REG-Genel Energy PLC Genel Energy PLC: Full-Year Results
22/03/2023 07:15
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Genel Energy PLC (GENL)
Genel Energy PLC: Full-Year Results
22-March-2023 / 07:00 GMT/BST
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22 March 2023
Genel Energy plc
Audited results for the year ended 31 December 2022
Genel Energy plc (‘Genel’ or ‘the Company’) announces its audited results
for the year ended 31 December 2022.
Paul Weir, Chief Executive of Genel, said:
“Our production business generated record cash flow in 2022, building our
significant financial resources and resulting in a net cash balance at the
end of the year of over $200 million. The Company now has an exceptional
opportunity to deploy its financial resources carefully to add new assets
and grow and diversify our production business in order to improve the
resilience and extend the line of sight on the funding of our established
dividend programme.
Our capital allocation decisions for 2023 and beyond will be centred around
that material, sustainable and progressive dividend programme, while
protecting and maintaining the strength of our balance sheet. Our core
business remains robust, funding our dividend from free cash flow in the
mid-term and there is significant potential still remaining in the
portfolio. We have an extremely busy 18 months ahead that carries much
potential, and we have a highly capable team in place that is fully focused
on delivering on that potential.”
Results summary ($ million unless stated)
2022 2021
Average Brent oil price ($/bbl) 101 71
Production (bopd, working interest) 30,150 31,710
Revenue 432.7 334.9
EBITDAX1 361.6 275.1
Depreciation and amortisation (149.2) (172.8)
Exploration expense (1.0) -
Net impairment/write-off of oil and gas assets (201.3) (403.2)
Net reversal of impairment of receivables 8.2 24.1
Operating profit / (loss) 18.3 (276.8)
Cash flow from operating activities 412.4 228.1
Capital expenditure 143.1 163.7
Free cash flow2 234.8 85.9
Cash 494.6 313.7
Total debt 274.0 280.0
Net cash3 228.0 43.9
Basic LPS (¢ per share) (2.6) (111.4)
EPS excluding impairments4 66.7 25.8
Dividends declared relating to financial year (¢ per 18 18
share)
1. EBITDAX is operating profit / (loss) adjusted for the add back of
depreciation and amortisation, impairment/write-off of oil and gas
assets and net reversal of impairment of receivables
2. Free cash flow is reconciled on page 10
3. Reported cash less IFRS debt (page 10)
4. 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 reversal of impairment of receivables divided by
weighted average number of ordinary shares
Highlights
• Zero lost time incidents in 2022, with over three million hours now
worked since the last incident
• Another year of active drilling on the Tawke PSC and consistent
reservoir performance resulted in average daily working interest
production of 30,150 bopd (2021: 31,710 bopd)
• Record free cash flow in 2022
◦ High oil price and recovery of receivables helped drive free cash
flow of $235 million (2021: $86 million)
◦ Investment in production and appraisal at Sarta resulted in
capital expenditure of $143 million (2021: $164 million)
• Disappointing results at Sarta resulted in a reduction in reserves and
an impairment of $126 million, with expiry of the Qara Dagh licence
resulting in a write off of $78 million
• Strong balance sheet provides opportunity to acquire and develop new
assets
◦ Significantly increased financial resources of $495 million ($314
million at 31 December 2021)
◦ Net cash under IFRS of $228 million at 31 December 2022 ($44
million at 31 December 2021)
◦ Total debt of $274 million at 31 December 2022 ($280 million at 31
December 2021)
• Committed material, sustainable, and progressive dividend programme
well established
◦ Dividends paid in 2022 increased by 13% to 18¢ per share (2021:
16¢ per share) a total distribution of $50 million
• Carbon intensity of 17.6 kgCO2e/bbl for Scope 1 and 2 emissions in 2022
(2021: 16 kgCO2e/bbl), below the global oil and gas industry average of
19 kgCO2e/boe
Outlook
• Committed dividend funded by free cash flow for medium-term
◦ The Board is recommending a final dividend of 12¢ per share (2022:
12¢ per share), a distribution of $33.5 million
• Established dividend programme frames business and capital allocation
decisions:
◦ Production guidance unchanged at 27-29,000 bopd
◦ 2023 capital expenditure expected to be between $100 million and
$125 million
◦ Progress towards drilling a well in Somaliland
◦ Genel continues to actively screen and work up opportunities to
invest our cash to extend the line of sight on resilient cash
flows that support our dividend programme into the long-term
• 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 regarding Genel’s claim for
substantial compensation from the KRG following the termination of the
Miran and Bina Bawi PSCs is progressing. The trial is scheduled for
February 2024
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 Wednesday 22 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
In the past six months we have simplified and refined our strategic
priorities and put the funding of our established dividend programme at the
heart of our business model. This is the lens through which we assess
capital allocation decisions.
Building and managing a portfolio to support the dividend over the
long-term is our clear focus. That work requires both judicious management
of our existing opportunities already within the business, together with
the objective of adding new assets that expand and diversify our asset base
and, importantly, improve both the cash generation of the business and the
resulting investor returns.
We have a very strong balance sheet with $495 million of cash, net cash of
$228 million, at the end of 2022 and no debt maturity until 2025. We have
achieved this position through a combination of factors. Disciplined
capital allocation combined with excellent Tawke production results,
recovery of old debts and, of course, the high oil price in 2022 have all
resulted in exceptional cash generation for Genel, despite only receiving
10 payments from the Kurdistan Regional Government.
We had hoped that the Sarta development would have been a major contributor
to our cash generation, but appraisal well results in 2022 were
disappointing. Further investment will only take place now if we can be
confident of positive returns and profitability, consistent with our focus
on cost control and carefully considered expenditure.
A clear focus
The business is now determined to add new revenue streams that build a
stronger business and replace the cash generation in 2022 that came from
historic debts owed by the KRG.
We have an established dividend programme that, following approval of the
proposed final dividend for 2022, will have returned over $200 million to
shareholders since 2019. Delivering on this dividend programme while
increasing the value of the business is our primary objective to deliver
long-term shareholder returns, and the business is progressing with a real
clarity of purpose.
A strong balance sheet, including liquidity of almost half a billion
dollars, provides us with a tremendous opportunity. We are determined to
use it in order to add shareholder value through strong operational
delivery and properly considered investment.
We also continue to work diligently towards arbitration regarding our claim
for substantial compensation from the KRG following the termination of the
Miran and Bina Bawi PSCs, with the trial scheduled for February 2024.
Adding to our production business
Growing our portfolio through the addition of the right assets is key. We
have a highly competent and dedicated team in place assessing a great many
opportunities in a disciplined and systematic manner. We only progress
opportunities that deliver the right outcomes when subjected to multiple
scenario analysis, that ultimately provide support for our dividend
programme and at the same time maintain business resilience and balance
sheet strength. Genel’s significant cash position does not distract us from
our focus on cost discipline and risk mitigation.
Genel has a robust production business and a free cash flow projection that
covers dividend payments in the medium-term. Doing deals takes time and
doing the right deal takes even longer, but we are confident in our ability
to take advantage of the opportunities that are out there to deliver for
our shareholders.
Organic reserves replacement opportunities
As we continue to enhance the business, we are also progressing exciting
opportunities within our existing portfolio. The Somaliland opportunity is
frontier exploration, with all of the challenges that entails, but rare in
terms of scale and potential. In a success case, there is a clear route to
market through existing port facilities and this opens up the tantalising
prospect of creating shareholder value in a region where our activities can
also have a hugely positive impact on the surrounding society.
