REG-Genel Energy PLC Genel Energy PLC: Full-Year Results
26/03/2024 07:15
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Genel Energy PLC (GENL)
Genel Energy PLC: Full-Year Results
26-March-2024 / 07:00 GMT/BST
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26 March 2024
Genel Energy plc
Audited results for the year ended 31 December 2023
Genel Energy plc (‘Genel’ or ‘the Company’) announces its audited results
for the year ended 31 December 2023.
Paul Weir, Chief Executive of Genel, said:
“We have continued the journey that we commenced in 2022 to, firstly,
refocus the business on areas where it can be profitable and deliver
shareholder value and, secondly, optimise the organisation to create a
reshaped and resilient business with the potential for transformational
value accretion through several catalysts.
We are a leaner, simplified company that retains clear objectives –
generating resilient and sustainable cash flows, diversifying our income
through the addition of new assets, and maintaining a strong balance sheet.
We have reduced our workforce and cut costs significantly, exited the Sarta
and Qara Dagh licences, worked with our operating partner to develop a new
income stream from local sales, and spent considerable time defending our
contractual rights under the Bina Bawi and Miran PSCs, where we invested
over $1.4 billion before their termination in December 2021.
These actions mean that we are now well positioned in 2024, with a reshaped
and resilient business and a strong balance sheet. In the absence of value
accretive M&A, we expect to maintain net cash of more than $100 million
even if the suspension of exports continues to the end of the year.
Genel has established a sound platform from which to spring forward. The
re-opening of the pipeline has the potential to more than double cash
generation. We expect to recover the $107 million of overdue receivables,
and we have the capacity and intent to acquire new assets. On the Miran and
Bina Bawi oil and gas assets arbitration, having now completed the
evidential hearing, our views on the merits of our case are unchanged since
the arbitration was launched in December 2021.”
Results summary ($ million unless stated)
2023 2022
Average Brent oil price ($/bbl) 82 101
Production (bopd, working interest) 12,410 30,150
Revenue 84.8 401.9
EBITDAX1 32.8 349.1
Depreciation and amortisation (44.0) (134.3)
Exploration expense (0.1) (1.0)
Net write-off / impairment of oil and gas assets 1.2 (75.8)
Net (expected credit loss (‘ECL’)) / reversal of ECL of (9.1) 8.6
receivables
Operating (loss) / profit (19.2) 146.6
Cash flow from operating activities 55.1 412.4
Capital expenditure 68.0 143.1
Free cash flow2 (71.0) 234.8
Cash 363.4 494.6
Total debt 248.0 274.0
Net cash3 119.7 228.0
Dividends declared during financial year (¢ per share) 12 18
1. EBITDAX is operating profit / (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 11
3. Reported cash less IFRS debt (page 11)
Highlights
• The Iraq-Türkiye pipeline (‘ITP’) has been suspended since March 2023,
with talks ongoing but no clear timing on when exports will restart
• Reshaped business resilient and well positioned to maximise upside
◦ Local sales consistent since end of January, with the Tawke PSC
currently generating sufficient funding to cover organisational
spend
◦ Increase to Tawke PSC 2P reserves replacing production in 2023 and
retaining 2P reserves of 79 MMbbls net to Genel at the licence
◦ Organisational spend outside the cash generative Tawke PSC reduced
by 40% to around $3 million per month
◦ Reduced workforce by 70% and cut costs significantly across all
areas of the business
◦ Sarta and Qara Dagh exited, resulting in a write off relating to
Sarta of $19 million
◦ Somaliland licence extended until 2026
• Strong balance sheet provides opportunity to acquire and develop new
assets
◦ Net cash of $120 million at 31 December 2023 ($228 million at 31
December 2022)
◦ Total debt of $248 million reduced by $26 million through
repurchase of bonds at below 95 cents ($274 million at 31 December
2022)
◦ Genel expects to maintain net cash well above $100 million
throughout 2024
• Ongoing focus on being a socially responsible contributor to the global
energy mix
◦ Zero lost time incidents in 2023, with over four million hours now
worked since the last incident
◦ Carbon intensity of 14 kgCO2e/bbl for Scope 1 and 2 emissions in
2023 (2022: 17.6 kgCO2e/bbl), below the global oil and gas
industry average of 19 kgCO2e/boe
◦ Genel continues to invest in the host communities in which we
operate, aiming to invest in those areas in which we can make a
material difference to society
• The London-seated international arbitration two-week hearing which
included Genel’s claim for substantial compensation from the Kurdistan
Regional Government (‘KRG’) following the termination of the Miran and
Bina Bawi PSCs finished as scheduled. Parties will make written closing
submissions in April, subsequent to which written reply submissions
will be made in May. The timing of the result is uncertain, but
continues to be expected by the end of 2024
Potential catalysts for significant shareholder value creation in 2024
• Reopening of the ITP has the potential to materially increase cash
generation
• $107 million overdue from the KRG for oil sales from October 2022 to
March 2023 inclusive
• The Company continues to seek to acquire new assets to increase and
diversify our income streams
Enquiries:
Genel Energy
+44 20 7659 5100
Andrew Benbow, Head of Communications
Vigo Consulting
+44 20 7390 0230
Patrick d’Ancona
Genel will host a live presentation on the Investor Meet Company platform
on Tuesday 26 March at 1000 GMT. 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. 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.
CEO STATEMENT
It is difficult to look at 2023 without it being dominated by the closure
of the Iraq-Türkiye pipeline. The suspension of our route to export
resulted in a material reduction in production and cash flow. In a year in
which we were buffeted by factors beyond our control, it was a reminder of
the inherent resilience of our business model, a resilience that means we
retain a strong position from which we view the future with confidence.
Going in to 2023, one of our key aims was to continue the simplification of
the business, focusing on optimisation and cost control and investment in
business improvement. With the ITP suspended, we accelerated this journey,
significantly changing the size and shape of the organisation, materially
reducing our cost base. We are now in a position where our income from
strong local sales in January and February 2024 has covered our outflows,
we have over $100 million in net cash, and significant opportunities lie
ahead.
A reshaped business
The closure of the pipeline prompted us to move quickly to reduce our
capital expenditure, with $50 million cut from our original budget. We have
more than halved our workforce, and we have shed non-profitable assets. We
allowed the Qara Dagh licence to lapse, and Sarta has been terminated. We
are a significantly leaner vehicle than we were even six months ago, having
efficiently closed out our activity at Sarta and having minimised our
footprint and cost base in Kurdistan. And we are getting leaner still,
encouraging a constant state of awareness in the business about how we can
drive further cost efficiencies.
As we have cut costs we have ensured that we have kept the right personnel
to grow the business in the better times that certainly lie ahead. It is
important that a reshaped business does not mean a business that lacks
skills, and we must ensure that we have the correct balance between being
right sized in the current environment and having the right people to drive
Genel forward and take advantage of upcoming opportunities.
All of the changes that we have made to the business have been done with
our shareholders in mind, protecting shareholder funds and ensuring that we
remain resilient with a robust balance sheet, with a business that is set
up to maximise shareholder value going forward.
Robustly positioned
Our focus on resilience is bolstered by income from the Tawke licence,
which remains the engine room of the business. Working with the operator,
DNO, a great job has been done to build a new income stream from local
sales, while cutting operational costs by 65%. Production ramped up through
the second half of the year, and local sales have been material and robust
so far this year.
Going forward we expect cash generation from these local sales to match our
total business expenditure, should income remain at levels seen in Q1 2024.
Should the ITP reopen, our cash generation has the potential to more than
double overnight. Along with our industry peers, we continue to work hard
to facilitate the resumption of exports with appropriate commercial terms.
Positive comments are regularly being made by politicians from both the
Federal Government of Iraq and the KRG, although these are not being
supported by movement on key issues so far. The timing of export resumption
is therefore not something that we can suggest with any certainty.
Opportunities ahead
The reopening of the export route, with a stable and predictable payment
environment, is one of the numerous catalysts that we can see ahead in
2024. We are reviewing all options relating to the $107 million that is
still owed for past exports, the repayment of which would help to further
strengthen our balance sheet and boost cash generation.
As we work to unlock the significant value from Kurdistan, we continue our
search to add new income streams elsewhere. Our criteria for new assets
have not changed – we are focused on cash generation, seeking a value
accretive deal in a stable jurisdiction. We remain laser focused and
disciplined as we seek the right deal for our shareholders, and are
comfortable looking beyond the MENA region to get a deal that ticks all of
our boxes. As we reshaped our business in 2023, we have continued our
search for the right opportunity to integrate within Genel. There remain
opportunities out there that fit our criteria, and we are confident that we
will find the correct deal.
Miran and Bina Bawi arbitration progressing
The Company has committed significant senior management time to the
arbitration relating to the Miran and Bina Bawi PSCs. As a reminder, our
position is that the KRG’s termination of the Bina Bawi and Miran licences
in December 2021 was repudiatory and caused us significant losses. By way
of reference, we have spent over $1.4 billion acquiring and attempting
development of these assets, both as operator and non-operator up to the
termination of both PSCs in December 2021.
The two-week hearing (including factual and expert evidence) was held in
London as scheduled and ended on 1 March 2024. The timing of the result is
uncertain, but is expected by the end of 2024 following the Parties making
closing written submissions in April 2024 and reply written submissions in
May 2024. Our views on the merits of the case are unchanged since the
dispute process under the PSCs was commenced in Q3 2021.
Outlook
Genel retains a robust cash position, a resilient business model, and a
focus on taking advantage of the material catalysts ahead.
OPERATING REVIEW
Reserves and resources development
Genel's proven plus probable (2P) net working interest reserves totalled 89
MMbbls (31 December 2022: 92 MMbbls) at the end of 2023. A positive 4
MMbbls revision of 2P reserves at the Tawke PSC offset the removal of 2.7
MMbbls of 2P reserves from the terminated Sarta PSC, with 4.5 MMbbls of
production in 2023.
