Current or Noncurrent - Deferral of Effective Date (issued on 15 July 2020); and Non-current Liabilities with Covenants (issued on 31 October 2022), Amendments to IFRS 16 Leases: Lease Liability in a Sale and Leaseback (issued on 22 September 2022). These standards did not have a material impact on the Company’s results or financial statements disclosures in the current reporting period.

 

The following new accounting standards, amendments to existing standards and interpretations have been issued but are not yet effective and/or have not yet been endorsed by the EU: IFRS 19 Subsidiaries without Public Accountability: Disclosures (issued on 9 May 2024), IFRS 18 Presentation and Disclosure in Financial Statements (issued on 9 April 2024), Amendments to the Classification and Measurement of Financial Instruments (Amendments to IFRS 9 and IFRS 7) (issued on 30 May 2024), Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates: Lack of Exchangeability (issued on 15 August 2023). 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 periods they become effective.

 

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 fields) and the Taq Taq PSC which are located in the KRI and make export sales to the KRG in 2023 and local sales to the local buyers. The pre-production segment is comprised of 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 2024

	Production	Pre-production	Other	Total
	$m	$m	$m	$m
Revenue from contracts with customers (local)	37.6	-	-	37.6
Cost of sales	(33.9)	-	-	(33.9)
Gross profit	3.7	-	-	3.7
Exploration expense	-	(1.1)	-	(1.1)
Other operating costs	(2.2)	-	-	(2.2)
General and administrative costs	-	-	(16.2)	(16.2)
Operating profit / (loss)	1.5	(1.1)	(16.2)	(15.8)
Operating profit / (loss) is comprised of
EBITDAX	27.2	-	(16.1)	11.1
Depreciation and amortisation	(25.7)	-	(0.1)	(25.8)
Exploration expense	-	(1.1)	-	(1.1)
Finance income	-	-	9.2	9.2
Bond interest expense	-	-	(11.5)	(11.5)
Other finance expense	(1.7)	-	(1.2)	(2.9)
Loss before income tax from continuing operations	(0.2)	(1.1)	(19.7)	(21.0)
Loss from discontinued operations	(0.9)	-	-	(0.9)
Loss before income tax	(1.1)	(1.1)	(19.7)	(21.9)
Capital expenditure	13.4	2.5	-	15.9
Total assets	403.9	28.6	355.5	788.0
Total liabilities	(111.1)	(7.0)	(256.4)	(374.5)

Sarta PSC figures have been disclosed as discontinued operation following the PSC termination in 2023 (note 7).

 

Total assets and liabilities in the ‘Other’ column are predominantly cash and debt balances.

 

 

For the 6-month period ended 30 June 2023

	Production	Pre-production	Other	Total
	$m	$m	$m	$m
Revenue from contracts with customers (export)	45.6	-	-	45.6
Revenue from contracts with customers (local)	0.6			0.6
Revenue from other sources	1.8	-	-	1.8
Cost of sales	(39.4)	-	-	(39.4)
Gross profit	8.6	-	-	8.6
Exploration expense	-	(0.3)	-	(0.3)
Other operating costs	(0.5)	-	-	(0.5)
Reversal of ECL of trade receivables	4.2	-	-	4.2
ECL of trade receivables	(13.3)	-	-	(13.3)
General and administrative costs	-	-	(9.9)	(9.9)
Operating loss	(1.0)	(0.3)	(9.9)	(11.2)
Operating loss is comprised of
EBITDAX	32.8	-	(9.9)	22.9
Depreciation and amortisation	(24.7)	-	-	(24.7)
Exploration expense	-	(0.3)	-	(0.3)
Reversal of ECL of receivables	4.2	-	-	4.2
ECL of receivables	(13.3)	-	-	(13.3)
Finance income	-	-	10.5	10.5
Bond interest expense	-	-	(12.7)	(12.7)
Other finance expense	(1.5)	-	(1.1)	(2.6)
Loss before income tax from continuing operations	(2.5)	(0.3)	(13.2)	(16.0)
Loss from discontinued operations	(24.7)	-	-	(24.7)
Loss before income tax	(27.2)	(0.3)	(13.2)	(40.7)
Capital expenditure	43.5	4.0	-	47.5
Total assets	412.6	29.4	413.2	855.2
Total liabilities	(99.1)	(18.6)	(280.9)	(398.6)

Sarta PSC figures have been disclosed as discontinued operation following the PSC termination in 2023 (note 7).

 

Total assets and liabilities in the ‘Other’ column are predominantly cash and debt balances.