We are attempting to replicate the Somaliland farm-out success in Morocco,
seeking a partner to drill a well in the Lagzira block, with high-graded
material prospects. Both of these exploration opportunities support our aim
of adding low-cost and large-scale assets to our portfolio to provide
resilient, diversified, and value accretive cash generation that funds our
dividend programme and offer catalysts to deliver shareholder value.
Making a positive difference
As all of these opportunities unfold, Genel sees the need to have a
positive impact in the areas where it is present as being an essential part
of business success. In 2022 we marked 20 years of operations in KRI by
launching a number of social initiatives, the centre of which was our
Genel20 Scholars programme.
This was an appropriate way to mark our 20 years of operations in KRI, a
period which has seen an entire industry develop, thousands of jobs
created, and more than $20 billion generated for the KRG. Our social
activities in Somaliland will now begin to ramp up as our operational
activities increase there and, as an Anglo-Turkish company, we are of
course providing support following the horrendous impact of the recent
earthquakes.
Our work on emissions continues and we are very pleased that our emissions
intensity remains below the industry average at 17.6kg CO2/bbl. We have
been very proud to work with our partner DNO on Kurdistan’s first gas
reinjection project, which has captured 1.2 million tonnes of CO2e since
its inception in 2020. Not only has this facility greatly reduced flaring
at Tawke, but it has also led to a marked improvement in field performance.
On a smaller scale, our pilot solar powered well site at the Sarta-1 well
pad has saved almost nine tonnes of CO2 emissions there and established a
new standard design for Genel well pads. As we seek to diversify our
business, we will retain our clear commitment to being a socially
responsible contributor to the global energy mix.
Outlook
The production base that the Tawke licence provides is set to deliver free
cash flow that supports the progression of business catalysts and payment
of our material dividend. We have a firm commitment to invest our cash to
add shareholder value, and both the means and determination to do it. Our
team is dedicated to delivering strong future cash flow and shareholder
returns.
OPERATING REVIEW
Reserves and resources development
Genel's proven (1P) and proven plus probable (2P) net working interest
reserves totalled 69 MMbbls (31 December 2021: 63 MMbbls) and 92 MMbbls (31
December 2021: 104 MMbbls) respectively at the end of 2022.
Ongoing positive performance at the Tawke PSC has boosted the 1P number,
and helped to offset the reduction in 2P reserves at Sarta.
Remaining reserves Resources (MMboe)
(MMbbls)
Contingent Prospective
1P 2P 1C 2C Best
Gross Net Gross Net Gross Net Gross Net Gross Net
31 December 2021 238 63 391 104 163 49 400 122 5,443 3,274
Production (42) (11) (42) (11) - - - - - -
Acquisitions and - - - - (13) (5) (55) (22) (585) (234)
disposals
Extensions and - - - - - - - - - -
discoveries
New developments - - - - - - - - - -
Revision of
previous 71 17 0 (1) (113) (33) (216) (63) (136) (34)
estimates
31 December 2022 267 69 349 92 37 11 129 36 4,722 3,006
Production
Production averaged 30,150 bopd in 2022, driven by the ongoing positive
performance of the Tawke licence.
PRODUCING ASSETS
Tawke PSC (25% working interest)
Gross production at the Tawke licence averaged 107,090 bopd in 2022, of
which the Peshkabir field contributed 62,040 bopd, and the Tawke field
45,050 bopd.
By the end of 2022 the Tawke field had delivered three consecutive quarters
of production growth, the first quarterly increases since 2015, as new
wells were drilled, workovers conducted on existing ones and gas injection
stepped up to counter natural field decline. In 2022, the field partners
also completed the $25 million expansion of the Peshkabir-to-Tawke gas
project, Kurdistan’s only gas capture and enhanced recovery injection
project. Since 2020, the project has captured 1.2 million tonnes of CO2e
through avoided flaring.
Sarta (30% working interest, operator)
Gross production averaged 4,710 bopd in 2022. Following the disappointing
appraisal results and pilot production, Genel’s focus is on making ongoing
production from Sarta profitable, with any further capital investment
contingent on both licence profitability and the extent to which there can
be confidence that such investment can add cash generative production.
Taq Taq (44% working interest, joint operator)
Gross production at Taq Taq averaged 4,490 bopd in 2022. Activity in 2023
is expected to include one sidetrack well targeting the Upper Shiranish
formation.
PRE-PRODUCTION ASSETS
Somaliland
Preparation continues for the drilling of the Toosan-1 well on the highly
prospective SL10B13 block (51% working interest and operator).
The Toosan prospect contains stacked Mesozoic reservoir objectives, with
multiple individual prospective resource estimates each ranging from 100 to
200 MMbbls.
Environmental and social impact assessments are continuing, and community
engagement efforts are ramping up. Tendering for the rig and well services
is ongoing. Genel continues to target a spud date in the next 12-16 months,
acknowledging the challenges of operating in such a frontier area with
limited existing infrastructure.
In Q3 2022, samples from a water well drilled by the Ministry of Water
Resources Development near a village on the Odewayne licence (50% working
interest and operator) indicated trace hydrocarbons. Traces of oil have
historically been found in surface seepages across Somaliland, and Genel is
set to obtain a more meaningful sample in 2023, helping to define any
future work programme on the licence.
Morocco (Lagzira block - 75% working interest and operator)
The Petroleum Agreement and Association Contract was signed with ONHYM in
February for a full eight-year exploration term (in three exploration
periods), with attractive fiscal terms.
The Lagzira block (formerly Sidi Moussa) is a large offshore licence, in
water depths of 200-1,200 metres, with a proven petroleum system following
Genel’s 2014 SM-1 well which recovered oil from Upper and Middle Jurassic
reservoirs.
3D seismic acquired in 2018 resulted in a significant uplift and
improvement in subsurface imaging and prospects have been high-graded, and
the new data has highlighted new plays and provided an enhanced
understanding of the SM-1 well result.
In total, 18 prospects and leads have been identified, with over 2.5 Bboe
mean recoverable resource potential with individual prospects estimated at
100-700 MMbbls each.
Genel has launched a process to find a partner to take a material equity
position and jointly pursue the exploration programme in the block, with
the opportunity to drill and test one of the high-graded prospects.
FINANCIAL REVIEW
(all figures $ million) FY 2022 FY 2021
Brent average oil price $101/bbl $71/bbl
Revenue 432.7 334.9
Production costs (51.1) (45.9)
Cost recovered production asset capex (85.9) (49.9)
Production business net income after cost recovered capex 295.7 239.1
G&A (excl. non-cash) (19.2) (12.4)
Net cash interest1 (19.2) (26.1)
Working capital (9.7) (19.7)
Payments for deferred receivables 94.4 35.1
Changes to payment days2 (44.4) (65.0)
Free cash flow before investment in growth 297.6 151.0
Pre-production capex (57.2) (88.6)
Working capital and other (5.6) 23.5
Free cash flow 234.8 85.9
Dividend paid (47.9) (44.4)
Other - (1.3)
Bond repayment (6.0) (81.0)
Net change in cash 180.9 (40.8)
Cash 494.6 313.7
Amounts owed for deferred receivables 16.5 114.6
1 Net cash interest is bond interest payable less bank interest income (see
note 5)
2 At year-end the KRG owed five months of sales, adversely impacting free
cash flow for the year by $44.4 million (2021: $65.0 million)
Strategy focused on our dividend
In 2022, we refocused our business towards delivering shareholder returns
primarily through our established dividend programme. The dividend
programme has three key pillars:
• Material: it is competitive with the ordinary dividend of peers
• Sustainable: it is repeatable and reliable
• Progressive: it increases as the repeatable cash generation of the
business grows
That dividend programme has paid $177 million to shareholders since
inception in 2019.
