REG - Gulf Keystone Petrol - 2023 Full Year Results announcement
21/03/2024 07:00
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RNS Number : 7580H Gulf Keystone Petroleum Ltd. 21 March 2024
21 March 2024
Gulf Keystone Petroleum Ltd. (LSE: GKP)
("Gulf Keystone", "GKP", "the Group" or "the Company")
2023 Full Year Results announcement
Gross average sales in 2024 year to 19 March of c.33,300 bopd; March 2024 to
date sales of c.43,000 bopd
Cash balance as at 20 March of $86 million, accounts payable current
Cash generative in current environment with upside potential from exports
restart and payments normalisation
Gulf Keystone, a leading independent operator and producer in the Kurdistan
Region of Iraq ("Kurdistan"), today announces its results for the full year
ended 31 December 2023.
Jon Harris, Gulf Keystone's Chief Executive Officer, said:
"Following a challenging year in 2023, in which our operational and financial
performance was impacted by the suspension of Kurdistan exports and delays to
KRG payments, we successfully adapted to the new local sales environment.
Local sales volumes have rebounded since the beginning of 2024, with year to
date gross average sales of c.33,300 bopd and March to date sales of c.43,000
bopd. We are more than covering our monthly expenditures and have
significantly reduced accounts payable, with all invoices now current. Free
cash flow from current robust local sales demand is being used to further
improve our liquidity position. Looking ahead, we remain resilient with upside
potential from the restart of exports and normalisation of payments. While
there is no defined timeline, we continue to actively engage with government
stakeholders to secure a solution to unlock significant value for all
stakeholders."
Highlights to 31 December 2023 and post reporting period
Operational
· Continued rigorous focus on safety, with Zero Lost Time Incidents
for 430 days as at 20 March 2024
· Significant operational transition following the Iraq-Turkey
Pipeline ("ITP") closure on 25 March 2023 as GKP moved from pipeline exports
and reservoir development to the shut-in of production, suspension of all
expansion activities and subsequent start-up of local sales
· 2023 gross average production of 21,891 bopd (2022: 44,202 bopd),
reflecting strong growth prior to the suspension of exports followed by the
start-up of local sales in H2 2023 at lower levels
o Gross production averaged 49,165 bopd between 1 January and 24 March 2023,
with the ramp-up of SH-16 and start-up of SH-17 driving production to highs of
over 55,000 bopd on several days in March 2023
o Gross average local sales of 23,331 bopd between 19 July and 31 December
2023
· Increasing local demand in 2024 year to date has driven a rebound
in sales volumes
o Year to date gross average sales of 33,300 bopd, with gross average sales
in March 2024 to date of c.43,000 bopd, as at 19 March 2024
o Ramp up in local sales reflects strong market demand for certain refined
products, the further easing of seasonal logistic challenges and a realised
price of c.$25/bbl
Financial
· Material impact on 2023 financial performance from the suspension
of exports and continued delays to payments from the Kurdistan Regional
Government ("KRG")
· Decisive action taken to preserve liquidity¸ with significant
expenditure reductions and transition to local sales
· Reduction in revenue and profitability from lower production and
realised prices
o Revenue reduced to $123.5 million (2022: $460.1 million), reflecting the
50% decrease in gross average production to 21,891 bopd and lower average
realised prices from local sales in H2 2023 of $30/bbl
o Loss after tax of $11.5 million (2022: profit after tax of $266.1
million), including an increase in the expected credit loss provision
determined under IFRS 9 of $21.4 million (2022: $2.0 million) related to the
$151 million overdue receivables from the KRG for October 2022 to March 2023
export sales. The Company continues to expect to recover the receivables
· Free cash outflow of $13.1 million (2022 free cash flow of $266.5
million), reflecting lower Adjusted EBITDA and delays to KRG payments,
partially offset by reduced net capex and costs
o Adjusted EBITDA declined to $50.1 million (2022: $358.5 million)
o Revenue receipts of $109.2 million (2022: $450.4 million), reflecting
$65.7 million for export sales in August and September 2022 received in Q1
2023 and $43.5 million from local sales in H2 2023
o 2023 net capex of $58.2 million (2022: $114.9 million), of which $11.2
million was in H2 2023, as the Company suspended all Shaikan Field expansion
activity
o 2023 operating costs of $36.1 million were 14% lower year-on-year (2022:
$41.9 million), reflecting the shut-in of production for more than three
months and cost saving initiatives
o 2023 Other G&A reduced to $10.5 million (2022: $12.2 million)
principally due to cost savings and no bonus payments to staff, partially
offset by non-recurring corporate costs of $2.1 million in H1 2023
· Cash generated from local sales has enabled the Company to more
than cover its monthly expenditures and strengthen its balance sheet
o Net capex, operating costs and Other G&A reduced to a monthly run rate
below $6 million in H2 2023
o GKP's 36% net entitlement from local sales have enabled the Company to
more than cover its costs since commencement, with current breakeven at gross
sales of c.22,200 bopd
o Excess cash generation facilitated the reduction in accounts payable,
including trade payables and accrued expenditures, to $26.0 million at 31
December 2023 (31 December 2022: $44.1 million)
o The payment of all remaining overdue invoices in 2024 has resulted in a
further reduction in accounts payable to roughly half the balance at the end
of 2023
· Following the payment of a $25 million interim dividend in March
2023, the Company's ordinary dividend policy was suspended to preserve