Remaining reserves Resources (MMboe)
(MMbbls)
Contingent Prospective
1P 2P 1C 2C Best
Gross Net Gross Net Gross Net Gross Net Gross Net
31 December 2022 267 69 349 92 37 11 129 36 4,722 3,006
Production (18) (5) (18) (4) - - - - - -
Acquisitions and - - (9) (3) (28) (8) (85) (25) (142) (43)
disposals
Extensions and - - - - - - - - - -
discoveries
New developments - - - - - - - - - -
Revision of previous (4) (1) 16 4 4 1 (5) (1) - -
estimates
31 December 2023 245 63 338 89 13 3 39 10 4,580 2,964
Production
Net production in 2023 averaged 12,410 bopd, significantly down on the
prior year (2022: 30,150 bopd) due to the suspension of the ITP. This
caused there to be minimal sales in the second quarter of the year, before
the local sales market was established in Q3 and production was then ramped
up in Q4. Production was dominated by the Tawke PSC, which produced 11,570
bopd.
All Genel production in H2 2023 came from the Tawke PSC. Gross production
from the Tawke licence increased to 65,780 bopd in Q4 2023, up from 25,980
bopd in Q3, with the field partners selling their entitlement share into
the local market.
PRODUCING ASSETS
Tawke PSC (25% working interest)
Gross production from the Tawke licence averaged 46,280 bopd in 2023,
impacted by the closure of the ITP. Following the start of local sales in
H2, production increased to 65,780 bopd in Q4 2023.
At the end of 2023, gross production from the Tawke licence was averaging
80,000 bopd, with entitlement barrels sold at prices in the low-to-mid $30s
per barrel. The operator, DNO, expects gross production at the licence to
continue to average 80,000 bopd. That figure could change depending on the
outcome of ongoing discussions related to recovery of arrears for past
deliveries to the KRG and payment terms and conditions for any future oil
exports, which in turn will drive investments in wells.
With operational spend having been reduced by 65%, the Tawke PSC is
currently generating over $3 million a month in net cash flow for Genel
from strong local sales, which if retained at current levels is able to
cover total organisational spend away from the licence.
Taq Taq (44% working interest, joint operator)
Prior to the closure of the ITP, field partners were planning a resumption
of drilling at Taq Taq. In line with Genel’s focus on reducing costs, and
lack of clarity regarding the resumption of exports and payments, this plan
was dropped. Costs were reduced to below $1 million per month at the start
of 2024, and further cuts are expected to reduce this to around half a
million dollars per month. Given the lack of meaningful cash flows expected
to come from Taq Taq going forward, its place in the Genel portfolio is
under review.
Sarta (30% working interest, operator)
Genel’s focus at the start of 2023 was on making ongoing production from
Sarta profitable, and capital investment was contingent on both licence
profitability and the extent to which there could be confidence that such
investment would add cash generative production. Given the investment
required, and the lack of certainty over a resumption of payments, Genel
and its joint venture partner, Chevron, informed the Ministry of Natural
Resources of its intention to surrender the asset and thereby terminate the
Sarta PSC on 1 December 2023.
Remediation work was completed in Q1 2024, at a net cost of $1 million, and
there will be no further material expenditure at Sarta going forward.
PRE-PRODUCTION ASSETS
Somaliland
Work continued in 2023 on readiness towards the potential drilling of a
well at the Toosan-1 well site on the SL10B13 block (51% working interest
and operator). The Environmental, Social and Health Impact Assessment was
finished, and required civil work at the well site at this stage of the
project is now complete.
Genel continues to believe that there is a tremendous opportunity in
Somaliland, and is assessing the timing of further investment. There is no
significant expenditure expected in 2024, and a licence extension has been
granted which allows for drilling to be undertaken in due course.
Morocco (Lagzira block - 75% working interest and operator)
The farm-out programme on the Lagzira block is ongoing.
FINANCIAL REVIEW
(all figures $ million) FY 2023 FY 2022
Brent average oil price $82/bbl $101/bbl
Revenue 84.8 401.9
Production costs (21.3) (34.3)
Cost recovered production asset capex (55.2) (85.9)
Production business net income after cost recovered capex 8.3 281.7
Other operating costs (3.6) -
G&A (excl. non-cash) (25.5) (17.7)
Net cash interest1 (4.2) (19.2)
Working capital 4.7 47.2
Free cash flow before investment in growth (20.3) 292.0
Non cost recovered capex (12.8) (57.2)
Net (expense) / income from discontinued operations (11.6) 12.5
Working capital and other (26.3) (12.5)
Free cash flow (71.0) 234.8
Dividend paid (33.5) (47.9)
Purchases of own shares (1.8) -
Purchases of own bonds (24.9) (6.0)
Net change in cash (131.2) 180.9
Cash 363.4 494.6
1 Net cash interest is bond interest payable less bank interest income (see
note 5)
2023 financial priorities
With the export pipeline suspended from March, 2023 did not generate the
financial performance that we had planned for, but we have taken decisions
that mean we have ended the year in a resilient position, with an outlook
where we can see a clear route to delivery of material shareholder value.
While the closure of the ITP accelerated and deepened some of our planned
cost cutting, we were already well on the way to reshaping the business and
ensuring that it has the financial strength to endure challenges and
maintain our exposure to the significantly value accretive potential events
that we hope to see materialise in 2024.
The table below summarises our progress against the 2023 financial
priorities of the Company as set out in our 2022 results.
2023 financial priorities Progress
• On suspension of exports,
completed work efficiently,
significantly cut capital and
operating expenditure,
• Maintain business resilience and suspended the dividend
balance sheet strength programme
• Developed a new income stream
through domestic sales
• Cash of $363 million at end of
2023
• Final dividend of 12¢ per share
paid
• On the Tawke licence, new wells
were completed in the first
half, and 2P reserves increased
• Put our significant cash balance to to offset production in the
work, earning appropriate returns year
to deliver value to shareholders • Bond debt reduced by $26
primarily through our dividend million at an average price
programme and diversify our cash below 95 cents in the dollar
generation • Continued to actively screen
and work up opportunities to
acquire new production assets,
with the ultimate aim of
resuming dividend returns to
shareholders
• Deliver the 2023 work programme on • Work programme reduced due to
time and on budget, and continue external conditions
simplification of the business with • Remaining activities completed
a focus on optimisation and cost on time and below budget
control and investment in business • Simplification of the business
improvement was accelerated and deepened,
with a two thirds reduction to
our total workforce
Outlook and financial priorities for 2024
The key principles of our financial focus remain largely unchanged. We have
a resilient business model that will continue to mitigate negative events
and maximise potential upside, all with a firm focus on maximising cash
generation. Ultimately, successful strategic delivery will lead to a
resumption of shareholder returns, through delivering robust, resilient,
diverse, and predictable cash flows.
Maintain business resilience and balance sheet strength
Running a resilient business with a strong balance sheet is a key component
of our business model. It is particularly relevant at the current time,
with the lack of access to export prices and volumes and the delayed
receipt of amounts owed. While the ITP remains closed, we protect the
balance sheet and resilience of the business by balancing the sources and
uses of our cash flows. Actions taken to reduce costs and restructure the
organisation in 2023 have prepared us well for this, with monthly
organisation spend excluding the cash-generative Tawke PSC reduced to under
$3 million per month at the time of writing.
Local market sales since November 2023 have seen relatively consistent
volumes, which has required constant attention from the operator. We
believe the Tawke PSC is well positioned to continue to deliver stable and
meaningful cash flows that will be sufficient to cover our costs, and as a
consequence we expect to retain a net cash position of over $100 million in
2024. Should the pipeline open, which we expect, then the subsequent
establishment of regular payments would materially boost our cash
generation, with the receipt of our outstanding receivable of $107 million
offering further significant upside.
Ensure capital availability for funding of key strategic objectives
Our capital allocation priorities remain maintenance of a strong balance
sheet and funding of the Company’s strategic objectives in order to
generate long-term value for shareholders.
We are currently retaining a significant cash balance in excess of the cash
required to fund the organic business in order to fund the acquisition of
new assets, as we seek to diversify our income streams. This balance is
partly funded by our bond debt of $248 million, which matures in October
2025. We retain strict discipline as we seek new opportunities, with
appropriate economic analysis and downside planning key considerations.
With a coupon that is low relative to prevailing market rates, the net cost
of retaining this optionality is low.
Ensure appropriate capital allocation
In pursuit of our strategic objectives, robust assessment of the expected
benefit to be obtained from invested capital underpins our processes to
ensure appropriate allocation of capital, making sure that each dollar
spent is done so in the knowledge that we are custodians of shareholder
funds.
In 2023, as well as cutting our capital allocation appropriately in the
face of the ongoing ITP closure, with Tawke drilling suspended, we ensured
that any investment was necessary and effective towards improving the
profitability of our business and achieving our objectives.
At the start of the year, we took the decision to exit the Qara Dagh
licence, due to the extent of certainty that redrilling on the licence
would have a positive outcome. For similar reasons, it was decided not to
pursue other drilling opportunities at Sarta, and to reduce costs
appropriately at Taq Taq. This focus has meant that our future activity at
that licence is under review. Finally, we agreed with the government and
our partner to extend the exploration period on the Toosan-1 well in
Somaliland. There is the opportunity for significant value creation in
Somaliland, where we remain excited about the potential of the subsurface.
In addition, we invested in the Miran and Bina Bawi arbitration process,
where we are seeking to protect our contractual position under the PSCs
which are governed by English law. We have invested over $1.4 billion in
the acquisition and attempted development of these assets, and we will
continue to ensure that funds are available to pursue collection in the
event of an Award in Genel’s favour.
Finally, we reduced our debt by nominal $26 million of our debt at a cost
of below 95 cents in the dollar, which provided an attractive level of
return without significantly impacting our capital availability for other
strategic objectives.
Financial results for the year
Income statement
(all figures $ million) FY 2023 FY 2022
Brent average oil price $82/bbl $101/bbl
Production (bopd, working interest) 12,410 30,150
Profit oil 25.4 143.4
Cost oil 58.6 116.1
Override royalty 0.8 142.4
Revenue 84.8 401.9
Production costs (21.3) (34.3)
Other operating costs (3.6) -
G&A (excl. depreciation and amortisation) (27.1) (18.5)
EBITDAX 32.8 349.1
Depreciation and amortisation (44.0) (134.3)
Exploration expense (0.1) (1.0)
Net write-off / impairment of oil and gas assets 1.2 (75.8)
Net (ECL) / reversal of ECL of receivables (9.1) 8.6
Net finance expense (9.1) (24.5)
Income tax expense (0.2) (0.2)
Loss from discontinued operations (32.8) (129.2)
Loss (61.3) (7.3)
Production of 12,410 bopd was significantly lower than last year (2022:
30,150 bopd) as a result of the suspension of exports through the ITP. This
resulted in very limited production between April and July, with production
from Tawke only restarting from July at lower levels, selling into the
domestic market. This decrease in production, together with the
significantly lower realised price per barrel for local sales, resulted in
a reduction in revenue from $402 million to $85 million, with $38 million
generated from local sales in H2 2023 and the remainder of $47 million
generated from export sales between January and March inclusive.