Funding the dividend programme is the frame that we apply to our capital
allocation decisions and the type of assets that we want in our portfolio,
with a focus on acquiring or developing low-cost, cash generative assets to
build a business with consistent, long-dated, diversified, and resilient
cash generation.
Total dividends paid in 2022 amounted to $50 million (2021: $44 million),
representing 18¢ per share (2021: 16¢ per share).
The Board has now approved the retention of the final dividend at 12¢ per
share, in addition to the interim dividend of 6¢ per share that was paid in
October 2022.
The payment timetable for the final dividend is below:
• Ex-dividend date: 20 April 2023
• Record date: 21 April 2023
• Annual General Meeting: 11 May 2023
• Payment date: 19 May 2023
2022 financial priorities
The table below summarises our progress against the 2022 financial
priorities of the Company as set out at our 2021 results.
2022 financial priorities Progress
• Maintain our financial strength and • Material cash generation
put that financial strength to work • Material recovery of deferred
through investing in growth receivables
opportunities • Net cash increased
• Sarta appraisal delivered
• Maximise NPV by prioritising highest • Focus of capital allocation
value investment in assets with on cash generative investment
ongoing or near-term cash and value in the Tawke PSC
generation
• Deliver 2022 work programme on time • Work programme activity
and on budget delivered, capital
expenditure guidance
maintained
• Continue to focus on growing our • Allocation of capital to
income streams and cash generation, Sarta appraisal programmes
bringing greater resilience and and progression of Somaliland
diversity to the business and • Morocco farm-out process
supporting our sustainable and underway
progressive dividend programme • Continue to explore
value-accretive additions
Outlook and financial priorities for 2023
We carry significant liquidity and are net cash positive with our outlook
cash generation expected to cover our established dividend in the
medium-term.
The focus of the business is now on investing capital to add income streams
and drive the long-term cash generation profile of the business, building a
stronger Company and providing shareholders with a clear line of sight for
a long-term and ultimately progressive dividend. We continue to see a
long-term oil price that is supportive to our business, and coupled with
our focus on the right barrels in the right locations, means we are
committed to our business model and remaining resilient to volatility and
the challenges faced by the sector.
For 2023, our financial priorities are the following:
• Maintain business resilience and balance sheet strength
• Put our significant cash balance to work, earning appropriate returns
to deliver value to shareholders primarily through our dividend
programme and diversify our cash generation
• Deliver the 2023 work programme on time and on budget, and continue
simplification of the business with a focus on optimisation and cost
control and investment in business improvement
Financial results for the year
Income statement
(all figures $ million) FY 2022 FY 2021
Brent average oil price $101/bbl $71/bbl
Production (bopd, working interest) 30,150 31,710
Profit oil 149.2 120.6
Cost oil 141.1 100.4
Override royalty 142.4 113.9
Revenue 432.7 334.9
Production costs (51.1) (45.9)
G&A (excl. depreciation and amortisation) (20.0) (13.9)
EBITDAX 361.6 275.1
Depreciation and amortisation (149.2) (172.8)
Exploration expense (1.0) -
Net impairment / write-off of oil and gas assets (201.3) (403.2)
Net reversal of impairment of receivables 8.2 24.1
Net finance expense (25.4) (31.0)
Income tax expense (0.2) (0.2)
Loss (7.3) (308.0)
With our predictable production over 30,000 bopd (2021: 31,710 bopd) the
40% increase in oil price resulted in a significant increase in revenue to
$433 million from $335 million last year.
Production costs of $51 million increased from the prior year (2021: $46
million), with cost per barrel $4.6/bbl in 2022 (2021: $4.0/bbl),
principally caused by higher operating costs per barrel at Sarta.
Corporate cash costs were $18 million (2021: $12 million), with an
additional $5 million incurred on legal spend.
The increase in revenue resulted in a similar increase to EBITDAX, which
was $362 million (2021: $275 million). EBITDAX is presented in order to
illustrate the cash 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 $110 million (2021: $115 million) and Tawke intangibles
amortisation of $39 million (2021: $58 million) decreased due to lower
production and the completion of amortisation of the Tawke override
intangible asset in July 2022.
The Company has reported a write-off expense of $78 million relating to
Qara Dagh, and an impairment expense of $126 million relating to Sarta. A
net impairment reversal of $8 million has been recognised relating to
receivables. Further explanation is provided in note 1 to the financial
statements.
Interest income of $7 million (2021: $0.2 million) has significantly
increased as a result of increase in interest rates, in turn reducing our
cost of debt, which is helpful as we carefully view acquisition
opportunities. Bond interest expense of $26 million (2021: $26 million) was
in line with previous year. Other finance expense of $6 million (2021: $5
million) related to non-cash discount unwinding on provisions.
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
(2022: $0.2 million, 2021: $0.2 million).
Capital expenditure
Key to our business model remains financial discipline, with investment
focused on cash generation and in turn free cash flow and the support of
our dividend. Capital expenditure was reduced to $143 million (2021: $164
million), with spend on production assets of $133 million, and
pre-production assets of $10 million.
(all figures $ million) FY 2022 FY 2021
Cost recovered production capex 85.9 49.9
Pre-production capex – oil 47.5 55.4
Pre-production capex – gas - 5.0
Other exploration and appraisal capex 9.7 53.4
Capital expenditure 143.1 163.7
Cash flow, cash, net cash and debt
Gross proceeds received totalled $473 million (2021: $281 million), of
which $124 million (2021: $73 million) was received for the override
royalty and $94 million for receivable recovery (2021: $35 million).
This was despite the receipt of 10 payments from the KRG in 2022, instead
of the expected 12. Genel continues to work with other IOCs in the KRI and
the KRG to deliver timely payments, which in turn enable ongoing investment
in Kurdistan. Expenditure in the KRI will be appropriate to the payment
environment.
(all figures $ million) FY 2022 FY 2021
Brent average oil price $101/bbl $71/bbl
EBITDAX 361.6 275.1
Working capital 50.8 (47.0)
Operating cash flow 412.4 228.1
Producing asset cost recovered capex (77.8) (46.9)
Development capex (50.4) (41.6)
Exploration and appraisal capex (20.0) (24.1)
Interest and other (29.4) (29.6)
Free cash flow 234.8 85.9
Free cash flow is presented in order to illustrate the free cash generated
for equity. Free cash flow was $235 million (2021: $86 million) with an
overall increase mainly as a result of higher Brent.
(all figures $ million) FY 2022 FY 2021
Free cash flow 234.8 85.9
Dividend paid (47.9) (44.4)
Other - (1.3)
Bond repayment (6.0) (81.0)
Net change in cash 180.9 (40.8)
Opening cash 313.7 354.5
Closing cash 494.6 313.7
Debt reported under IFRS (266.6) (269.8)
Net cash 228.0 43.9
The bonds maturing in 2025 have two financial covenant maintenance tests:
Financial covenant Test YE 2022
Equity ratio (Total equity/Total assets) > 40% 56%
Minimum liquidity > $30m $495m
Net assets
Net assets at 31 December 2022 were $528 million (31 December 2021: $581
million) and consist primarily of oil and gas assets of $327 million (31
December 2021: $539 million), trade receivables of $117 million (31
December 2021: $158 million) and net cash of $228 million (31 December
2021: $44 million).
Liquidity / cash counterparty risk management
The Company monitors its cash position, cash forecasts and liquidity on a
regular basis. The Company holds surplus cash in treasury bills or on time
deposits with a number of major financial institutions. Suitability of
banks is assessed using a combination of sovereign risk, credit default
swap pricing and credit rating.
