REG-Genel Energy PLC Genel Energy PLC: Half-Year Results
06/08/2024 07:30
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Genel Energy PLC (GENL)
Genel Energy PLC: Half-Year Results
06-Aug-2024 / 07:20 GMT/BST
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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
+44 20 7659 5100
Luke Clements, CFO
Vigo Consulting
+44 20 7390 0230
Patrick d’Ancona
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:
1 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.
Gross Gross Gross WI WI
production production production production production
(bopd) Domestic Domestic Domestic Domestic Exports
sales sales sales sales
H1 2023
Q1 2024 Q2 2024 H1 2024 H1 2024
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: 2 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
Audited
Unaudited Unaudited
Year
6 months to 30 6 months to 30
June 2024 June 2023 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 4 (25.7) (24.7) (43.9)
of oil assets
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 4 - - 1.2
assets
Net expected credit loss 4 - (9.1) (9.1)
(‘ECL’) of receivables
General and administrative 4 (16.2) (9.9) (27.2)
costs
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 4 - - 1.2
assets
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 (21.0) (16.0) (28.5)
operations
Loss from discontinued 7 (0.9) (24.7) (32.8)
operations
Loss and total comprehensive (21.9) (40.7) (61.3)
expense
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 8 (7.9) (4.3) (11.9)
impairments1
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 Unaudited Audited 31 Dec
2023
30 June 2024 30 June 2023
Note $m $m $m
Assets
Non-current assets
Intangible assets 9 83.8 80.4 84.7
Property, plant and 10 237.1 249.2 246.5
equipment
Trade and other 11 66.5 - 66.5
receivables
387.4 329.6 397.7
Current assets
Trade and other 11 30.2 100.6 34.0
receivables
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 Share Accumulated Total
capital premium losses equity
$m $m $m $m
At 1 January 2023 43.8 3,897.4 (3,413.4) 527.8
Loss and total comprehensive - - (40.7) (40.7)
expense
Contributions by and
distributions to owners
Share-based payments - - 3.0 3.0
Dividends provided for or - (33.5) - (33.5)
paid1
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 - - (61.3) (61.3)
expense
Contributions by and
distributions to owners
Share-based payments - - 2.7 2.7
Purchase of own shares for - - (1.8) (1.8)
employee share plan
Dividends provided for or - (33.5) - (33.5)
paid1
At 31 December 2023 43.8 3,863.9 (3,473.8) 433.9
(Audited) and 1 January 2024
Loss and total comprehensive - - (21.9) (21.9)
expense
Contributions by and
distributions to owners
Share-based payments - - 3.0 3.0
Purchase of own shares for - - (1.5) (1.5)
employee share plan
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
Audited
Unaudited Unaudited
Note 31 Dec
30 June 2024 30 June 2023
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 1.8 (0.9) 0.8
income & share-based payment cost)
Changes in working capital:
Decrease in trade and other 1.8 13.3 14.4
receivables
Increase / (decrease) in trade 13.5 (4.3) (3.7)
and other payables
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 36.4 39.2 55.1
activities
Cash flows from investing
activities
Payments of intangible assets (2.2) (6.1) (9.7)
Payments of property, plant and (13.8) (53.9) (88.8)
equipment
Net cash used in investing (16.0) (60.0) (98.5)
activities
Cash flows from financing
activities
Dividends paid to company’s - (33.5) (33.5)
shareholders
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 (13.4) (48.8) (87.8)
activities
Net increase / (decrease) in cash 7.0 (69.6) (131.2)
and cash equivalents
Cash and cash equivalents at the 363.4 494.6 494.6
beginning of the period / year
Cash and cash equivalents at the 370.4 425.0 363.4
end of the period / year
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
Pre-production Total
Production Other
$m $m $m $m
Revenue from contracts with 37.6 - - 37.6
customers (local)
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 (0.2) (1.1) (19.7) (21.0)
continuing operations
Loss from discontinued (0.9) - - (0.9)
operations
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
Pre-production Total
Production Other
$m $m $m $m
Revenue from contracts with 45.6 - - 45.6
customers (export)
Revenue from contracts with 0.6 0.6
customers (local)