Production costs of $21 million decreased from the prior year (2022: $34
million), with cost per barrel $4.8/bbl in 2023 (2022: $3.3/bbl), with the
higher cost per barrel being the result of a combination of lower
production and some fixed costs.
Other operating costs of $4 million were related to Taq Taq which were
incurred after production cease.
Corporate cash costs were $12 million (2022: $14 million).
The decrease in revenue resulted in a similar decrease to EBITDAX, which
was $33 million (2022: $349 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.
Depreciation of $40 million (2022: $95 million) and Tawke intangibles
amortisation of $4 million (2022: $39 million) decreased due to lower
production and pipeline closure.
While Genel expects to recover its overdue receivables of $107 million in
full, given there is currently no repayment plan, a net expense of $10
million has been recognised relating to the expected credit loss on overdue
receivables. Further explanation is provided in note 1 to the financial
statements.
Interest income of $21 million (2022: $7 million) has significantly
increased as a result of the increase in interest rates, in turn reducing
our net cost of debt. Bond interest expense of $25 million (2022: $26
million) was in line with the previous year. Other finance expense of $5
million (2022: $5 million) related to non-cash discount unwinding on
provisions and bond which is partly offset by gain on buyback of bonds in
the year.
In relation to taxation, under the terms of KRI production sharing
contracts, corporate income tax due is paid on behalf of the Company by the
KRG from the KRG's own share of revenues, resulting in no corporate income
tax payment required or expected to be made by the Company. Tax presented
in the income statement was related to taxation of the service companies
(2023: $0.2 million, 2022: $0.2 million).
Following the termination of Sarta PSC in the year, income statement
figures of Sarta PSC have been disclosed as discontinued operation. Further
details are provided in note 7 to the financial statements.
Capital expenditure
Capital expenditure was reduced to $68 million (2023: $143 million), a
reduction of around $50 million reduced from our initial guidance. Spend on
production assets was $59 million, and pre-production assets $9 million,
with $20 million spent in H2 as expenditure cuts were made following the
ITP closure.
(all figures $ million) FY 2023 FY 2022
Cost recovered production capex 55.1 85.9
Non cost recovered production capex 3.8 47.5
Other exploration and appraisal capex 9.1 9.7
Capital expenditure 68.0 143.1
Cash flow, cash, net cash and debt
Gross proceeds received totalled $102 million (2022: $473 million).
(all figures $ million) FY 2023 FY 2022
Brent average oil price $82/bbl $101/bbl
EBITDAX 32.8 349.1
Working capital 22.3 63.3
Operating cash flow 55.1 412.4
Producing asset cost recovered capex (66.6) (77.8)
Development capex (22.2) (50.4)
Exploration and appraisal capex (9.7) (20.0)
Interest and other (27.6) (29.4)
Free cash flow (71.0) 234.8
Free cash flow is presented in order to illustrate the free cash generated
for equity. Free cash outflow was $71 million (2022: $235 million inflow)
with an overall decrease due to pipeline closure and delay in proceeds.
(all figures $ million) FY 2023 FY 2022
Free cash flow (71.0) 234.8
Dividend paid (33.5) (47.9)
Purchase of shares (1.8) -
Bond repayment (24.9) (6.0)
Net change in cash (131.2) 180.9
Opening cash 494.6 313.7
Closing cash 363.4 494.6
Debt reported under IFRS (243.7) (266.6)
Net cash 119.7 228.0
The bonds maturing in 2025 have two financial covenant maintenance tests:
Financial covenant Test YE 2023
Equity ratio (Total equity/Total assets) > 40% 55%
Minimum liquidity > $30m $363m
Net assets
Net assets at 31 December 2023 were $434 million (31 December 2022: $528
million) and consist primarily of oil and gas assets of $331 million (31
December 2022: $327 million), net trade receivables of $93 million (31
December 2022: $117 million) and net cash of $120 million (31 December
2022: $228 million).
Liquidity / cash counterparty risk management
The Company monitors its cash position, cash forecasts and liquidity on a
regular basis. The Company holds surplus cash in treasury bills, 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.
Going concern
The Directors have assessed that the Company’s forecast liquidity provides
adequate headroom over forecast expenditure for the 12 months following the
signing of the annual report for the year ended 31 December 2023 and
consequently that the Company is considered a going concern. Further
explanation is provided in note 1 to the financial statements.
The Company is in a net cash position with no near-term maturity of
liabilities.
Consolidated statement of comprehensive income
For the year ended 31 December 2023
Restated
2023 2022
Note $m $m
Revenue 2 84.8 401.9
Production costs 3 (21.3) (34.3)
Depreciation and amortisation of oil assets 3 (43.9) (134.2)
Gross profit 19.6 233.4
Exploration expense 3 (0.1) (1.0)
Other operating costs 3 (3.6) -
Net write-off of intangible assets 3 1.2 (75.8)
Net (expected credit loss (‘ECL’)) / reversal of ECL 3 (9.1) 8.6
of receivables
General and administrative costs 3 (27.2) (18.6)
Operating (loss) / profit (19.2) 146.6
Operating (loss) / profit is comprised of:
EBITDAX 32.8 349.1
Depreciation and amortisation 3 (44.0) (134.3)
Exploration expense 3 (0.1) (1.0)
Net write-off of intangible assets 3 1.2 (75.8)
Net (ECL) / reversal of ECL of receivables 3 (9.1) 8.6
Finance income 5 20.6 6.7
Bond interest expense 5 (24.8) (25.9)
Net other finance expense 5 (4.9) (5.3)
(Loss) / profit before income tax (28.3) 122.1
Income tax expense 6 (0.2) (0.2)
(Loss) / profit and total comprehensive (expense) / (28.5) 121.9
income from continuing operations
Loss from discontinued operations 7 (32.8) (129.2)
Loss and total comprehensive expense (61.3) (7.3)
Attributable to:
Owners of the parent (61.3) (7.3)
(61.3) (7.3)
(Loss) / Earnings per ordinary share ¢ ¢
From continuing operations:
Basic 8 (10.2) 43.7
Diluted 8 (10.2) 43.7
From continuing and discontinued operations:
Basic 8 (22.0) (2.6)
Diluted 8 (22.0) (2.6)
Basic (LPS) / EPS excluding impairments1 8 (11.9) 66.7
1Basic (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
Previous year’s figures have been restated for discontinued operation
disclosure in relation to Sarta PSC (see note 7).
Consolidated balance sheet
At 31 December 2023
2023 2022
Note $m $m
Assets
Non-current assets
Intangible assets 9 84.7 79.1
Property, plant and equipment 10,20 246.5 248.1
Trade and other receivables 11 66.5 -
397.7 327.2
Current assets
Trade and other receivables 11 34.0 121.7
Cash and cash equivalents 12 363.4 494.6
397.4 616.3
Total assets 795.1 943.5
Liabilities
Non-current liabilities
Trade and other payables 13,20 (0.5) (1.2)
Deferred income 14 (8.2) (6.5)
Provisions 15 (45.2) (52.2)
Interest bearing loans 16 (243.7) (266.6)
(297.6) (326.5)
Current liabilities
Trade and other payables 13,20 (57.6) (82.4)
Deferred income 14 (6.0) (6.8)
(63.6) (89.2)
Total liabilities (361.2) (415.7)
Net assets 433.9 527.8
Owners of the parent
Share capital 18 43.8 43.8
Share premium 3,863.9 3,897.4
Accumulated losses (3,473.8) (3,413.4)
Total equity 433.9 527.8
Consolidated statement of changes in equity
For the year ended 31 December 2023
Share Share Accumulated Total
capital premium losses equity
$m $m $m $m
Note
At 1 January 2022 43.8 3,947.5 (3,410.2) 581.1
Loss and total comprehensive - - (7.3) (7.3)
expense
Contributions by and
distributions to owners
Share-based payments 21 - - 4.1 4.1
Dividends provided for or 19 - (50.1) - (50.1)
paid1
At 31 December 2022 and 1 43.8 3,897.4 (3,413.4) 527.8
January 2023
Loss and total comprehensive - - (61.3) (61.3)
expense
Contributions by and
distributions to owners
Share-based payments 21 - - 2.7 2.7
Purchase of own shares for - - (1.8) (1.8)
employee share plan
Dividends provided for or 19 - (33.5) - (33.5)
paid1
At 31 December 2023 43.8 3,863.9 (3,473.8) 433.9
1 The Companies (Jersey) Law 1991 does not define the expression “dividend”
but refers instead to “distributions”. Distributions may be debited to any
account or reserve of the Company (including share premium account)
Consolidated cash flow statement
For the year ended 31 December 2023
Note 2023 2022
$m $m
Cash flows from operating activities
Loss for the year (61.3) (7.3)
Adjustments for:
Net finance expense 5,7 9.4 25.4
Taxation 6 0.2 0.2
Depreciation and amortisation 3,7 46.7 152.0
Exploration expense 3 0.1 1.0
Net impairments, write-offs 3,7 28.1 193.1
Other non-cash items (royalty income and 0.8 (7.4)
share-based payment cost)
Changes in working capital:
Decrease in trade and other receivables 14.4 47.2
(Decrease) / Increase in trade and other payables (3.7) 1.7
Cash generated from operations 34.7 405.9
Interest received 5 20.6 6.7
Taxation paid (0.2) (0.2)
Net cash generated from operating activities 55.1 412.4
Cash flows from investing activities
Payments of intangible assets (9.7) (20.0)
Payments of property, plant and equipment (88.8) (128.2)
Net cash used in investing activities (98.5) (148.2)
Cash flows from financing activities
Dividends paid to company’s shareholders 19 (33.5) (47.9)
Purchase of own shares (1.8) -
Bond repayment 16 (24.9) (6.0)
Lease payments (2.8) (3.8)
Interest paid (24.8) (25.6)
Net cash used in financing activities (87.8) (83.3)
Net (decrease) / increase in cash and cash (131.2) 180.9
equivalents
Cash and cash equivalents at 1 January 12 494.6 313.7
Cash and cash equivalents at 31 December 12 363.4 494.6
Notes to the consolidated financial statements
1. Summary of material accounting policies
1. Basis of preparation
Genel Energy Plc – registration number: 107897 (the Company), is a public
limited company incorporated and domiciled in Jersey with a listing on the
London Stock Exchange. The address of its registered office is 26 New
Street, St Helier, Jersey, JE2 3RA.