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 period ended 31 December 2022 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 2022
2022 2021
Note $m $m
Revenue 2 432.7 334.9
Production costs 3 (51.1) (45.9)
Depreciation and amortisation of oil assets 3 (149.1) (172.7)
Gross profit 232.5 116.3
Exploration expense 3 (1.0) -
Net write-off of intangible assets 1,3,8 (75.8) (403.2)
Impairment of property, plant and equipment 3,9 (125.5) -
Net reversal of impairment of receivables 3,10 8.2 24.1
General and administrative costs 3 (20.1) (14.0)
Operating profit / (loss) 18.3 (276.8)
Operating profit / (loss) is comprised of:
EBITDAX 361.6 275.1
Depreciation and amortisation 3 (149.2) (172.8)
Exploration expense 3 (1.0) -
Net write-off of intangible assets 3,8 (75.8) (403.2)
Impairment of property, plant and equipment 3,9 (125.5) -
Net reversal of impairment of receivables 3,10 8.2 24.1
Finance income 5 6.7 0.2
Bond interest expense 5 (25.9) (26.3)
Other finance expense 5 (6.2) (4.9)
Loss before income tax (7.1) (307.8)
Income tax expense 6 (0.2) (0.2)
Loss and total comprehensive expense (7.3) (308.0)
Attributable to:
Owners of the parent (7.3) (308.0)
(7.3) (308.0)
Earnings / (Loss) per ordinary share ¢ ¢
Basic 7 (2.6) (111.4)
Diluted 7 (2.6) (111.4)
EPS excluding impairments1 66.7 25.8
1EPS 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
reversal of impairment of receivables divided by weighted average number of
ordinary shares
Consolidated balance sheet
At 31 December 2022
2022 2021
Note $m $m
Assets
Non-current assets
Intangible assets 8 79.1 186.8
Property, plant and equipment 9,19 248.1 352.5
Trade and other receivables 10 - 18.4
327.2 557.7
Current assets
Trade and other receivables 10 121.7 145.0
Cash and cash equivalents 11 494.6 313.7
616.3 458.7
Total assets 943.5 1,016.4
Liabilities
Non-current liabilities
Trade and other payables 12,19 (1.2) (4.9)
Deferred income 13 (6.5) (14.0)
Provisions 14 (52.2) (42.6)
Interest bearing loans 15 (266.6) (269.8)
(326.5) (331.3)
Current liabilities
Trade and other payables 12,19 (82.4) (97.5)
Deferred income 13 (6.8) (6.5)
(89.2) (104.0)
Total liabilities (415.7) (435.3)
Net assets 527.8 581.1
Owners of the parent
Share capital 17 43.8 43.8
Share premium account 3,897.4 3,947.5
Accumulated losses (3,413.4) (3,410.2)
Total equity 527.8 581.1
Consolidated statement of changes in equity
For the year ended 31 December 2022
Share Share Accumulated Total
capital premium losses equity
$m $m $m $m
Note
At 1 January 2021 43.8 3,991.9 (3,105.9) 929.8
Loss and total comprehensive - - (308.0) (308.0)
expense
Contributions by and
distributions to owners
Share-based payments 20 - - 5.0 5.0
Purchase of shares for - - (1.3) (1.3)
employee share awards
Dividends provided for or 18 - (44.4) - (44.4)
paid1
At 31 December 2021 and 1 43.8 3,947.5 (3,410.2) 581.1
January 2022
Loss and total comprehensive - - (7.3) (7.3)
expense
Contributions by and
distributions to owners
Share-based payments 20 - - 4.1 4.1
Dividends provided for or 18 - (50.1) - (50.1)
paid1
At 31 December 2022 43.8 3,897.4 (3,413.4) 527.8
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 2022
Note 2022 2021
$m $m
Cash flows from operating activities
Loss for the year (7.3) (308.0)
Adjustments for:
Net finance expense 5 25.4 31.0
Taxation 6 0.2 0.2
Depreciation and amortisation 3 152.0 175.3
Exploration expense 3 1.0 -
Net impairments, write-offs 3 193.1 379.1
Other non-cash items (royalty income and (7.4) (5.4)
share-based cost)
Changes in working capital:
Decrease / (Increase) in trade receivables 47.2 (42.4)
(Increase) in other receivables - (0.4)
Increase / (Decrease) in trade and other payables 1.7 (1.4)
Cash generated from operations 405.9 228.0
Interest received 5 6.7 0.2
Taxation paid (0.2) (0.1)
Net cash generated from operating activities 412.4 228.1
Cash flows from investing activities
Net payments of intangible assets (20.0) (24.1)
Net payments of property, plant and equipment (128.2) (88.5)
Net cash used in investing activities (148.2) (112.6)
Cash flows from financing activities
Dividends paid to company’s shareholders 18 (47.9) (44.4)
Purchase of own shares - (1.3)
Bond repayment 15 (6.0) (81.0)
Lease payments (3.8) (3.3)
Interest paid (25.6) (26.3)
Net cash used in financing activities (83.3) (156.3)
Net increase / (decrease) in cash and cash 180.9 (40.8)
equivalents
Cash and cash equivalents at 1 January 11 313.7 354.5
Cash and cash equivalents at 31 December 11 494.6 313.7
Notes to the consolidated financial statements
1. Summary of significant 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 12 Castle
Street, St Helier, Jersey, JE2 3RT.
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 $494.6 million, with no debt maturing
until the second half of 2025 and headroom on both the equity ratio and
minimum liquidity financial covenants. The strength of the balance sheet is
expected to be enhanced through 2023.
The Company’s low-cost assets and flexibility on commitment of capital mean
that it is resilient to low oil prices, with the only customer, the KRG,
demonstrating its ability to pay in times of financial stress. There is
considered to be sufficient cash in the business and still more room for
flexibility if needed given the nature of the discretionary capex planned.
Longer term, our low-cost, low-carbon assets, located in a region where oil
revenues provide a material proportion of funding to the government and its
people means that we are well positioned to address the appropriate
challenges and demands that climate change initiatives are bringing to the
sector. Given the footprint and the benefit to society generated, we see
our portfolio as being well-positioned for a future of fewer and better
natural resources projects, while the global energy mix continues to
require hydrocarbons.
As a result, the Directors have assessed that the Company’s forecast
liquidity provides adequate headroom over its forecast expenditure for the
12 months following the signing of the annual report for the period ended
31 December 2022 and consequently that the Company is considered a going
concern.
Foreign currency
Foreign currency transactions are translated into the functional currency
of the relevant entity using the exchange rates prevailing at the dates of
the transactions or at the balance sheet date where items are re-measured.
Foreign exchange gains and losses resulting from the settlement of such
transactions and from the translation at period-end exchange rates of
monetary assets and liabilities denominated in foreign currencies are
recognised in the statement of comprehensive income.
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 and liabilities relating to its interests
in joint operations, including its share of assets held jointly and
liabilities incurred jointly with other partners.
Acquisitions
The Company uses the acquisition method of accounting to account for
business combinations. Identifiable assets acquired and liabilities and
contingent liabilities assumed in a business combination are measured at
their fair values at the acquisition date. The Company recognises any
non-controlling interest in the acquiree at fair value at time of
recognition or at the non-controlling interest‘s proportionate share of net
assets. Acquisition-related costs are expensed as incurred.
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 Company’s accounting policies and that have
the most significant effect on the amounts recognised in the financial
statements.