 

For the 12-month period ended 31 December 2023

 

	Production	Pre-production	Other	Total
	$m	$m	$m	$m
Revenue from contracts with customers (export)	45.8	-	-	45.8
Revenue from contracts with customers (local)	38.2	-	-	38.2
Revenue from other sources	0.8	-	-	0.8
Cost of sales	(65.2)	-	-	(65.2)
Gross profit	19.6	-	-	19.6
Exploration expense	-	(0.1)	-	(0.1)
Other operating costs	(3.6)	-	-	(3.6)
Reversal of decommissioning provision	1.2	-	-	1.2
Reversal of ECL of trade receivables	4.2	-	-	4.2
ECL of trade receivables	(13.3)	-	-	(13.3)
General and administrative costs	-	-	(27.2)	(27.2)
Operating profit / (loss)	8.1	(0.1)	(27.2)	(19.2)
Operating profit / (loss) is comprised of
EBITDAX	59.9	-	(27.1)	32.8
Depreciation and amortisation	(43.9)	-	(0.1)	(44.0)
Exploration expense	-	(0.1)	-	(0.1)
Reversal of decommissioning provision	1.2	-	-	1.2
Reversal of ECL of receivables	4.2	-	-	4.2
ECL of receivables	(13.3)	-	-	(13.3)
Finance income	-	-	20.6	20.6
Bond interest expense	-	-	(24.8)	(24.8)
Net other finance expense	(3.2)	(0.1)	(1.6)	(4.9)
Profit / (Loss) before income tax from continuing operations	4.9	(0.2)	(33.0)	(28.3)
Loss from discontinued operations	(32.8)	-	-	(32.8)
Profit / (Loss) before income tax	(27.9)	(0.2)	(33.0)	(61.1)
Capital expenditure	58.9	9.1	-	68.0
Total assets	412.1	26.8	356.2	795.1
Total liabilities	(91.0)	(12.0)	(258.2)	(361.2)

Sarta PSC figures have been disclosed as discontinued operation following the PSC termination in 2023 (note 7).

 

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

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
	$m	$m	$m
Production costs	(8.2)	(14.7)	(21.3)
Depreciation of oil and gas property, plant and equipment (excl. RoU assets)	(23.0)	(22.2)	(39.6)
Amortisation of oil and gas intangible assets	(2.7)	(2.5)	(4.3)
Cost of sales	(33.9)	(39.4)	(65.2)
Exploration expense	(1.1)	(0.3)	(0.1)
Other operating costs1	(2.2)	(0.5)	(3.6)
1 Other operating costs relate to Taq Taq costs which were incurred after production ceased in May 2023, following the pipeline closure.
Net reversal of accruals and provisions	-	-	1.2
Net write-off of intangible assets	-	-	1.2
Reversal of ECL of trade receivables (note 2,11)	-	4.2	4.2
ECL of trade receivables (note 2,11)	-	(13.3)	(13.3)
Net ECL of trade receivables	-	(9.1)	(9.1)
Corporate cash costs	(7.6)	(4.3)	(12.4)
Non-recurring costs	(6.7)	(4.7)	(13.1)
Corporate share-based payment expense	(1.8)	(0.9)	(1.6)
Depreciation and amortisation of corporate assets (excl. RoU assets)	(0.1)	-	(0.1)
General and administrative expenses	(16.2)	(9.9)	(27.2)

 

 

5. Finance expense and income 

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
	$m	$m	$m
Bond interest	(11.5)	(12.7)	(24.8)
Other finance expense (non-cash)	(2.9)	(2.6)	(6.0)
Finance expense	(14.4)	(15.3)	(30.8)
Bank interest income	9.2	10.5	20.6
Gain on bond buyback	-	-	1.1
Finance income	9.2	10.5	21.7
Net finance expense	(5.2)	(4.8)	(9.1)

 

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

 

 

6. Income tax expense

 

Current tax expense is incurred on profits of service companies. Under the terms of the KRI PSCs, the Company is not required to pay any cash corporate income taxes as explained in note 2.