The consolidated financial statements of the Company have been prepared in
accordance with International Financial Reporting Standards as adopted by
the European Union and interpretations issued by the IFRS Interpretations
Committee (together ’IFRS’); are prepared under the historical cost
convention except as where stated; and comply with Company (Jersey) Law
1991. The significant accounting policies are set out below and have been
applied consistently throughout the period.
The Company prepares its financial statements on a historical cost basis,
unless accounting standards require an alternate measurement basis. Where
there are assets and liabilities calculated on a different basis, this fact
is disclosed either in the relevant accounting policy or in the notes to
the financial statements.
Items included in the financial information of each of the Company's
entities are measured using the currency of the primary economic
environment in which the entity operates (the functional currency). The
consolidated financial statements are presented in US dollars to the
nearest million ($ million) rounded to one decimal place, except where
otherwise indicated.
For explanation of the key judgements and estimates made by the Company in
applying the Company’s accounting policies, refer to significant accounting
judgements and estimates on pages 17 to 19.
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 $363 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 forecast expenditure for the
12 months following the signing of the annual report for the period ended
31 December 2023 and consequently that the Company is considered a going
concern.
Consolidation
The consolidated financial statements consolidate the Company and its
subsidiaries. These accounting policies have been adopted by all companies.
Subsidiaries
Subsidiaries are all entities over which the Company has control. The
Company controls an entity when it is exposed to, or has rights to,
variable returns from its involvement with the entity and has the ability
to affect those returns through its power over the entity. Subsidiaries are
fully consolidated from the date on which control is transferred to the
Company. They are deconsolidated from the date that control ceases.
Transactions, balances and unrealised gains on transactions between
companies are eliminated.
Joint arrangements and associates
Arrangements under which the Company has contractually agreed to share
control with another party, or parties, are joint ventures where the
parties have rights to the net assets of the arrangement, or joint
operations where the parties have rights to the assets and obligations for
the liabilities relating to the arrangement. Investments in entities over
which the Company has the right to exercise significant influence but has
neither control nor joint control are classified as associates and
accounted for under the equity method.
The Company recognises its assets, liabilities, income and expenses
relating to its interests in joint operations, including its share of
assets and income held jointly and liabilities and expenses incurred
jointly with other partners.
Farm-in/farm-out
Farm-in/farm-out transactions undertaken in the exploration phase of an oil
and gas asset are accounted for on a no gain/no loss basis due to inherent
uncertainties in the exploration phase and associated difficulties in
determining fair values reliably prior to the determination of commercially
recoverable proved reserves. The resulting exploration and evaluation asset
is then assessed for impairment indicators under IFRS 6. Any cash payment
or proceeds are presented as an increase or reduction to additions
respectively.
2. Significant accounting judgements and estimates
The preparation of the financial statements in accordance with IFRS
requires the Company to make judgements and estimates that affect the
reported results, assets and liabilities. Where judgements and estimates
are made, there is a risk that the actual outcome could differ from the
judgement or estimate made.
Significant judgements
The following are the significant judgements 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.
Sarta PSC (note 10 and 7)
At 31 December 2022, the Company’s assessment on the recoverable value of
the Sarta PSC had resulted with an impairment expense of $125.5 million
following the disappointing results of the two appraisal wells and pilot
production.
In 2023, the Company has informed the KRG of its intention to exit the
Sarta licence and the remaining recoverable value of the Sarta PSC have
been reduced to nil and a write-off expense of $18.7 million has been
booked. Following the termination of the PSC on 1 December 2023,
decommissioning provisions have been derecognised.
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 and the viability statement.
Proved and probable reserves are estimates of the amount of hydrocarbons
that can be economically extracted from the Company’s assets. The Company
estimates its reserves using standard recognised evaluation techniques
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% (2022: 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 year-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, going concern and the
viability statement.
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 2023 2024 2025 2026 2027 2028
Actual / Estimate 82 80 76 74 71 70
HY2023 estimate 82 78 74 70 70 70
Prior year estimate 82 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.
The Company has also taken the change into account in its assessment of
impairment reversal and considered it appropriate not to reverse any
previous impairments.
Estimation of the recoverable value of deferred receivables and trade
receivables (note 11)
As of 31 December 2023, the Company is owed six months of payments.
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 by considering the recovery of previous deferred
receivables. The result of this assessment is an ECL provision of $14.5
million. Each 1% increase in discount rate would increase the ECL by $0.9
million. Sensitivity of the calculation 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 Group and Company’s accounting policies and that
have effect on the amounts recognised in the financial statements.
Decommissioning provision (note 15)
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% (2022: 2%) and
discounted at 4% (2022: 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.
3. Accounting policies
The accounting policies adopted in preparation of these financial
statements are consistent with those used in preparation of the annual
financial statements for the year ended 31 December 2022, adjusted for
transitional requirements where necessary, further explained under revenue
and changes in accounting policies headings.
Revenue
Revenue from contracts with customers is earned based on the entitlement
mechanism under the terms of the relevant PSC and, overriding royalty
income (‘ORRI’), which was earned on 4.5% of gross field revenue from the
Tawke licence up until July 2022.
Under IFRS 15, entitlement revenue and ORRI is recognised when the control
of the product is deemed to have passed to the customer, in exchange for
the consideration amount determined by the terms of the contract. For
exports the control passes to the customer when the oil enters the export
pipe. For local sales, the control passes to the customer when the oil is
delivered to the trucks.
Entitlement has two components: cost oil, which is the mechanism by which
the Company recovers its costs incurred on an asset, and profit oil, which
is the mechanism through which profits are shared between the Company, its
partners and the KRG. The Company pays capacity building payments on profit
oil entitlement earned on the Sarta and Taq Taq licences, which become due
for payment once the Company has received the relevant proceeds. Profit oil
revenue is always reported net of any capacity building payments that will
become due.
The Company’s export oil sales made to the KRG are valued at a netback
price which is explained further in significant accounting estimates and
judgements. The Company’s local sales are valued at the price agreed with
the local buyers.
The Company is not able to measure the tax that has been paid on its behalf
and consequently has not been able to assess where revenue should be
reported gross of implied income tax paid.
The Company’s revenue from other sources includes a non-cash royalty income
which is recognised in the statement of comprehensive income in a manner
consistent with entitlement mechanism.
Intangible assets
Exploration and evaluation assets
Oil and gas assets classified as exploration and evaluation assets are
explained under Oil and Gas assets below.
Tawke RSA
Intangible assets include the Receivable Settlement Agreement (‘RSA’)
effective from 1 August 2017, which was entered into in exchange for trade
receivables due from KRG for Taq Taq and Tawke past sales. The RSA was
recognised at cost and is amortised on a units of production basis in line
with the economic lives of the rights acquired.
Property, plant and equipment
Producing and Development assets
Oil and gas assets classified as producing and development assets are
explained under Oil and Gas assets below.
Oil and gas assets
Costs incurred prior to obtaining legal rights to explore are expensed to
the statement of comprehensive income.
Exploration, appraisal and development expenditure is accounted for under
the successful efforts method. Under the successful efforts method only
costs that relate directly to the discovery and development of specific oil
and gas reserves are capitalised as exploration and evaluation assets
within intangible assets so long as the activity is assessed to be
de-risking the asset and the Company expects continued activity on the
asset into the foreseeable future. Costs of activity that do not identify
oil and gas reserves are expensed.
All licence acquisition costs, geological and geophysical costs,
inventories and other direct costs of exploration, evaluation and
development are capitalised as intangible assets or property, plant and
equipment according to their nature. Intangible assets comprise costs
relating to the exploration and evaluation of properties which the
directors consider to be unevaluated until assessed as being 2P reserves
and commercially viable.
Once assessed as being 2P reserves they are tested for impairment and
transferred to property, plant and equipment as development assets. Where
properties are appraised to have no commercial value, the associated costs
are expensed as an impairment loss in the period in which the determination
is made. Development assets are classified under producing assets following
the commercial production commencement.
Development expenditure is accounted for in accordance with IAS 16 –
Property, plant and equipment. Producing assets are depreciated once they
are available for use and are depleted on a field-by-field basis using the
unit of production method. The sum of carrying value and the estimated
future development costs are divided by total barrels to provide a $/barrel
unit depreciation cost. Changes to depreciation rates as a result of
changes in forecast production and estimates of future development
expenditure are reflected prospectively.
The estimated useful lives of property, plant and equipment and their
residual values are reviewed on an annual basis and changes in useful lives
are accounted for prospectively. The gain or loss arising on the disposal
or retirement of an asset is determined as the difference between the sales
proceeds and the carrying amount of the asset and is recognised in the
statement of comprehensive income for the relevant period.
Where exploration licences are relinquished or exited for no consideration
or costs incurred are neither de-risking nor adding value to the asset, the
associated costs are expensed to the income statement.
Impairment testing of oil and gas assets is considered in the context of
each cash generating unit. A cash generating unit is generally a licence,
with the discounted value of the future cash flows of the CGU compared to
the book value of the relevant assets and liabilities.
Subsequent costs
The cost of replacing part of an item of property and equipment is
recognised in the carrying amount of the item if it is probable that the
future economic benefits embodied within the part will flow to the Company,
and its cost can be measured reliably. The net book value of the replaced
part is expensed. The costs of the day-to-day servicing and maintenance of
property, plant and equipment are recognised in the statement of
comprehensive income.
Discontinued operations
A part of the Company’s operations is classified as a discontinued
operation if the component has either been disposed of or is classified as
held for sale and represents a separate major line of business or
geographic area of operations, is part of a single coordinated plan to
dispose of a separate major line of business or geographic area of
operations, or is a subsidiary acquired exclusively with a view to resale.
Discontinued operations are excluded from the net income/loss from
continuing operations and are presented as a single amount as gain/loss
from discontinued operations, in the consolidated statement of
comprehensive income. When an operation is classified as a discontinued
operation, the comparative consolidated statement of comprehensive income
is restated and presented as if the operation had been classified as such
from the start of the comparative year.