Recognition of revenue generated by the override royalty, arising from the
RSA (note 2 and 10)
In 2020, the KRG informed the Company that amounts owed in relation to the
suspension of the override for the period between 1 March 2020 to 31
December 2020 would not be paid until oil price improved and towards the
end of 2020 introduced a temporary mechanism to pay those amounts. As
management did not have visibility on how or when this contractual right
would be received, it assessed that the criteria for revenue recognition
under IFRS15, specifically on payment terms and collectability, have not
been met and proceeded to recognise revenue associated with this mechanism
on a cash receipts basis.
Following the cash receipts in 2022, the Company has recognised $18.2
million in the reporting period.
At 31 December 2022, management has assessed that it is now sufficiently
confident to recognise amounts due under the mechanism, but not yet
received. This has resulted in $16.5 million being also recognised in the
reporting period. All of this amount has been received since the reporting
date.
Qara Dagh PSC (note 8)
Due to the expiry of the Qara Dagh licence on 2 January 2023, the book
value of $78.0 million has been written off under IFRS 6.
Significant estimates
The following are the critical estimates that the directors have made in
the process of applying the Company’s accounting policies and that have the
most significant effect on the amounts recognised in the financial
statements.
Estimation of hydrocarbon reserves and resources and associated production
profiles and costs
Estimates of hydrocarbon reserves and resources are inherently imprecise
and are subject to future revision. The Company’s estimation of the quantum
of oil and gas reserves and resources and the timing of its production,
cost and monetisation impact the Company’s financial statements in a number
of ways, including: testing recoverable values for impairment; the
calculation of depreciation, amortisation and assessing the cost and likely
timing of decommissioning activity and associated costs. This estimation
also impacts the assessment of going concern and the viability statement.
Proved and probable reserves are estimates of the amount of hydrocarbons
that can be economically extracted from the Company’s assets. The Company
estimates its reserves using standard recognised evaluation techniques
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.
Change in accounting estimate
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 8 and 9)
Estimation of the asset value of oil and gas assets is calculated from a
number of inputs that require varying degrees of estimation. Principally
oil and gas assets are valued by estimating the future cash flows based on
a combination of reserves and resources, costs of appraisal, development
and production, production profile and future sales price and discounting
those cash flows at an appropriate discount rate.
Future costs of appraisal, development and production are estimated taking
into account the level of development required to produce those reserves
and are based on past costs, experience and data from similar assets in the
region, future petroleum prices and the planned development of the asset.
However, actual costs may be different from those estimated.
Discount rate is assessed by the Company using various inputs from market
data, external advisers and internal calculations. A post tax nominal
discount rate of 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.
Change in accounting estimate – Discount rate for assessing recoverable
amount of producing assets
Following the changes in the macro geo-political, economic and industry
environment, the Company has updated the discount rate used for assessing
the recoverable amount of its producing assets from 13% to 14%.
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 forecast of average Brent oil price for future years is based
on a range of publicly available market estimates and is summarised in the
table below.
$/bbl 2022 2023 2024 2025 2026
Actual / Forecast 101 82 78 74 70
HY2022 forecast 100 90 80 70 70
Prior year forecast 75 75 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 does not have
direct visibility on the components of the netback price realised for its
oil because sales are managed by the KRG, but invoices are currently raised
for payments on account using a netback price provided by the KRG. Due to
lack of this visibility, the Company has used an estimated c.$10/bbl
discount on its Brent forecast based on the realised price in 2022 for its
impairment testing and viability. 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. A sensitivity analysis
of netback price on producing asset values has been provided in note 9.
Change in accounting estimate – Sarta PSC (note 9)
Following the results of the two appraisal wells and ongoing pilot
production, the Company has assessed that initial field expectations are
unlikely to be met and there is an impairment trigger in relation to
reserves and production profiles, hence undertaken an impairment review of
the carrying value of the asset. This has resulted in a reduction in the
recoverable value of the Sarta PSC to its value in use of $16.8 million and
in an impairment expense of $125.5 million.
Other estimates
The following are the other estimates that the directors have made in the
process of applying the Company’s accounting policies and that have effect
on the amounts recognised in the financial statements.
Estimation of the recoverable value of deferred receivables and trade
receivables (note 10)
At the end of March 2020, in line with other International Oil Companies
(IOCs) in Kurdistan, the KRG informed the Company that payments owed for
sales made in the four months from November 2019 to February 2020 would be
deferred and paid under a reconciliation model.
As at 31 December 2022, all amounts owed for deferred receivables have been
collected and as a result the Company has released the remaining expected
credit loss (ECL) provision of $10.8 million. On the other hand, the
Company is owed five months of payments and therefore, management has
compared the carrying value of trade receivables with the present value of
the estimated future cash flows based on different collection timing
scenarios and 14% discount rate. The ECL is the weighted average of these
scenarios and is recognised in the income statement. The result of this
assessment is an ECL provision of $4.6 million.
Decommissioning provision (note 14)
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 the period inflated at 2% (2021: 2%) and discounted
at 4% (2021: 4%). 10% increase in cost estimates would increase the
existing provision by c.$5 million and 1% increase in discount rate would
decrease the existing provision by c.$4 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 2021, 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.
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 oil sales are made to the KRG and are valued at a netback
price which is explained further in significant accounting estimates and
judgements. The Company does not expect to have any contracts where the
period between the transfer of oil to the customer and the payment exceeds
one year. Therefore, the transaction price is not adjusted for the time
value of money.
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.
Other intangible assets
Other intangible assets that are acquired by the Company are stated at cost
less accumulated amortisation and less accumulated impairment losses.
Amortisation is expensed on a straight-line basis over the estimated useful
lives of the assets of between 3 and 5 years from the date that they are
available for use.
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.
Other property, plant and equipment
Other property, plant and equipment are principally the Company’s leasehold
improvements and other assets and are carried at cost, less any accumulated
depreciation and accumulated impairment losses. Costs include purchase
price and construction cost. Depreciation of these assets is expensed on a
straight-line basis over their estimated useful lives of between 3 and 5
years from the date they are available for use.
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.
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, accounting for operating leases with a remaining
lease term of less than 12 months as at balance sheet date as short-term
leases 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 impairment.
The Company’s assessment of impairment model based on expected credit loss
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 impairment model based on expected credit losses (ECLs).
The standard requires the Company to book an allowance for ECLs for its
financial assets. The Company has assessed its trade receivables as at 31
December 2022 for ECLs. Further explanation is provided in significant
accounting judgements and estimates.
A financial asset is assessed at each reporting date to determine whether
there is any objective evidence that it is impaired. A financial asset is
considered to be impaired if objective evidence indicates that one or more
events have had a negative effect on the estimate of future cash flows of
that asset. An impairment loss in respect of a financial asset measured at
amortised cost is calculated as the difference between its carrying amount,
and the present value of the estimated future cash flows discounted at the
original effective interest rate. All impairment losses are recognised as
an expense in the statement of comprehensive income. An impairment loss is
reversed if the reversal can be related objectively to an event occurring
after the impairment loss was recognised.
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 IFRS2 is recognised in the statement of
comprehensive income over the vesting period of the award. 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 2022. Amendments to IFRS 3
Business Combinations; IAS 16 Property, Plant and Equipment; IAS 37
Provisions, Contingent Liabilities and Contingent Assets; and Annual
Improvements 2018-2020 (All issued 14 May 2020). These standards did not
have a material impact on the Company’s results or financial statements
disclosures in the current reporting period.