 

7. Discontinued operations

 

Sarta PSC was terminated on 1 December 2023. The results of the discontinued operations were as follows:

 

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
	$m	$m	$m
Revenue	-	3.3	3.6
Production costs	-	(3.6)	(3.6)
Depreciation of oil and gas property, plant and equipment	-	(0.7)	(0.7)
Gross loss	-	(1.0)	(0.7)
Other operating costs1	(0.8)	(4.7)	(20.0)
Write-off of property, plant and equipment (note 10)	-	(17.7)	(18.7)
Reversal of provisions	-	-	8.2
Reversal of ECL of trade receivables	-	0.4	0.4
ECL of trade receivables	-	(1.2)	(1.2)
General and administrative costs	(0.1)	(0.3)	(0.5)
Operating loss	(0.9)	(24.5)	(32.5)
Other finance expense (non-cash)	-	(0.2)	(0.3)
Loss from discontinued operations	(0.9)	(24.7)	(32.8)

 

1 Other operating costs relate to costs incurred after production ceased in March 2023, following the pipeline closure and costs incurred in relation to exiting the PSC.

 

 

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
Cash flows from discontinued operations	$m	$m	$m
Net cash used in operating activities	(1.5)	(13.3)	(27.8)
Net cash used in investing activities	-	(3.8)	(3.8)
Net cash used in financing activities	-	(1.3)	(2.1)

 
 

8. Loss per share

 

Basic

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

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
Loss from continuing operations ($m)	(21.0)	(16.0)	(28.5)
Loss from discontinued operations ($m)	(0.9)	(24.7)	(32.8)
Loss attributable to owners of the parent ($m)	(21.9)	(40.7)	(61.3)
Weighted average number of ordinary shares – number 1	276,953,398	278,923,402	278,836,216
Basic loss per share – cents (from continuing operations)	(7.6)	(5.7)	(10.2)
Basic loss per share – cents	(7.9)	(14.6)	(22.0)

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, share options and deferred bonus plans not included in the calculation of basic earnings per share. Because the Company reported a loss for the period ended 30 June 2024, the performance shares, restricted shares and share options are anti-dilutive and therefore diluted LPS is the same as basic LPS:

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
Loss from continuing operations ($m)	(21.0)	(16.0)	(28.5)
Loss from discontinued operations ($m)	(0.9)	(24.7)	(32.8)
Loss attributable to owners of the parent ($m)	(21.9)	(40.7)	(61.3)
Weighted average number of ordinary shares – number1	276,953,398	278,923,402	278,836,216
Adjustment for performance shares, restricted shares, share options and deferred bonus plans		-	-
Weighted average number of ordinary shares and potential ordinary shares	276,953,398	278,923,402	278,836,216
Diluted loss per share – cents (from continuing operations)	(7.6)	(5.7)	(10.2)
Diluted loss per share – cents	(7.9)	(14.6)	(22.0)

1 Excluding shares held as treasury shares 

 

Basic (LPS) / EPS excluding impairments

Basic (LPS) / EPS excluding impairment is loss and total comprehensive expense adjusted for the add back of net impairment/write-off of oil and gas assets and net ECL/reversal of ECL of receivables divided by weighted average number of ordinary shares.

	6 months to 30 June 2024	6 months to 30 June 2023	Year to 31 December 2023
Loss attributable to owners of the parent ($m)	(21.9)	(40.7)	(61.3)
Add back of net impairment/write-off of oil and gas assets	-	18.7	18.2
Add back of net ECL of receivables	-	9.9	9.9
Loss attributable to owners of the parent ($m) - adjusted	(21.9)	(12.1)	(33.2)
Weighted average number of ordinary shares – number 1	276,953,398	278,923,402	278,836,216
Basic loss per share excluding impairments – cents	(7.9)	(4.3)	(11.9)

1 Excluding shares held as treasury shares
 

9. Intangible assets

	Exploration and evaluation assets	Tawke RSA	Other assets	Total
	$m	$m	$m	$m
Cost
At 1 January 2023	12.9	425.1	7.5	445.5
Additions	4.0	-	-	4.0
Other	(0.2)	-	-	(0.2)
At 30 June 2023	16.7	425.1	7.5	449.3
At 1 January 2023	12.9	425.1	7.5	445.5
Additions	9.1	-	-	9.1
Other	0.8	-	-	0.8
At 31 December 2023 and 1 January 2024	22.8	425.1	7.5	455.4
Additions	2.5	-	-	2.5
Other	(0.7)	-	-	(0.7)
At 30 June 2024	24.6	425.1	7.5	457.2
Accumulated amortisation and impairment
At 1 January 2023	-	(358.9)	(7.5)	(366.4)
Amortisation charge for the period	-	(2.5)	-	(2.5)
At 30 June 2023	-	(361.4)	(7.5)	(368.9)
At 1 January 2023	-	(358.9)	(7.5)	(366.4)
Amortisation charge for the year	-	(4.3)	-	(4.3)
At 31 December 2023 and 1 January 2024	-	(363.2)	(7.5)	(370.7)
Amortisation charge for the period	-	(2.7)	-	(2.7)
At 30 June 2024	-	(365.9)	(7.5)	(373.4)
Net book value
At 1 January 2023	12.9	66.2	-	79.1
At 30 June 2023	16.7	63.7	-	80.4
At 31 December 2023 and 1 January 2024	22.8	61.9	-	84.7
At 30 June 2024	24.6	59.2	-	83.8