Right of use (RoU) assets / Lease liabilities
The Company recognises a right to use asset and lease liability, depreciate
the associated asset, re-measure and reduce the liability through lease
payments unless the underlying leased asset is of low value and/or short
term in nature. The Company uses the following judgements permitted by the
standard: applying a single discount rate to a portfolio of leases with
reasonably similar characteristics, exemption from recognition of right of
use assets with a lease term of less than 12 months at the inception and
using hindsight in determining the lease term where the contract contains
options to extend or terminate the lease. Right-of-use assets are
depreciated over the lifetime of the related lease contract. Lease
liabilities were measured at the present value of the remaining lease
payments, discounted using the lessee’s incremental borrowing rate and
included within trade and other payables.
Drill rig contracts are service contracts where contractors provide the rig
together with the services and the contracted personnel on a day-rate basis
for the purpose of drilling exploration or development wells. The Company
has no right of use of the rigs. The aggregate payments under drilling
contracts are determined by the number of days required to drill each well
and are capitalised as exploration or development assets as appropriate.
Financial assets and liabilities
Classification
The Company assesses the classification of its financial assets on initial
recognition at amortised cost, fair value through other comprehensive
income or fair value through profit and loss. The Company assesses the
classification of its financial liabilities on initial recognition at
either fair value through profit and loss or amortised cost.
Recognition and measurement
Regular purchases and sales of financial assets are recognised at fair
value on the trade-date – the date on which the Company commits to purchase
or sell the asset. Trade and other receivables, trade and other payables,
borrowings and deferred contingent consideration are subsequently carried
at amortised cost using the effective interest method.
Trade and other receivables
Trade receivables are amounts due from crude oil sales, sales of gas or
services performed in the ordinary course of business. If payment is
expected within one year or less, trade receivables are classified as
current assets otherwise they are presented as non-current assets. Trade
receivables are recognised initially at fair value and subsequently
measured at amortised cost using the effective interest method, less
provision for expected credit loss.
The Company’s assessment of expected credit loss model is explained below
under financial assets.
Cash and cash equivalents
In the consolidated balance sheet and consolidated statement of cash flows,
cash and cash equivalents includes cash in hand, deposits held on call with
banks, other short-term highly liquid investments which are assessed as
cash and cash equivalents under IAS 7 and includes the Company’s share of
cash held in joint operations.
Interest-bearing borrowings
Borrowings are recognised initially at fair value, net of any discount in
issuance and transaction costs incurred. Borrowings are subsequently
carried at amortised cost; any difference between the proceeds (net of
transaction costs) and the redemption value is recognised in the statement
of comprehensive income over the period of the borrowings using the
effective interest method.
Fees paid on the establishment of loan facilities are recognised as
transaction costs of the loan.
Borrowings are presented as long or short-term based on the maturity of the
respective borrowings in accordance with the loan or other agreement.
Borrowings with maturities of less than twelve months are classified as
short-term. Amounts are classified as long-term where maturity is greater
than twelve months. Where no objective evidence of maturity exists, related
amounts are classified as short-term.
Trade and other payables
Trade and other payables are recognised initially at fair value. Subsequent
to initial recognition they are measured at amortised cost using the
effective interest method.
Offsetting
Financial assets and liabilities are offset and the net amount reported in
the balance sheet when there is a legally enforceable right to offset the
recognised amounts and there is an intention to settle on a net basis or
realise the asset and settle the liability simultaneously.
Provisions
Provisions are recognised when the Company has a present obligation as a
result of a past event, and it is probable that the Company will be
required to settle that obligation. Provisions are measured at the
Company’s best estimate of the expenditure required to settle the
obligation at the balance sheet date and are discounted to present value
where the effect is material. The unwinding of any discount is recognised
as finance costs in the statement of comprehensive income.
Decommissioning
Provision is made for the cost of decommissioning assets at the time when
the obligation to decommission arises. Such provision represents the
estimated discounted liability for costs which are expected to be incurred
in removing production facilities and site restoration at the end of the
producing life of each field. A corresponding cost is capitalised to
property, plant and equipment and subsequently depreciated as part of the
capital costs of the production facilities. Any change in the present value
of the estimated expenditure attributable to changes in the estimates of
the cash flow or the current estimate of the discount rate used are
reflected as an adjustment to the provision and capitalised as part of the
cost of the assets.
Impairment
Exploration and evaluation assets
Spend on exploration and evaluation assets is capitalised in accordance
with IFRS 6. The carrying amounts of the Company’s exploration and
evaluation assets are reviewed at each reporting date to determine whether
there is any indication of impairment under IFRS 6. Impairment assessment
of exploration and evaluation assets is considered in the context of each
cash generating unit, which is generally represented by relevant the
licence.
Producing and Development assets
The carrying amounts of the Company’s producing and development assets are
reviewed at each reporting date to determine whether there is any
indication of impairment or reversal of impairment. If any such indication
exists, then the asset’s recoverable amount is estimated. The recoverable
amount of an asset or cash generating unit is the greater of its value in
use and its fair value less costs of disposal. For value in use, the
estimated future cash flows arising from the Company’s future plans for the
asset are discounted to their present value using a nominal post tax
discount rate that reflects market assessments of the time value of money
and the risks specific to the asset. For fair value less costs of disposal,
an estimation is made of the fair value of consideration that would be
received to sell an asset less associated selling costs (which are assumed
to be immaterial). Assets are grouped together into the smallest group of
assets that generates cash inflows from continuing use that are largely
independent of the cash inflows of other assets or groups of assets (cash
generating unit).
The estimated recoverable amount is then compared to the carrying value of
the asset. Where the estimated recoverable amount is materially lower than
the carrying value of the asset an impairment loss is recognised.
Non-financial assets that suffered impairment are reviewed for possible
reversal of the impairment at each reporting date.
Property, plant and equipment and intangible assets
Impairment testing of oil and gas assets is explained above. When
impairment indicators exist for other non-financial assets, impairment
testing is performed based on the higher of value in use and fair value
less costs of disposal. The Company assets' recoverable amount is
determined by fair value less costs of disposal.
Financial assets
Impairment of financial assets is assessed under IFRS 9 with a
forward-looking expected credit loss (‘ECL’) model. The standard requires
the Company to book an allowance for ECL for its financial assets. The
Company has assessed its trade receivables as at 31 December 2023 for ECL.
Further explanation is provided in significant accounting judgements and
estimates.
Equity
Share capital
Amounts subscribed for share capital at nominal value. Ordinary shares are
classified as equity.
When share capital recognised as equity is repurchased, the amount of the
consideration paid, which includes directly attributable costs, is net of
any tax effects and is recognised as a deduction in equity. Repurchased
shares are classified as treasury shares and are presented as a deduction
from total equity. When treasury shares are subsequently sold or reissued,
the amount received is recognised as an increase in equity and the
resulting surplus or deficit of the transaction is transferred to/from
retained earnings.
Share premium
Amounts subscribed for share capital in excess of nominal value.
Accumulated loss
Cumulative net losses recognised in the statement of comprehensive income
net of amounts recognised directly in equity.
Dividend
Liability to pay a dividend is recognised based on the declared timetable.
A corresponding amount is recognised directly in equity.
Employee benefits
Short-term benefits
Short-term employee benefit obligations are expensed to the statement of
comprehensive income as the related service is provided. A liability is
recognised for the amount expected to be paid under short-term cash bonus
or profit-sharing plans if the Company has a present legal or constructive
obligation to pay this amount as a result of past service provided by the
employee and the obligation can be estimated reliably.
Share-based payments
The Company operates equity-settled share-based compensation plans. The
expense required in accordance with IFRS 2 is recognised in the statement
of comprehensive income over the vesting period of the award and partially
capitalised as oil and gas assets in line with the hours incurred by the
employees. The expense is determined by reference to option pricing models,
principally Monte Carlo and adjusted Black-Scholes models.
At each balance sheet date, the Company revises its estimate of the number
of options that are expected to become exercisable. Any revision to the
original estimates is reflected in the statement of comprehensive income
with a corresponding adjustment to equity immediately to the extent it
relates to past service and the remainder over the rest of the vesting
period.
Finance income and finance costs
Finance income comprises interest income on cash invested, foreign currency
gains and the unwind of discount on any assets held at amortised cost.
Interest income is recognised as it accrues, using the effective interest
method.
Finance expense comprises interest expense on borrowings, foreign currency
losses and discount unwind on any liabilities held at amortised cost.
Borrowing costs directly attributable to the acquisition of a qualifying
asset as part of the cost of that asset are capitalised over the respective
assets.
Taxation
Under the terms of the KRI PSCs, the Company is not required to pay any
cash corporate income taxes as explained in significant accounting
judgements and estimates. Current tax expense is incurred on profits of
service companies.
Segmental reporting
IFRS 8 requires the Company to disclose information about its business
segments and the geographic areas in which it operates. It requires
identification of business segments on the basis of internal reports that
are regularly reviewed by the CEO, the chief operating decision maker, in
order to allocate resources to the segment and assess its performance.
Related parties
Parties are related if one party has the ability, directly or indirectly,
to control the other party or exercise significant influence over the party
in making financial or operational decisions. Parties are also related if
they are subject to common control. Transactions between related parties
are transfers of resources, services or obligations, regardless of whether
a price is charged and are disclosed separately within the notes to the
consolidated financial information.
New standards
The following new accounting standards, amendments to existing standards
and interpretations are effective on 1 January 2023. Amendments to IAS 12
Income taxes: International Tax Reform – Pillar Two Model Rules (issued on
23 May 2023), Amendments to IFRS 17 Insurance contracts: Initial
Application of IFRS 17 and IFRS 9 – Comparative Information (issued on 9
December 2021), Amendments to IAS 12 Income Taxes: Deferred Tax related to
Assets and Liabilities arising from a Single Transaction (issued on 7 May
2021), Amendments to IAS 1 Presentation of Financial Statements and IFRS
Practice Statement 2: Disclosure of Accounting policies (issued on 12
February 2021), Amendments to IAS 8 Accounting policies, Changes in
Accounting Estimates and Errors: Definition of Accounting Estimates (issued
on 12 February 2021), IFRS 17 Insurance Contracts (issued on 18 May 2017).
These standards did not have a material impact on the Company’s results or
financial statements disclosures in the current reporting period except
Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice
Statement 2: Disclosure of Accounting policies (issued on 12 February
2021). The Company has adopted the amendments to IAS 1 for the first time
in the current year as to disclose material accounting policies.