The following new accounting standards, amendments to existing standards
and interpretations have been issued but are not yet effective and/or have
not yet been endorsed by the EU: Amendments to IAS 1 Presentation of
Financial Statements: Classification of Liabilities as Current or
Non-current and Classification of Liabilities as Current or Non-current,
Amendments to IFRS 16 Leases: Lease Liability in a Sale and Leaseback,
Amendments to IFRS 17 Insurance contracts: Initial Application of IFRS 17
and IFRS 9 – Comparative Information (1 Jan 2023), Amendments to IAS 12
Income Taxes: Deferred Tax related to Assets and Liabilities arising from a
Single Transaction (1 Jan 2023), Amendments to IAS 1 Presentation of
Financial Statements and IFRS Practice Statement 2: Disclosure of
Accounting policies (1 Jan 2023), Amendments to IAS 8 Accounting policies,
Changes in Accounting Estimates and Errors: Definition of Accounting
Estimates (1 Jan 2023), IFRS 17 Insurance Contracts; including Amendments
to IFRS 17 (1 Jan 2023). Nothing has been early adopted, and these
standards are not expected to have a material impact on the Company’s
results or financials statement disclosures in the periods they become
effective.
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), the Taq Taq PSC (Taq Taq)
and the Sarta PSC (Sarta) which are located in the KRI and make sales
predominantly to the KRG. The pre-production segment is comprised of
discovered resource held under the Qara Dagh PSC (written-off in the year),
the Bina Bawi PSC (derecognised in 2021) and the Miran PSC (derecognised in
2021), all in the KRI and exploration activity, principally located in
Somaliland and Morocco. ‘Other’ includes corporate assets, liabilities and
costs, elimination of intercompany receivables and intercompany payables,
which are non-segment items.
For the year ended 31 December 2022
Total
Production Pre-production Other
$m $m $m $m
Revenue from contracts with 419.5 - - 419.5
customers
Revenue from other sources 13.2 - - 13.2
Cost of sales (200.2) - - (200.2)
Gross profit 232.5 - - 232.5
Exploration expense - (1.0) - (1.0)
Net write-off of intangible - (75.8) - (75.8)
asset
Impairment of property, plant (125.5) - - (125.5)
and equipment
Reversal of impairment of 10.8 - 2.0 12.8
receivables
Impairment of receivables (4.6) - - (4.6)
General and administrative - - (20.1) (20.1)
costs
Operating profit / (loss) 113.2 (76.8) (18.1) 18.3
Operating profit / (loss) is
comprised of
EBITDAX 381.6 - (20.0) 361.6
Depreciation and amortisation (149.1) - (0.1) (149.2)
Exploration expense - (1.0) - (1.0)
Net write-off of intangible - (75.8) - (75.8)
assets
Impairment of property, plant (125.5) - - (125.5)
and equipment
Reversal of impairment of 10.8 - 2.0 12.8
receivables
Impairment of receivables (4.6) - - (4.6)
Finance income - - 6.7 6.7
Bond interest expense - - (25.9) (25.9)
Other finance expense (3.3) (0.4) (2.5) (6.2)
Profit / (Loss) before income 109.9 (77.2) (39.8) (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 (2021: $101.9
million) arising from the ORRI and $34.7 million in relation to the
suspended ORRI as further explained in note 1. No more ORRI income is
expected in the future.
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
For the year ended 31 December 2021
Total
Production Pre-production Other
$m $m $m $m
Revenue from contracts with 322.9 - - 322.9
customers
Revenue from other sources 12.0 - - 12.0
Cost of sales (218.6) - - (218.6)
Gross profit 116.3 - - 116.3
Write-off of intangible asset - (403.2) - (403.2)
Reversal of impairment on 24.1 - - 24.1
receivables
General and administrative - - (14.0) (14.0)
costs
Operating profit / (loss) 140.4 (403.2) (14.0) (276.8)
Operating profit / (loss) is
comprised of
EBITDAX 289.0 - (13.9) 275.1
Depreciation and amortisation (172.7) - (0.1) (172.8)
Write-off of intangible assets - (403.2) - (403.2)
Reversal of impairment of 24.1 - - 24.1
receivables
Finance income - - 0.2 0.2
Bond interest expense - - (26.3) (26.3)
Other finance expense (2.1) (0.2) (2.6) (4.9)
Profit / (Loss) before income 138.3 (403.4) (42.7) (307.8)
tax
Capital expenditure 105.3 58.4 - 163.7
Total assets 644.0 88.3 284.1 1,016.4
Total liabilities (118.2) (22.4) (294.7) (435.3)
Total assets and liabilities in the other segment are predominantly cash
and debt balances.
3. Operating loss
2022 2021
$m $m
Operating costs (50.7) (45.5)
Trucking costs (0.4) (0.4)
Production cost (51.1) (45.9)
Depreciation of oil and gas property, plant and (109.9) (115.1)
equipment (excl. RoU assets)
Amortisation of oil and gas intangible assets (39.2) (57.6)
Cost of sales (200.2) (218.6)
Exploration expense (1.0) -
Write-off of intangible assets (note 1,8) (78.0) (403.2)
Net reversal of accruals 2.2 -
Net write-off of intangible assets (75.8) (403.2)
Impairment of property, plant and equipment (note (125.5) -
1,9)
Reversal of impairment of other receivables 2.0 -
Reversal of impairment of trade receivables (note 10.8 24.1
1,10)
Impairment of receivables (note 1,10) (4.6) -
Corporate cash costs (18.1) (12.2)
Other operating expenses (1.1) (0.2)
Corporate share-based payment expense (0.8) (1.5)
Depreciation and amortisation of corporate assets (0.1) (0.1)
(excl. RoU assets)
General and administrative expenses (20.1) (14.0)
Trucking costs are not cost-recoverable and relate to the Sarta licence
only.
Auditor’s remuneration:
2022 2021
$m $m
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
2022 2021
$m $m
Wages and salaries (21.1) (23.3)
Contractors costs (20.6) (21.2)
Social security costs (4.3) (3.2)
Share based payments (4.1) (5.5)
(50.1) (53.2)
Average headcount was:
2022 number 2021 number
Turkey 39 51
KRI 38 28
UK 34 33
Somaliland 18 16
Contractors 129 110
258 238
5. Finance expense and income
2022 2021
$m $m
Bond interest (25.9) (26.3)
Other finance expense (non-cash) (6.2) (4.9)
Finance expense (32.1) (31.2)
Bank interest income 6.7 0.2
Finance income 6.7 0.2
Net finance expense (25.4) (31.0)
Bond interest payable is the cash interest cost of the Company bond debt.
Other finance expense (non-cash) primarily relates to the discount unwind
on the bond and the asset retirement obligation provision.
6. Income tax expense
Current tax expense is incurred on profits of service companies. Under the
terms of the KRI PSCs, the Company is not required to pay any cash
corporate income taxes as explained in note 1.
7. Loss per share
Basic
Basic loss per share is calculated by dividing the loss attributable to
owners of the parent by the weighted average number of shares in issue
during the period.