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 4.2 - - 4.2
receivables
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 (2.5) (0.3) (13.2) (16.0)
continuing operations
Loss from discontinued (24.7) - - (24.7)
operations
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
Pre-production Total
Production Other
$m $m $m $m
Revenue from contracts with 45.8 - - 45.8
customers (export)
Revenue from contracts with 38.2 - - 38.2
customers (local)
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 1.2 - - 1.2
provision
Reversal of ECL of trade 4.2 - - 4.2
receivables
ECL of trade receivables (13.3) - - (13.3)
General and administrative - - (27.2) (27.2)
costs
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 1.2 - - 1.2
provision
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 4.9 (0.2) (33.0) (28.3)
tax from continuing operations
Loss from discontinued (32.8) - - (32.8)
operations
Profit / (Loss) before income (27.9) (0.2) (33.0) (61.1)
tax
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 6 months to
30 June 30 June Year to 31
December 2023
2024 2023
$m $m $m
Production costs (8.2) (14.7) (21.3)
Depreciation of oil and gas
property, plant and equipment (23.0) (22.2) (39.6)
(excl. RoU assets)
Amortisation of oil and gas (2.7) (2.5) (4.3)
intangible assets
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 - - 1.2
provisions
Net write-off of intangible - - 1.2
assets
Reversal of ECL of trade - 4.2 4.2
receivables (note 2,11)
ECL of trade receivables (note - (13.3) (13.3)
2,11)
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 (1.8) (0.9) (1.6)
expense
Depreciation and amortisation of
corporate assets (excl. RoU (0.1) - (0.1)
assets)
General and administrative (16.2) (9.9) (27.2)
expenses
5. Finance expense and income
6 months to 30 6 months to 30
June June Year to 31
December 2023
2024 2023
$m $m $m
Bond interest (11.5) (12.7) (24.8)
Other finance expense (2.9) (2.6) (6.0)
(non-cash)
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 6 months to
June 30 June Year to 31
December 2023
2024 2023
$m $m $m
Revenue - 3.3 3.6
Production costs - (3.6) (3.6)
Depreciation of oil and gas - (0.7) (0.7)
property, plant and equipment
Gross loss - (1.0) (0.7)
Other operating costs1 (0.8) (4.7) (20.0)
Write-off of property, plant and - (17.7) (18.7)
equipment (note 10)
Reversal of provisions - - 8.2
Reversal of ECL of trade - 0.4 0.4
receivables
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 6 months to 30
June June Year to 31
December 2023
2024 2023
Cash flows from discontinued $m $m $m
operations
Net cash used in operating (1.5) (13.3) (27.8)
activities
Net cash used in investing - (3.8) (3.8)
activities
Net cash used in financing - (1.3) (2.1)
activities
8. Loss per share
Basic
Basic loss per share is calculated by dividing the loss attributable to
owners of the parent by the weighted average number of shares in issue
during the period.
6 months to 30
June 6 months to 30 Year to 31
June 2023 December 2023
2024
Loss from continuing (21.0) (16.0) (28.5)
operations ($m)
Loss from discontinued (0.9) (24.7) (32.8)
operations ($m)
Loss attributable to owners of (21.9) (40.7) (61.3)
the parent ($m)
Weighted average number of 276,953,398 278,923,402 278,836,216
ordinary shares – number 1
Basic loss per share – cents (7.6) (5.7) (10.2)
(from continuing operations)
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 6 months to 30 Year to 31
June 2023 December 2023
2024
Loss from continuing (21.0) (16.0) (28.5)
operations ($m)
Loss from discontinued (0.9) (24.7) (32.8)
operations ($m)
Loss attributable to owners of (21.9) (40.7) (61.3)
the parent ($m)
Weighted average number of 276,953,398 278,923,402 278,836,216
ordinary shares – number1
Adjustment for performance
shares, restricted shares, - -
share options and deferred
bonus plans
Weighted average number of
ordinary shares and potential 276,953,398 278,923,402 278,836,216
ordinary shares
Diluted loss per share – cents (7.6) (5.7) (10.2)
(from continuing operations)
Diluted loss per share – cents (7.9) (14.6) (22.0)
1 Excluding shares held as treasury shares
Basic (LPS) / EPS excluding impairments
Basic (LPS) / EPS excluding impairment is loss and total comprehensive
expense adjusted for the add back of net impairment/write-off of oil and
gas assets and net ECL/reversal of ECL of receivables divided by weighted
average number of ordinary shares.