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: Amendments to IAS 21 The Effects of
Changes in Foreign Exchange Rates: Lack of Exchangeability (issued on 15
August 2023), 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). 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.
2. Segmental information
The Company has two reportable business segments: Production and
Pre-production. Capital allocation decisions for the production segment are
considered in the context of the cash flows expected from the production
and sale of crude oil. The production segment is comprised of the producing
fields on the Tawke PSC (Tawke and Peshkabir fields) and the Taq Taq PSC
which are located in the KRI and make export sales to the KRG 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 year ended 31 December 2023
Total
Production Pre-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 the year (see note 7).
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
For the year ended 31 December 2022
Total
Production Pre-production Other
$m $m $m $m
Revenue from contracts with 388.7 - - 388.7
customers
Revenue from other sources 13.2 - - 13.2
Cost of sales (168.5) - - (168.5)
Gross profit 233.4 - - 233.4
Exploration expense - (1.0) - (1.0)
Net write-off of intangible - (75.8) - (75.8)
asset
Reversal of ECL of receivables 10.8 - 2.0 12.8
ECL of receivables (4.2) - - (4.2)
General and administrative - - (18.6) (18.6)
costs
Operating profit / (loss) 240.0 (76.8) (16.6) 146.6
Operating profit / (loss) is
comprised of
EBITDAX 367.6 - (18.5) 349.1
Depreciation and amortisation (134.2) - (0.1) (134.3)
Exploration expense - (1.0) - (1.0)
Net write-off of intangible - (75.8) - (75.8)
assets
Reversal of ECL of receivables 10.8 - 2.0 12.8
ECL of receivables (4.2) - - (4.2)
Finance income - - 6.7 6.7
Bond interest expense - - (25.9) (25.9)
Other finance expense (2.4) (0.4) (2.5) (5.3)
Profit / (Loss) before income 237.6 (77.2) (38.3) 122.1
tax from continuing operations
Loss from discontinued (129.2) - - (129.2)
operations
Profit / (Loss) before income 108.4 (77.2) (38.3) (7.1)
tax
Capital expenditure 133.4 9.7 - 143.1
Total assets 447.3 23.5 472.7 943.5
Total liabilities (111.9) (17.7) (286.1) (415.7)
Revenue from contracts with customers includes $94.5 million arising from
the ORRI and $34.7 million in relation to the suspended ORRI.
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
3. Operating (loss) / profit
2023 2022
$m $m
Production costs (21.3) (34.3)
Depreciation of oil and gas property, plant (39.6) (95.0)
and equipment (excl. RoU assets)
Amortisation of oil and gas intangible (4.3) (39.2)
assets
Cost of sales (65.2) (168.5)
Exploration expense (0.1) (1.0)
Other operating costs1 (3.6) -
1 Other operating costs relate to Taq Taq costs which were incurred after
production ceased in May 2023, following the pipeline closure.
Write-off of intangible assets (note 9) - (78.0)
Net reversal of accruals and provisions 1.2 2.2
Net write-off of intangible assets 1.2 (75.8)
Reversal of ECL of other receivables - 2.0
Reversal of ECL of trade receivables (note 4.2 10.8
1,11)
ECL of trade receivables (note 1,11) (13.3) (4.2)
Net (ECL) / reversal of ECL of receivables (9.1) 8.6
Corporate cash costs (12.4) (14.0)
Non-recurring costs (13.1) (3.7)
Corporate share-based payment expense (1.6) (0.8)
Depreciation and amortisation of corporate (0.1) (0.1)
assets (excl. RoU assets)
General and administrative expenses (27.2) (18.6)
Auditor’s remuneration:
Audit of the Group’s consolidated financial statements (0.3) (0.3)
Audit of the Group’s subsidiaries pursuant to legislation (0.1) (0.1)
Total audit services (0.4) (0.4)
Interim review (0.1) (0.1)
Total audit related and non-audit services (0.5) (0.5)
All fees paid to the auditor were charged to operating loss in both years.
4. Staff costs and headcount
2023 2022
$m $m
Wages and salaries (19.3) (21.1)
Contractors costs (13.8) (20.6)
Social security costs (1.9) (4.3)
Share based payments (3.7) (4.1)
(38.7) (50.1)
2023 number 2022 number
Average headcount was:
Türkiye 38 39
KRI 23 38
UK 30 34
Somaliland 27 18
Contractors 84 129
202 258
5. Finance expense and income
2023 2022
$m $m
Bond interest (24.8) (25.9)
Other finance expense (non-cash) (6.0) (5.3)
Finance expense (30.8) (31.2)
Bank interest income 20.6 6.7
Gain on bond buyback 1.1 -
Finance income 21.7 6.7
Net finance expense (9.1) (24.5)
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 1.
7. Discontinued operations
Sarta PSC was terminated on 1 December 2023. The results of the
discontinued operations, which have been included in the loss for the year,
were as follows:
2023 2022
$m $m
Revenue 3.6 30.8
Production costs (3.6) (16.8)
Depreciation of oil and gas property, plant and equipment (0.7) (14.9)
Gross loss (0.7) (0.9)
Other operating costs1 (20.0) -
Write-off / impairment of property, plant and equipment (18.7) (125.5)
(note 1,10)
Reversal of provisions 8.2 -
Reversal of ECL of trade receivables 0.4 -
ECL of trade receivables (1.2) (0.4)
General and administrative costs (0.5) (1.5)
Operating loss (32.5) (128.3)
Other finance expense (non-cash) (0.3) (0.9)
Loss from discontinued operations (32.8) (129.2)
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.
2023 2022
Cash flows from discontinued operations $m $m
Net cash (used in) / generated from operating activities (27.8) 18.5
Net cash used in investing activities (3.8) (53.7)
Net cash used in financing activities (2.1) (2.9)
8. (Loss) / Earnings per share
Basic
Basic loss per share is calculated by dividing the loss attributable to
owners of the parent by the weighted average number of shares in issue
during the year.
2023 2022
(Loss) / Profit from continuing operations ($m) (28.5) 121.9
Loss from discontinued operations ($m) (32.8) (129.2)
Loss attributable to owners of the parent ($m) (61.3) (7.3)
Weighted average number of ordinary shares – number 278,836,216 278,654,909
1
Basic (loss) / earnings per share – cents per share (10.2) 43.7
(from continuing operations)
Basic loss per share – cents per share (22.0) (2.6)
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 year ended 31 December 2023 and 31 December
2022, the performance shares, restricted shares and share options are
anti-dilutive and therefore diluted LPS is the same as basic LPS:
2023 2022
(Loss) / Profit from continuing operations ($m) (28.5) 121.9
Loss from discontinued operations ($m) (32.8) (129.2)
Loss attributable to owners of the parent ($m) (61.3) (7.3)
Weighted average number of ordinary shares – 278,836,216 278,654,909
number1
Adjustment for performance shares, restricted - -
shares, share options and deferred bonus plans
Weighted average number of ordinary shares and 278,836,216 278,654,909
potential ordinary shares
Basic (loss) / earnings per share – cents per share (10.2) 43.7
(from continuing operations)
Diluted loss per share – cents per share (22.0) (2.6)
1 Excluding shares held as treasury shares
Basic (LPS) / EPS excluding impairments
Basic (LPS) / EPS excluding impairment is loss and total comprehensive
expense adjusted for the add back of net impairment/write-off of oil and
gas assets and net ECL/reversal of ECL of receivables divided by weighted
average number of ordinary shares.
2023 2022
Loss attributable to owners of the parent ($m) (61.3) (7.3)
Add back of net impairment/write-off of oil and gas 18.2 201.3
assets
Add back of net ECL/reversal of ECL of receivables 9.9 (8.2)
(Loss) / profit attributable to owners of the (33.2) 185.8
parent ($m) - adjusted
Weighted average number of ordinary shares – number 278,836,216 278,654,909
1
Basic (loss) / earnings per share excluding
impairments – cents per share
(11.9) 66.7
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 2022 81.4 425.1 7.5 514.0
Additions 9.7 - - 9.7
Write-off in the year (note 1) (78.0) - - (78.0)
Other (0.2) - - (0.2)
At 31 December 2022 and 1 12.9 425.1 7.5 445.5
January 2023
Additions 9.1 - - 9.1
Other 0.8 - - 0.8
At 31 December 2023 22.8 425.1 7.5 455.4
Accumulated amortisation and
impairment
At 1 January 2022 - (319.7) (7.5) (327.2)
Amortisation charge for the - (39.2) - (39.2)
period
At 31 December 2022 and 1 - (358.9) (7.5) (366.4)
January 2023
Amortisation charge for the year - (4.3) - (4.3)
At 31 December 2023 - (363.2) (7.5) (370.7)
Net book value
At 1 January 2022 81.4 105.4 - 186.8
At 31 December 2022 12.9 66.2 - 79.1
At 31 December 2023 22.8 61.9 - 84.7
2023 2022
Book value $m $m
Somaliland PSC Exploration 22.8 12.9
Exploration and evaluation assets 22.8 12.9
Tawke capacity building payment waiver 61.9 66.2
Tawke RSA assets 61.9 66.2
10. Property, plant and equipment
Other
Producing assets
assets Total
$m $m $m
Cost
At 1 January 2022 3,117.2 17.1 3,134.3
Net additions 129.1 0.9 130.0
Right-of-use assets (note 20) - (0.4) (0.4)
Other1 5.9 - 5.9
At 31 December 2022 and 1 January 2023 3,252.2 17.6 3,269.8
Additions 58.9 - 58.9
Right-of-use assets (note 20) - (0.3) (0.3)
Other1 2.1 - 2.1
At 31 December 2023 3,313.2 17.3 3,330.5
Accumulated depreciation and impairment
At 1 January 2022 (2,769.2) (12.6) (2,781.8)
Depreciation charge for the year (112.8) (1.6) (114.4)
Impairment (note 1) (125.5) - (125.5)
At 31 December 2022 and 1 January 2023 (3,007.5) (14.2) (3,021.7)
Depreciation charge for the year (42.3) (1.3) (43.6)
Write-off (note 1) (18.7) - (18.7)
At 31 December 2023 (3,068.5) (15.5) (3,084.0)
Net book value
At 1 January 2022 348.0 4.5 352.5
At 31 December 2022 244.7 3.4 248.1
At 31 December 2023 244.7 1.8 246.5
1 Other line includes non-cash asset retirement obligation provision and
share-based payment costs.