2022 2021
Loss attributable to owners of the parent ($m) (7.3) (308.0)
Weighted average number of ordinary shares – number 278,654,909 276,408,652
1
Basic loss per share – cents per share (2.6) (111.4)
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 2022 and 31 December
2021, the performance shares, restricted shares and share options are
anti-dilutive and therefore diluted LPS is the same as basic LPS:
2022 2021
Loss attributable to owners of the parent ($m) (7.3) (308.0)
Weighted average number of ordinary shares – 278,654,909 276,408,652
number1
Adjustment for performance shares, restricted - -
shares, share options and deferred bonus plans
Weighted average number of ordinary shares and 278,654,909 276,408,652
potential ordinary shares
Diluted loss per share – cents per share (2.6) (111.4)
1 Excluding shares held as treasury shares
8. Intangible assets
Exploration and Other
evaluation assets Tawke Total
assets
RSA
$m $m $m $m
Cost
At 1 January 2021 1,541.5 425.1 7.4 1,974.0
Net additions 33.2 - 0.1 33.3
Other 1.3 - - 1.3
Derecognition of accumulated (1,005.3) - - (1,005.3)
costs
Write-off in the year (489.3) - - (489.3)
At 31 December 2021 and 1 81.4 425.1 7.5 514.0
January 2022
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 12.9 425.1 7.5 445.5
Accumulated amortisation and
impairment
At 1 January 2021 (1,005.3) (262.1) (7.2) (1,274.6)
Amortisation charge for the - (57.6) (0.3) (57.9)
period
Derecognition of accumulated 1,005.3 - - 1,005.3
impairment
At 31 December 2021 and 1 - (319.7) (7.5) (327.2)
January 2022
Amortisation charge for the - (39.2) - (39.2)
year
At 31 December 2022 - (358.9) (7.5) (366.4)
Net book value
At 1 January 2021 536.2 163.0 0.2 699.4
At 31 December 2021 81.4 105.4 - 186.8
At 31 December 2022 12.9 66.2 - 79.1
2022 2021
Book value $m $m
Somaliland PSC Exploration 12.9 10.6
Qara Dagh PSC Exploration / Appraisal - 70.8
Exploration and evaluation assets 12.9 81.4
Tawke overriding royalty - 27.5
Tawke capacity building payment waiver 66.2 89.7
Tawke RSA assets 66.2 105.4
An impairment review was conducted by Management and the Board which
resulted in a write-off expense of $78.0 million in the carrying value of
the Qara Dagh PSC. Further explanation is provided in note 1.
9. Property, plant and equipment
Other
Producing assets
assets Total
$m $m $m
Cost
At 1 January 2021 3,036.3 22.6 3,058.9
Net additions 69.3 0.4 69.7
Right-of-use assets (note 19) - 1.5 1.5
Transfer of right-of-use assets 7.4 (7.4) -
Other1 4.2 - 4.2
At 31 December 2021 and 1 January 2022 3,117.2 17.1 3,134.3
Net additions 129.1 0.9 130.0
Right-of-use assets (note 19) - (0.4) (0.4)
Other1 5.9 - 5.9
At 31 December 2022 3,252.2 17.6 3,269.8
Accumulated depreciation and impairment
At 1 January 2021 (2,651.4) (11.8) (2,663.2)
Depreciation charge for the year (115.1) (3.5) (118.6)
Transfer (2.7) 2.7 -
At 31 December 2021 and 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 (3,007.5) (14.2) (3,021.7)
Net book value
At 1 January 2021 384.9 10.8 395.7
At 31 December 2021 348.0 4.5 352.5
At 31 December 2022 244.7 3.4 248.1
1 Other line includes non-cash asset retirement obligation provision and
share-based payment costs.
2022 2021
Book value $m $m
Tawke PSC Oil production 199.1 196.4
Taq Taq PSC Oil production 28.8 37.2
Sarta PSC Oil production/development 16.8 114.4
Producing assets 244.7 348.0
An impairment review was conducted by Management and the Board which
resulted in a reduction in the carrying value of the Sarta PSC and in an
impairment expense of $125.5 million. 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.
Sensitivities
Taq Taq Tawke Sarta
$m $m $m
Netback price +/- $5/bbl +/- 5 +/- 32 +/- 6
Discount rate +/- 1% +/- 0 +/- 8 +/- 1
Production +/- 10% +/- 5 +/- 25 +/- 6
10. Trade and other receivables
2022 2021
$m $m
Trade receivables – current 117.0 139.7
Trade receivables – non-current - 18.4
Other receivables and prepayments 4.7 5.3
121.7 163.4
At 31 December 2022, the Company is owed five months of payments (31
December 2021: three months).
Period when sale made
Deferred
receivables
Not due Overdue 2020 2019 Total ECL Trade
2022 nominal provision receivables
$m $m $m $m $m $m $m
31
December 60.7 44.4 16.5 - 121.6 (4.6) 117.0
2022
31
December 92.1 - 55.4 21.4 168.9 (10.8) 158.1
2021
2022 2021
Movement on trade receivables in the period
$m $m
Carrying value at 1 January 158.1 94.0
Revenue from contracts with customers 384.8 322.9
Revenue recognised for suspended ORRI (note 1) 34.7 -
Cash proceeds (473.3) (281.3)
Offset of payables due to the KRG (0.1) (2.9)
Reversal of previous year’s expected credit loss (note 1) 10.8 24.1
Expected credit loss for current year (note 1) (4.6) -
Capacity building payments 5.2 1.3
Sarta processing fee payments 1.4 -
Carrying value at 31 December 117.0 158.1
Of which non-current - 18.4
11. Cash and cash equivalents
2022 2021
$m $m
Cash and cash equivalents 494.6 313.7
494.6 313.7
Cash is primarily held on major international financial institutions and in
US Treasury bills.
12. Trade and other payables
2022 2021
$m $m
Trade payables 25.3 19.5
Other payables 5.2 14.3
Accruals 53.1 68.6
83.6 102.4
Non-current 1.2 4.9
Current 82.4 97.5
83.6 102.4
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 19.
13. Deferred income
2022 2021
$m $m
Non-current (within 1-2 years) 6.5 14.0
Current 6.8 6.5
13.3 20.5
14. Provisions
2022 2021
$m $m
Balance at 1 January 42.6 45.9
Interest unwind 2.6 1.8
Additions 7.0 2.2
Reversals - (7.3)
Balance at 31 December 52.2 42.6
Provisions cover expected decommissioning, abandonment and exit costs
arising from the Company’s assets which are further explained in note 1.
15. Interest bearing loans and net cash
1 Jan Discount Dividend Net 31 Dec
2022 unwind paid other 2022
Repurchase changes
$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
At 31 December 2022, the fair value of the $274 million of bonds held by
third parties is $257.6 million (2021: $287.8 million).
The Company repurchased $6 million of its existing $280 million senior
unsecured bond for an opportunistic acquisition at a price equal to 95% of
the nominal amount that provided an attractive level of return.
The bonds maturing in 2025 have two financial covenant maintenance tests:
Financial covenant Test YE 2022 YE 2021
Equity ratio (Total equity/Total assets) > 40% 56% 57%
Minimum liquidity > $30m $494.6m $313.7m
1 Jan Discount Dividend Net other 31 Dec
2021 unwind paid changes 2021
Buyback
$m $m $m $m $m $m
2022 Bond 10.0% (80.6) (0.4) 81.0 - - -
(current)
2025 Bond 9.25% (267.7) (2.1) - - - (269.8)
(non-current)
Cash 354.5 - (81.0) (44.4) 84.6 313.7
Net cash 6.2 (2.5) - (44.4) 84.6 43.9
In October 2020, the Company issued a new $300 million senior unsecured
bond with maturity in October 2025. The new bond has a fixed coupon of
9.25% per annum. In connection with the issue, the Company repurchased
$222.9 million of its existing $300.0 million senior unsecured bond issue
with maturity date in December 2022 at a price of 107 per cent. On 22
December 2020, the Company wrote to the Trustees confirming that they were
exercising the right to call the remaining $77.1 million of the 2022 bond
at the call price of 105 per cent. This settlement completed on 8 January
2021.
16. 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:
2022 2021
$m $m
Trade and other receivables 119.1 160.8
Cash and cash equivalents 494.6 313.7
613.7 474.5
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 2022 the Company had cash and
cash equivalents of $494.6 million (2021: $313.7 million).