 

 

		30 June 2024	30 June 2023	31 Dec 2023
Book value		$m	$m	$m
Somaliland PSC	Exploration	24.6	16.7	22.8
Exploration and evaluation assets		24.6	16.7	22.8
Tawke capacity building payment waiver		59.2	63.7	61.9
Tawke RSA assets		59.2	63.7	61.9

 

 

10. Property, plant and equipment

		Producing assets	Other assets		Total
		$m	$m		$m
Cost
At 1 January 2023		3,252.2	17.6		3,269.8
Additions		43.5	(0.1)		43.4
Other1		2.0	-		2.0
At 30 June 2023		3,297.7	17.5		3,315.2
At 1 January 2023		3,252.2	17.6		3,269.8
Additions		58.9	-		58.9
Right-of-use assets		-	(0.3)		(0.3)
Other1		2.1	-		2.1
At 31 December 2023 and 1 January 2024		3,313.2	17.3		3,330.5
Additions		13.4	0.3		13.7
Other1		0.6	-		0.6
At 30 June 2024		3,327.2	17.6		3,344.8
Accumulated depreciation and impairment
At 1 January 2023		(3,007.5)	(14.2)		(3,021.7)
Depreciation charge for the period		(26.0)	(0.6)		(26.6)
Write-off		(17.7)	-		(17.7)
At 30 June 2023		(3,051.2)	(14.8)		(3,066.0)
At 1 January 2023		(3,007.5)	(14.2)		(3,021.7)
Depreciation charge for the year		(42.3)	(1.3)		(43.6)
Write-off		(18.7)	-		(18.7)
At 31 December 2023 and 1 January 2024		(3,068.5)	(15.5)		(3,084.0)
Depreciation charge for the period		(23.0)	(0.7)		(23.7)
At 30 June 2024		(3,091.5)	(16.2)		(3,107.7)
Net book value
At 1 January 2023		244.7	3.4		248.1
At 30 June 2023	246.5			2.7		249.2
At 31 December 2023 and 1 January 2024		244.7	1.8		246.5
At 30 June 2024		235.7	1.4		237.1

 

1 Other line includes non-cash asset retirement obligation provision and share-based payment costs.

 

		30 June 2024	30 June 2023	31 Dec 2023
Book value		$m	$m	$m
Tawke PSC	Oil production	198.7	215.2	210.0
Taq Taq PSC	Oil production	37.0	31.3	34.7
Producing assets		235.7	246.5	244.7

 

The sensitivities below provide an indicative impact on net recoverable value of a change in netback price, discount rate, production or pipeline reopening, assuming no change to any other inputs.

 

Sensitivities	Taq Taq CGU $m	Tawke CGU $m
Netback price +/- $5/bbl	+/- 2	+/- 30
Discount rate +/- 1%	+/- 0	+/- 8
Production +/- 10%	+/- 2	+/- 32
Local sales only for 1 year	+/- 0	- 19

 

 

11. Trade and other receivables

	30 June 2024	30 June 2023	31 Dec 2023
	$m	$m	$m
Trade receivables – non-current	66.5	-	66.5
Trade receivables – current	26.4	95.1	26.4
Other receivables and prepayments	3.8	5.5	7.6
	96.7	100.6	100.5

 

As of 30 June 2024, the Company is owed six months of payments (31 December 2023: six months).

 

	Period when sale made
	Overdue 2023	Overdue 2022	Total nominal	ECL provision		Trade receivables
	$m	$m	$m	$m		$m
30 June 2023	49.3	60.3	109.6	(14.5)		95.1
31 December 2023	49.3	58.1	107.4	(14.5)		92.9
30 June 2024	49.3	58.1	107.4	(14.5)		92.9

 

 