2023 2022
Book value $m $m
Tawke PSC Oil production 210.0 199.1
Taq Taq PSC Oil production 34.7 28.8
Sarta PSC Oil production/development - 16.8
Producing assets 244.7 244.7
Sarta PSC was terminated on 1 December 2023 and this resulted in a
reduction in the carrying value to nil and write-off of assets of $18.7
million as of 31 December 2023. Further explanation is provided in note 1.
The sensitivities below provide an indicative impact on net asset value of
a change in netback price, discount rate or production, 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
2023 2022
$m $m
Trade receivables – non-current 66.5 -
Trade receivables – current 26.4 117.0
Other receivables and prepayments 7.6 4.7
100.5 121.7
At 31 December 2023, the Company is owed six months of payments (31
December 2022: five months).
Period when sale made
Not due Overdue Overdue Deferred Total ECL Trade
2023 2022 2020 nominal provision receivables
$m $m $m $m $m $m $m
31
December - 49.3 58.1 - 107.4 (14.5) 92.9
2023
31
December 60.7 - 44.4 16.5 121.6 (4.6) 117.0
2022
2023 2022
Movement on trade receivables in the year
$m $m
Carrying value at 1 January 117.0 158.1
Revenue from contracts with customers 87.6 384.8
Revenue recognised for suspended ORRI - 34.7
Cash for export sales (61.2) (473.3)
Cash for local sales (41.0) -
Offset of payables due to the KRG - (0.1)
Reversal of previous year’s expected credit loss (note 1) 4.6 10.8
Expected credit loss for current year (note 1) (14.5) (4.6)
Capacity building payments 0.2 5.2
Sarta processing fee payments 0.2 1.4
Carrying value at 31 December 92.9 117.0
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 1, 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 1.
Total
$m
Booked nominal balance to be recovered 107.4
Estimated net present value of total cash flows 92.9
Sensitivities/Scenarios
The table below shows the sensitivity of the net present value of the
overdue trade receivables to start and timing of repayment that the company
has used during its ECL assessment. Each scenario has been weighted in
accordance with the management’s expected outcome.
NPV14.0 ($m) Months it takes to recover the nominal amount owed
0 3 6 12 18 24
0 107 105 103 100 97 94
Months until 3 103 102 100 97 94 91
repayment commences 6 99 98 97 94 91 88
9 96 95 94 91 88 85
12 93 92 91 88 85 82
12. Cash and cash equivalents
2023 2022
$m $m
Cash and cash equivalents 363.4 494.6
363.4 494.6
Cash is primarily invested with major international financial institutions,
in US Treasury bills or liquidity funds. $0.6 million (2022: $0.1 million)
of cash is restricted.
13. Trade and other payables
2023 2022
$m $m
Trade payables 23.0 25.3
Other payables 2.2 5.2
Accruals 32.9 53.1
58.1 83.6
Non-current 0.5 1.2
Current 57.6 82.4
58.1 83.6
Current payables are predominantly short-term in nature and there is
minimal difference between contractual cash flows related to the financial
liabilities and their carrying amount. For non-current payables,
liabilities are recognised at discounted fair value using the effective
interest rate. Lease liabilities are included in other payables, further
explanation is provided in note 20.
14. Deferred income
2023 2022
$m $m
Balance at 1 January 13.3 20.5
Interest (non-cash) 1.7 1.0
Royalty income (non-cash) (0.8) (8.2)
Balance at 31 December 14.2 13.3
Non-current (within 1-2 years) 8.2 6.5
Current 6.0 6.8
14.2 13.3
15. Provisions
2023 2022
$m $m
Balance at 1 January 52.2 42.6
Interest unwind 1.8 2.6
Additions 0.7 7.0
Reversals (9.5) -
Balance at 31 December 45.2 52.2
Provisions cover expected decommissioning, abandonment and exit costs
arising from the Company’s assets which are further explained in note 1.
Reversals are related to Sarta and Qara Dagh licences as a result of the
termination of the PSCs.
16. Interest bearing loans and net cash
1 Jan Discount Repurchase Dividend Net other 31 Dec
2023 unwind paid changes1 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
1 Net other changes are free cash flow plus purchase of own shares
At 31 December 2023, the fair value of the $248 million (2022: $274
million) of bonds held by third parties is $236.5 million (2022: $257.6
million).
The Company repurchased $26 million of its existing $274 million senior
unsecured bond at a price equal to 93.5% of the nominal amount.
The bonds maturing in 2025 have two financial covenant maintenance tests:
Financial covenant Test YE 2023 YE 2022
Equity ratio (Total equity/Total assets) > 40% 55% 56%
Minimum liquidity > $30m $363.4m $494.6m
1 Jan Discount Repurchase Dividend Net other 31 Dec
2022 unwind of bond paid changes1 2022
$m $m $m $m $m $m
2025 Bond 9.25% (269.8) (2.5) 5.7 - - (266.6)
(non-current)
Cash 313.7 - (6.0) (47.9) 234.8 494.6
Net cash 43.9 (2.5) (0.3) (47.9) 234.8 228.0
17. Financial Risk Management
Credit risk
Credit risk arises from cash and cash equivalents, trade and other
receivables and other assets. The carrying amount of financial assets
represents the maximum credit exposure. The maximum credit exposure to
credit risk at 31 December was:
2023 2022
$m $m
Trade and other receivables 97.4 119.1
Cash and cash equivalents 363.4 494.6
460.8 613.7
All trade receivables are owed by the KRG. Cash is deposited with major
international financial institutions and the US treasury that are assessed
as appropriate based on, among other things, sovereign risk, CDS pricing
and credit rating.
Liquidity risk
The Company is committed to ensuring it has sufficient liquidity to meet
its payables as they fall due. At 31 December 2023 the Company had cash and
cash equivalents of $363.4 million (2022: $494.6 million).
Oil price risk
The Company’s export revenues are calculated from netback price and local
sales revenues are from a price established on an arms length basis as
further explained in note 1, and a $5/bbl change in average price across
local and export sales would result in a (loss) / profit before tax change
of circa $10 million.
Currency risk
Other than head office costs, substantially all of the Company’s
transactions are denominated and/or reported in US dollars. The exposure to
currency risk is therefore immaterial and accordingly no sensitivity
analysis has been presented.
Interest rate risk
The Company reported borrowings of $243.7 million (2022: $266.6 million) in
the form of a bond maturing in October 2025, with fixed coupon interest
payable of 9.25% on the nominal value of $248.0 million (2022: $274
million). Although interest is fixed on existing debts, whenever the
Company wishes to borrow new debt or refinance existing debt, it will be
exposed to interest rate risk. A 1% increase in interest rate payable on a
balance similar to the existing debts of the Company would result in an
additional cost of circa $2.5 million per annum.
Capital management
The Company manages its capital to ensure that it remains sufficiently
funded to support its business strategy and maximise shareholder value. The
Company’s short-term funding needs are met principally from the cash flows
generated from its operations and available cash of $363.4 million (2022:
$494.6 million).
Financial instruments
All financial assets and liabilities are measured at amortised cost. Due to
their short-term nature except interest bearing loans and non-current
portion of trade receivables, the carrying value of these financial
instruments approximates their fair value. Their carrying values are as
follows:
Financial assets 2023 2022
$m $m
Trade and other receivables 97.4 119.1
Cash and cash equivalents 363.4 494.6
460.8 613.7
Financial liabilities
Trade and other payables 55.9 78.4
Interest bearing loans 243.7 266.6
299.6 345.0
18. Share capital
Total
Ordinary Shares
At 1 January 2022 – fully paid1 280,248,198
At 31 December 2022, 1 January 2023 and 31 December 2023 – 280,248,198
fully paid1
1 Ordinary shares include 845,335 (2022: 845,335) treasury shares. Share
capital includes 2,224,090 (2022: 629,769) of trust shares.
There have been no changes to the authorised share capital since it was
determined to be 10,000,000,000 ordinary shares of £0.10 per share.
19. Dividends
2023 2022
$m $m
Ordinary shares
Final dividend (2023: 12¢ per share, 2022: 12¢ per share) 33.5 33.4
Interim dividend (2023: nil, 2022: 6¢ per share) - 16.7
Total dividends provided for or paid 33.5 50.1
Paid in cash 33.5 47.9
Foreign exchange on dividend paid - 2.2
Total dividends provided for or paid 33.5 50.1
20. Right-of-use assets / Lease liabilities
The Company’s right-of-use assets are related to the offices and included
within property, plant and equipment.
Right-of-use assets
$m
Cost
At 1 January 2022 13.2
Disposals due to terminations (0.4)
At 31 December 2022 and 1 January 2023 12.8
Disposals due to terminations (0.3)
At 31 December 2023 12.5
Accumulated depreciation
At 1 January 2022 (5.1)
Depreciation charge for the period (3.7)
At 31 December 2022 and 1 January 2023 (8.8)
Depreciation charge for the period (2.6)
At 31 December 2023 (11.4)
Net book value
At 1 January 2022 8.1
At 31 December 2022 4.0
At 31 December 2023 1.1
2023 2022
Book value $m $m
Offices 1.1 1.8
Cars - 0.2
Production facility - 2.0
Right-of-use assets 1.1 4.0
The weighted average lessee’s incremental borrowing rate applied to the
lease liabilities. The lease terms vary from one to five years.
Lease liabilities 2023 2022
$m $m
At 1 January (4.1) (8.3)
Additions - -
Disposals due to terminations 0.3 0.5
Payments of lease liabilities 2.8 3.8
Interest expense on lease liabilities (0.1) (0.1)
At 31 December (note 13) (1.1) (4.1)
Included within lease liabilities of $1.1 million (2022: $4.1 million) are
non-current lease liabilities of $0.5 million (2022: $1.2 million). The
identified leases have no significant impact on the Company`s financing,
bond covenants or dividend policy. The Company does not have any residual
value guarantees. The contractual maturities of the Company’s lease
liabilities are as follows:
Less than Between Between Total contractual Carrying
cash flow
1 year 1 - 2 years 2 - 5 years Amount
$m $m $m
$m $m
31 December (0.7) (0.3) (0.2) (1.2) (1.1)
2023
31 December (3.0) (0.7) (0.5) (4.2) (4.1)
2022
21. Share based payments
The Company has five share-based payment plans under which awards are
currently outstanding: performance share plan (2011), performance share
plan (2021), restricted share plan (2011), share option plan (2011), and
deferred bonus plan (2021). The main features of these share plans are set
out below.