6 months to 30
June 6 months to 30 Year to 31
June 2023 December 2023
2024
Loss attributable to owners of (21.9) (40.7) (61.3)
the parent ($m)
Add back of net
impairment/write-off of oil - 18.7 18.2
and gas assets
Add back of net ECL of - 9.9 9.9
receivables
Loss attributable to owners of (21.9) (12.1) (33.2)
the parent ($m) - adjusted
Weighted average number of 276,953,398 278,923,402 278,836,216
ordinary shares – number 1
Basic loss per share excluding (7.9) (4.3) (11.9)
impairments – cents
1 Excluding shares held as treasury shares
9. Intangible assets
Exploration and Other
evaluation assets Tawke Total
assets
RSA
$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 22.8 425.1 7.5 455.4
January 2024
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 - (2.5) - (2.5)
period
At 30 June 2023 - (361.4) (7.5) (368.9)
At 1 January 2023 - (358.9) (7.5) (366.4)
Amortisation charge for the - (4.3) - (4.3)
year
At 31 December 2023 and 1 - (363.2) (7.5) (370.7)
January 2024
Amortisation charge for the - (2.7) - (2.7)
period
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 22.8 61.9 - 84.7
January 2024
At 30 June 2024 24.6 59.2 - 83.8
30 June 2024 30 June 31 Dec 2023
2023
Book value $m $m $m
Somaliland PSC Exploration 24.6 16.7 22.8
Exploration and evaluation 24.6 16.7 22.8
assets
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
Other
Producing assets
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.
Taq Taq
Tawke CGU
CGU
Sensitivities $m
$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 Overdue Total ECL Trade
2023 2022 nominal receivables
provision
$m $m $m $m $m
30 June 2023 49.3 60.3 109.6 (14.5) 95.1
31 December 49.3 58.1 107.4 (14.5) 92.9
2023
30 June 2024 49.3 58.1 107.4 (14.5) 92.9
Movement on trade receivables in the 30 June 2024 30 June 2023 31 Dec 2023
period
$m $m $m
Carrying value at the beginning of 92.9 117.0 117.0
the period
Revenue from contracts with 37.6 49.5 87.6
customers
Cash for export sales - (61.2) (61.2)
Cash for local sales (37.6) (0.6) (41.0)
Reversal of previous year’s expected - 4.6 4.6
credit loss (note 2)
Expected credit loss for current - (14.5) (14.5)
period (note 2)
Capacity building payments - 0.2 0.2
Sarta processing fee payments - 0.1 0.2
Carrying value at the end of the 92.9 95.1 92.9
period
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
$m
Booked nominal balance to be recovered 107.4
Estimated net present value of total cash flows 92.9
Sensitivities/Scenarios
The table below shows the sensitivity of the net present value of the
overdue trade receivables to start and timing of repayment that the
company has used during its ECL assessment. Each scenario has been
weighted in accordance with the management’s expected outcome.
NPV 14% ($m) Months it takes to recover the nominal amount owed
0 3 6 12 18 24
0 107 105 103 100 97 94
3 103 102 100 97 94 91
Months until 6 99 98 97 94 91 88
repayment commences 9 96 95 94 91 88 85
12 93 92 91 88 85 82
15 90 89 88 85 82 80
12. Interest bearing loans and net cash
1 Jan Net other 30 June
Discount unwind changes1
2024 2024
$m $m $m $m
2025 Bond 9.25% (243.7) (1.2) - (244.9)
(non-current)
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 Discount Repurchase Dividend Net other 30 June
2023 unwind of bond paid 2023
changes1
$m $m $m $m $m $m
2025 Bond 9.25% (266.6) (1.1) 0.9 - - (266.8)
(non-current)
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 Discount Repurchase Dividend Net other 31 Dec
unwind paid changes1 2023
2023 of bond
$m $m $m $m $m $m
2025 Bond 9.25% (266.6) (2.7) 25.6 - - (243.7)
(non-current)
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).
══════════════════════════════════════════════════════════════════════════
Dissemination of a Regulatory Announcement that contains inside
information in accordance with the Market Abuse Regulation (MAR),
transmitted by EQS Group.
The issuer is solely responsible for the content of this announcement.
══════════════════════════════════════════════════════════════════════════
ISIN: JE00B55Q3P39, NO0010894330
Category Code: IR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
OAM Categories: 1.2. Half yearly financial reports and audit
reports/limited reviews
Sequence No.: 338637
EQS News ID: 1961447
End of Announcement EQS News Service
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