Movement on trade receivables in the period	30 June 2024 $m	30 June 2023 $m	31 Dec 2023 $m
Carrying value at the beginning of the period	92.9	117.0	117.0
Revenue from contracts with customers	37.6	49.5	87.6
Cash for export sales	-	(61.2)	(61.2)
Cash for local sales	(37.6)	(0.6)	(41.0)
Reversal of previous year’s expected credit loss (note 2)	-	4.6	4.6
Expected credit loss for current period (note 2)	-	(14.5)	(14.5)
Capacity building payments	-	0.2	0.2
Sarta processing fee payments	-	0.1	0.2
Carrying value at the end of the period	92.9	95.1	92.9

 

 

Recovery of the carrying value of the receivable

All trade receivables relate to export sales as the local sales are on a cash and carry basis. As explained in note 2, the booked nominal receivable value of $107.4 million has been recognised based on KBT due to IFRS 15 requirements and it would be $13 million higher under Brent pricing mechanism. The Company expects to recover the full value of receivables owed from the KRG under Brent pricing mechanism, but the terms of recovery are not determined yet. An explanation of the assumptions and estimates in assessing the net present value of the deferred receivables are provided in note 2.

	Total $m
Booked nominal balance to be recovered	107.4
Estimated net present value of total cash flows	92.9

 

Sensitivities/Scenarios

The table below shows the sensitivity of the net present value of the overdue trade receivables to start and timing of repayment that the company has used during its ECL assessment. Each scenario has been weighted in accordance with the management’s expected outcome.

 

 

12. Interest bearing loans and net cash

 

	1 Jan 2024	Discount unwind	Net other changes1	30 June 2024
	$m	$m	$m	$m
2025 Bond 9.25% (non-current)	(243.7)	(1.2)	-	(244.9)
Cash	363.4	-	7.0	370.4
Net cash	119.7	(1.2)	7.0	125.5

 

1 Net other changes are free cash flow plus purchase of own shares

 

As of 30 June 2024, the fair value of the $248 million of bonds held by third parties is $246.3 million (31 December 2023: $236.5 million).

 

The bonds maturing in 2025 have two financial covenant maintenance tests:

 

Financial covenant	Test	H1 2024	H1 2023	YE 2023
Equity ratio (Total equity/Total assets)	> 40%	52%	53%	55%
Minimum liquidity	> $30m	$370.4m	$425.0m	$363.4m

 

	1 Jan 2023	Discount unwind	Repurchase of bond	Dividend paid	Net other changes1	30 June 2023
	$m	$m	$m	$m	$m	$m
2025 Bond 9.25% (non-current)	(266.6)	(1.1)	0.9	-	-	(266.8)
Cash	494.6	-	(1.0)	(33.5)	(35.1)	425.0
Net cash	228.0	(1.1)	(0.1)	(33.5)	(35.1)	158.2

 

 

	1 Jan 2023	Discount unwind	Repurchase of bond	Dividend paid	Net other changes1	31 Dec 2023
	$m	$m	$m	$m	$m	$m
2025 Bond 9.25% (non-current)	(266.6)	(2.7)	25.6	-	-	(243.7)
Cash	494.6	-	(24.9)	(33.5)	(72.8)	363.4
Net cash	228.0	(2.7)	0.7	(33.5)	(72.8)	119.7

 

 

13. 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

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 2024 is not prepared, in all material respects, in accordance with International Accounting Standard 34 “Interim Financial Reporting” as adopted by the European Union, Article 106 of the Companies (Jersey) Law 1991 and the Disclosure, Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

We have been engaged by Genel Energy PLC (“the Company”) to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2024 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 related explanatory notes that have been reviewed. 

Basis for conclusion

We conducted our review in accordance with the Revised International Standard on Review Engagements (UK) 2410, “Review of Interim Financial Information Performed by the Independent Auditor of the Entity” (“ISRE (UK) 2410 (Revised)”). 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.

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” as adopted by the European Union, Article 106 of the Companies (Jersey) Law 1991 and the Disclosure, Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

Conclusions relating to going concern

Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed.

This conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410 (Revised), however future events or conditions may cause the Group to cease to continue as a going concern.

Responsibilities of directors

The directors are responsible for preparing the half-yearly financial report in accordance with the International Accounting Standard 34 “Interim Financial Reporting” as adopted by the European Union, Article 106 of the Companies (Jersey) Law 1991 and the Disclosure Guidance and Transparency Rules of the United Kingdom’s Financial Conduct Authority.

In preparing the half-yearly financial report, the directors are responsible for assessing the Group’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.

Auditor’s responsibilities for the review of the financial information

In reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statement in the half-yearly financial report. Our conclusion, including our Conclusions Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.

Use of our report

Our report has been prepared in accordance with the terms of our engagement to assist the Company in meeting the requirements of 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, UK

5 August 2024

 

 

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