Key features PSP (2011) PSP (2021) DBP (2021) RSP (2011) SOP (2011)
Either
Performance Performance Deferred Restricted
shares. The shares or bonus shares. The Market
intention is restricted shares. The intention value
to deliver shares. The intention is to options.
the full intention is is to deliver the Exercise
value of to deliver deliver the full value price is
vested shares the full full value of shares set equal
Form of at no cost to value of of shares at no cost to the
awards the vested at no cost to the average
participant shares at no to the participant share price
(as cost to the participant (as over a
conditional participant (as conditional period of
shares or (as conditional shares or up to 30
nil-cost conditional shares or nil-cost days to
options). shares or nil-cost options). grant.
nil-cost options).
options).
Performance
conditions Performance
will apply. conditions
Awards may or may
granted from not apply.
2017 are Awards Performance Performance Performance
measured granted with conditions conditions conditions
against performance may or may may or may may or may
relative and conditions not apply. not apply. not apply.
Performance absolute are measured For awards For awards For awards
conditions total against granted to granted to granted to
shareholder relative and date, there date, there date, there
return absolute TSR are no are no are no
(‘TSR’) measured performance performance performance
measured against a conditions. conditions. conditions.
against a group of
group of industry
industry peers over a
peers over a three-year
three-year period.
period.
For awards
subject to
performance
conditions,
they will
vest when
the
Remuneration
Awards will Committee
vest when the determines
Remuneration whether the
Committee performance Awards
determines conditions Awards typically Awards
Vesting whether the have been typically vest in typically
period performance met at the vest after tranches vest after
conditions end of the two years. over three three
have been met performance years. years.
at the end of period. For
the awards that
performance are not
period. subject to
performance
conditions,
awards
typically
vest in
tranches
over three
years.
Provision
Provision of of
additional additional
cash/shares cash/shares
to reflect to reflect
Provision of dividends dividends Provision Provision
additional over the over the of of
cash/shares vesting vesting additional additional
to reflect period and period and cash/shares cash/shares
Dividend dividends the period the period to reflect to reflect
equivalents over the where the where the dividends dividends
vesting options have options over the over the
period may or vested and have vested vesting vesting
may not have not yet and have period may period may
apply. been not yet or may not or may not
exercised been apply. apply.
(where exercised
applicable) (where
may or may applicable)
not apply. may or may
not apply.
In 2023, awards were made under the performance share plan only. The
numbers of outstanding shares as at 31 December 2023 are set out below:
Weighted
Share awards Share awards avg.
with without Share exercise
performance performance options price of
conditions conditions share
options
Outstanding at 1 January 2022 9,508,167 1,415,816 85,232 817p
Granted during the year 2,549,151 505,645 - -
Dividend equivalents 710,605 115,753 - -
Forfeited during the year (2,248,542) - - -
Lapsed during the year (2,555,194) (125,326) (33,967) 753p
Exercised during the year (11,647) (883,603) - -
Outstanding at 31 Dec 2022 7,952,540 1,028,285 51,265 858p
and 1 Jan 2023
Granted during the year 2,961,900 540,834 - -
Dividend equivalents 607,589 91,973 - -
Forfeited during the year (3,805,594) - - -
Lapsed during the year (191,374) (191,768) (26,443) 767p
Exercised during the year (64,085) (366,082) (6,370) 742p
Outstanding at 31 December 7,460,976 1,103,242 18,452 1,046p
2023
The exercise price for share options outstanding at the end of the period
is 1,046.00p.
Fair value of awards granted during the year has been measured by use of
the Monte-Carlo pricing model. The model takes into account assumptions
regarding expected volatility, expected dividends and expected time to
exercise. Expected volatility was also analysed with the historical
volatility of FTSE-listed oil and gas producers over the three years prior
to the date of grant. The expected dividend assumption was set at 0%. The
risk-free interest rate incorporated into the model is based on the term
structure of UK Government zero coupon bonds. The inputs into the fair
value calculation for PSP awards granted in 2023 and fair values per share
using the model were as follows:
PSP (without PSP PSP (without PSP
condition) condition)
06/04/2023 12/09/2023
06/04/2023 12/09/2023
Share price at grant date 124p 124p 82p 82p
Fair value on measurement 124p 80p 82p 43p
date
Expected life (years) 1-3 1-3 1-3 1-3
Expected dividends - - - -
Risk-free interest rate 3.25% 3.25% 4.73% 4.73%
Expected volatility 47.21% 47.21% 42.21% 42.21%
Share price at balance 71p 71p 71p 71p
sheet date
Change in share price
between grant date and 31 -43% -43% -13% -13%
December 2023
The weighted average fair value for PSP awards (without condition) granted
in 2023 is 121p and for PSP awards granted in 2023 is 80p.
The inputs into the fair value calculation for PSP awards granted in 2022
and fair values per share using the model were as follows:
PSP (without PSP PSP (without PSP
condition) condition)
04/04/2022 08/09/2022
04/04/2022 08/09/2022
Share price at grant date 186p 186p 137p 137p
Fair value on measurement 186p 127p 137p 82p
date
Expected life (years) 1-3 1-3 1-3 1-3
Expected dividends - - - -
Risk-free interest rate 1.41% 1.41% 3.04% 3.04%
Expected volatility 39.76% 39.76% 41.42% 41.42%
Share price at balance 125p 125p 125p 125p
sheet date
Change in share price
between grant date and 31 -33% -33% -9% -9%
December 2022
The weighted average fair value for PSP awards (without condition) granted
in 2022 is 164p and for PSP awards granted in 2022 is 124p.
Total share-based payment charge for the year was $3.7 million (2022: $4.1
million).
22. 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.
23. Related parties
The directors have identified related parties of the Company under IAS 24
as being: the shareholders; members of the Board; and members of the
executive committee, together with the families and companies, associates,
investments and associates controlled by or affiliated with each of them.
The compensation of key management personnel including the directors of the
Company is as follows:
2023 2022
$m $m
Board remuneration 0.7 0.8
Key management emoluments and short-term benefits 4.1 6.0
Share-related awards 2.7 1.0
7.5 7.8
There have been no changes in related parties since last year and no
related party transactions that had a material effect on financial position
or performance in the year.
24. Events occurring after the reporting period
The London-seated international arbitration hearing (factual and expert
evidence) which includes Genel’s claim for substantial compensation from
the KRG following the termination of the Miran and Bina Bawi PSCs ended on
1 March 2024. The timing of the result is uncertain but is expected by the
end of 2024 following the Parties making closing written submissions in
April 2024 and reply written submissions in May 2024.
25. Subsidiaries and joint arrangements
The Company has four joint arrangements in relation to its producing assets
Taq Taq, Tawke, Sarta and pre-production asset Qara Dagh PSC. The Company
holds 44% working interest in Taq Taq PSC and owns 55% of Taq Taq Operating
Company Limited. The Company holds 25% working interest in Tawke PSC which
is operated by DNO ASA.
For the period ended 31 December 2023 the principal subsidiaries of the
Company were the following:
Entity name Country of Ownership %
Incorporation (ordinary shares)
Barrus Petroleum Cote D'Ivoire Sarl1 Cote d'Ivoire 100
Barrus Petroleum Limited2 Isle of Man 100
Genel Energy Africa Exploration UK 100
Limited3
Genel Energy Finance 4 plc3 UK 100
Genel Energy Gas Company Limited4 Jersey 100
Genel Energy Holding Company Limited4 Jersey 100
Genel Energy International Limited5 Anguilla 100
Genel Energy Miran Bina Bawi Limited3 UK 100
Genel Energy Morocco Limited3 UK 100
Genel Energy No. 6 Limited3 UK 100
Genel Energy Petroleum Services UK 100
Limited3
Genel Energy Qara Dagh Limited3 UK 100
Genel Energy Sarta Limited3 UK 100
Genel Energy Somaliland Limited3 UK 100
Genel Energy UK Services Limited3 UK 100
Genel Energy Yӧnetim Hizmetleri A.Ş.6 Turkey 100
Taq Taq Drilling Company Limited7 BVI 55
Taq Taq Operating Company Limited7 BVI 55
1 Registered office is 7 Boulevard Latrille Cocody, 25 B.P. 945 Abidjan 25,
Cote d'Ivoire
2 Registered office is 6 Hope Street, Castletown, IM9 1AS, Isle of Man
3 Registered office is Fifth Floor, 36 Broadway, Victoria, London, SW1H
0BH, United Kingdom
4 Registered office is 26 New Street, St Helier, JE2 3RA, Jersey
5 Registered office is PO Box 1338, Maico Building, The Valley, Anguilla
6 Registered office is Vadi Istanbul 1 B Block, Ayazaga Mahallesi,
Azerbaycan Caddesi, No:3 Floor: 18, 34396, Sariyer, Istanbul, Turkey
7 Registered office is Kingston Chambers, P.O. Box 173, Road Town, Tortola,
VG1110, British Virgin Islands
26. Annual report
Copies of the 2023 annual report will be despatched to shareholders in
April 2024 and will also be available from the Company’s registered office
at 26 New Street, St Helier, Jersey, JE2 3RA and at the Company’s website –
2 www.genelenergy.com.
27. Statutory financial statements
The financial information for the year ended 31 December 2023 contained in
this preliminary announcement has been audited and was approved by the
Board on 25 March 2024. The financial information in this statement does
not constitute the Company's statutory financial statements for the years
ended 31 December 2023 or 2022. The financial information for 2023 and 2022
is derived from the statutory financial statements for 2022, which have
been delivered to the Registrar of Companies, and 2023, which will be
delivered to the Registrar of Companies and issued to shareholders in April
2024. The auditors have reported on the 2023 and 2022 financial statements;
their report was unqualified and did not include a reference to any matters
to which the auditors drew attention by way of emphasis without qualifying
their report. The statutory financial statements for 2023 are prepared in
accordance with International Financial Reporting Standards (IFRS) as
adopted for use in the European Union. The accounting policies (that comply
with IFRS) used by Genel Energy plc are consistent with those set out in
the 2022 annual report.
═══════════════════════════════════════════════════════════════════════════
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: FR
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 311832
EQS News ID: 1866825
End of Announcement EQS News Service
══════════════════════════════════════════════════════════════════════════
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