Oil price risk
The Company’s revenues are calculated from netback price as further
explained in note 1, and a $5/bbl change in average netback price would
result in a (loss) / profit before tax change of circa $17 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 $266.6 million (2021: $269.8 million) in
the form of a bond maturing in October 2025, with fixed coupon interest
payable of 9.25% on the nominal value of $274.0 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 $3 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 $494.6 million (2021:
$313.7 million).
Financial instruments
All financial assets and liabilities are measured at amortised cost. Due to
their short-term nature except interest bearing loans, the carrying value
of these financial instruments approximates their fair value. Their
carrying values are as follows:
Financial assets 2022 2021
$m $m
Trade and other receivables 119.1 160.8
Cash and cash equivalents 494.6 313.7
613.7 474.5
Financial liabilities
Trade and other payables 78.4 92.4
Interest bearing loans 266.6 269.8
345.0 362.2
17. Share capital
Total
Ordinary Shares
At 1 January 2021 – fully paid1 280,248,198
At 31 December 2021, 1 January 2022 and 31 December 2022 – 280,248,198
fully paid1
1 Ordinary shares include 845,335 (2021: 1,946,084) treasury shares. Share
capital includes 629,769 (2021: 559,216) 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.
18. Dividends
2022 2021
$m $m
Ordinary shares
Final dividend (2022: 12¢ per share, 2021: 10¢ per share) 33.4 27.9
Interim dividend (2022: 6¢ per share, 2021: 6¢ per share) 16.7 16.5
Total dividends provided for or paid 50.1 44.4
Paid in cash 47.9 44.4
Foreign exchange on dividend paid 2.2 -
Total dividends provided for or paid 50.1 44.4
19. Right-of-use assets / Lease liabilities
The Company’s right-of-use assets are related to the Sarta early production
facility, offices and car leases are included within property, plant and
equipment.
Right-of-use assets
$m
Cost
At 1 January 2021 11.7
Additions 1.5
At 31 December 2021 and 1 January 2022 13.2
Disposals due to terminations (0.4)
At 31 December 2022 12.8
Accumulated depreciation
At 1 January 2021 (2.2)
Depreciation charge for the period (2.9)
At 31 December 2021 and 1 January 2022 (5.1)
Depreciation charge for the period (3.7)
At 31 December 2022 (8.8)
Net book value
At 1 January 2021 9.5
At 31 December 2021 8.1
At 31 December 2022 4.0
2022 2021
Book value $m $m
Offices 1.8 3.2
Cars 0.2 0.2
Production facility 2.0 4.7
Right-of-use assets 4.0 8.1
The weighted average lessee’s incremental borrowing rate applied to the
lease liabilities except Sarta early production facility was 2.5%. 4% was
applied for the facility. The lease terms vary from one to five years.
2022 2021
$m $m
At 1 January (8.3) (9.8)
Additions - (1.4)
Disposals due to terminations 0.5 -
Payments of lease liabilities 3.8 3.3
Interest expense on lease liabilities (0.1) (0.4)
At 31 December (note 12) (4.1) (8.3)
Included within lease liabilities of $4.1 million (2021: $8.3 million) are
non-current lease liabilities of $1.2 million (2021: $4.9 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 (3.0) (0.7) (0.5) (4.2) (4.1)
2022
31 December (3.6) (3.5) (1.9) (9.0) (8.3)
2021
20. Share based payments
The Company has five share-based payment plans under which awards are
currently outstanding: a 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 Awards
Committee performance typically
determines conditions Awards vest in Awards
Vesting whether the have been typically tranches typically
period performance met at the vest after over a vest after
conditions end of the two years. three year three
have been met performance vesting years.
at the end of period. For period
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 2022, awards were made under the performance share plan only. The
numbers of outstanding shares as at 31 December 2022 are set out below:
Weighted
Share awards Share awards avg.
with without Priced exercise
performance performance options price of
conditions conditions priced
options
Outstanding at 1 January 2021 10,047,042 2,160,256 87,824 817p
Granted during the year 2,982,524 369,108 - -
Dividend equivalents 872,036 109,992 - -
Forfeited during the year (601,831) (20,528) - -
Lapsed during the year (1,284,140) (37,123) - -
Exercised during the year (2,783,799) (1,136,871) - -
Outstanding at 31 Dec 2021 9,231,832 1,444,834 87,824 817p
and 1 Jan 2022
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 December 7,676,205 1,057,303 53,857 858p
2022
The range of exercise prices for share options outstanding at the end of
the period is 742.00p to 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 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 RSP awards (without condition) granted
in 2022 is 164p and for PSP awards granted in 2022 is 124p.
The inputs into the fair value calculation for RSP and PSP awards granted
in 2021 and fair values per share using the model were as follows:
RSP PSP RSP PSP
06/04/2021 06/04/2021 07/09/2021 07/09/2021
Share price at grant date 173p 173p 122p 122p
Fair value on measurement 173p 110p 122p 64p
date
Expected life (years) 1-3 1-3 1-3 1-3
Expected dividends - - - -
Risk-free interest rate 0.126% 0.126% 0.182% 0.182%
Expected volatility 48.19% 48.19% 45.63% 45.63%
Share price at balance sheet 130p 130p 130p 130p
date
Change in share price between
grant date and 31 December -25% -25% 7% 7%
2021
The weighted average fair value for RSP awards granted in 2021 is 169p and
for PSP awards granted in 2021 is 109p.
Total share-based payment charge for the year was $4.1 million (2021: $5.5
million).
21. 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.
22. 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:
2022 2021
$m $m
Board remuneration 0.8 1.0
Key management emoluments and short-term benefits 6.0 7.9
Share-related awards 1.0 7.4
7.8 16.3
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.
23. Events occurring after the reporting period
The Qara Dagh PSC has expired on 2 January 2023.
On 28 February 2023, a ‘Petroleum Agreement and Association Contract’ was
signed with the Office National des Hydrocarbures et des Mines (‘ONHYM’)
regarding the Lagzira block.
24. 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. 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. The Company holds 30% working interest in Sarta PSC
which is operated by the Company in the year.
For the period ended 31 December 2022 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 Limited8 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 12 Castle Street, St Helier, JE2 3RT, 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 PO Box 146, Road Town, Tortola, British Virgin
Islands
8 Registered office is 3rd Floor, Geneva Place, Waterfront Drive, PO Box
3175, Road Town, Tortola, Virgin Islands, British
Genel Energy Finance 2 Limited was liquidated during the year.
25. Annual report
Copies of the 2022 annual report will be despatched to shareholders in
April 2023 and will also be available from the Company’s registered office
at 12 Castle Street, St Helier, Jersey JE2 3RT and at the Company’s website
– 2 www.genelenergy.com.
26. Statutory financial statements
The financial information for the year ended 31 December 2022 contained in
this preliminary announcement has been audited and was approved by the
board on 21 March 2023. The financial information in this statement does
not constitute the Company's statutory financial statements for the years
ended 31 December 2022 or 2021. The financial information for 2022 and 2021
is derived from the statutory financial statements for 2021, which have
been delivered to the Registrar of Companies, and 2022, which will be
delivered to the Registrar of Companies and issued to shareholders in April
2023. The auditors have reported on the 2022 and 2021 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 2022 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 2021 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: ACS
TIDM: GENL
LEI Code: 549300IVCJDWC3LR8F94
Sequence No.: 231542
EQS News ID: 1588605
End of Announcement EQS News Service
══════════════════════════════════════════════════════════════════════════
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