liquidity
· Cash balance of $86 million at 20 March 2024 with no debt
Shaikan Field estimated reserves
· In March 2023, the Company published the 2022 Competent Person's
Report ("CPR"), an independent third-party evaluation confirming 817 MMstb of
estimated gross reserves and resources, including 506 MMstb million stock tank
barrels ("MMstb") of estimated gross proved and probable ("2P") reserves
· We have seen no degradation to the reservoir from the extended
shut-in of production in 2023 and the field is performing in line with our
expectations
o However, we do not expect to consider a return to development of the
Shaikan Field until exports have restarted and we have confidence in KRG
payments and the commercial environment
· To assess the impact of the production shut-in and suspension of
expansion activity on gross 2P reserves, we have prepared internal estimates
that incorporate a delay in return to development drilling
o Adjusting year end 2022 gross 2P reserves of 506 MMstb for 2023 production
of 8 MMstb, we estimate that the development delay has reduced gross 2P
reserves by 40 MMstb or 8% to 458 MMstb at 31 December 2023, as recoverable
volumes are pushed beyond licence expiry in 2043
· Based on 2022 gross average production of 44,202 bopd, the last
full year of production prior to the ITP closure, the estimated gross 2P
reserves-to-production ratio is c.28 years, underpinning the case for eventual
further investment when the environment improves
· We expect to commission an updated CPR, including a comprehensive
independent assessment of proved reserves, 2P reserves and contingent
resources, once the operating environment has normalised
Outlook
· The Company is focused on maximising local sales and minimising
costs to improve its liquidity position, while pushing for an exports restart
and payment solution to unlock significant value
· While we continue to expect variable local sales demand in 2024,
we see robust market demand in the near term and remain focused on maintaining
our strong performance
· Subject to local sales demand and considering our limited capital
programme, gross production potential is currently between 43,000 - 45,000
bopd:
o Continue to manage well productivity to avoid traces of water and field
declines estimated at 6-10% per year
· Expect to maintain aggregate net capex, operating costs and other
G&A monthly run rate at or below c.$6 million in 2024:
o Estimated 2024 net capex of c.$20 million, comprising safety critical
upgrades and production maintenance expenditures
o Continuing to focus on further reducing costs while retaining operational
capability to respond to local sales demand and resume exports
· The Company continues to actively engage with government
stakeholders to push for a pipeline exports restart solution:
o While it remains uncertain when exports will restart, political and
commercial negotiations between the Federal Government of Iraq ("FGI") and the
KRG are ongoing
o Together with other International Oil Companies operating in Kurdistan, we
continue to emphasise the importance of payment surety for future oil exports,
the repayment of outstanding receivables and the preservation of current
contract economics
· With the resumption of exports and normalisation of payments and
arrears, GKP will consider incremental field investment to realise Shaikan's
substantial potential and return to previous production levels
· We continue to believe the distribution of excess cash by way of
dividends or share buybacks is important to reward shareholders. As the
operating environment and the Company's liquidity position improve, we will
keep under review our capability to reinstate distributions
Investor & analyst presentation
GKP's management team will be hosting a presentation for analysts and
investors at 10:00am (GMT) today via live audio webcast:
https://brrmedia.news/GKP_FY23 (https://brrmedia.news/GKP_FY23)
Management will also be hosting an additional webcast presentation focused on
retail investors via the Investor Meet Company ("IMC") platform at 12:00pm
(GMT) today. The presentation is open to all existing and potential
shareholders and participants will be able to submit questions at any time
during the event.
https://www.investormeetcompany.com/gulf-keystone-petroleum-ltd/register-investor
(https://www.investormeetcompany.com/gulf-keystone-petroleum-ltd/register-investor)
This announcement contains inside information for the purposes of the UK
Market Abuse Regime.
Enquiries:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations aclark@gulfkeystone.com (mailto:aclark@gulfkeystone.com)
& Corporate Communications
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton GKP@fticonsulting.com (mailto:GKP@fticonsulting.com)
Nick Hennis
or visit: www.gulfkeystone.com (http://www.gulfkeystone.com)
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent operator and
producer in the Kurdistan Region of Iraq. Further information on Gulf Keystone
is available on its website www.gulfkeystone.com
(http://www.gulfkeystone.com/)
Disclaimer
This announcement contains certain forward-looking statements that are subject
to the risks and uncertainties associated with the oil & gas exploration
and production business. These statements are made by the Company and its
Directors in good faith based on the information available to them up to the
time of their approval of this announcement but such statements should be
treated with caution due to inherent risks and uncertainties, including both
economic and business factors and/or 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. This announcement has been prepared solely to
provide additional information to shareholders to assess the Group's
strategies and the potential for those strategies to succeed. This
announcement should not be relied on by any other party or for any other
purpose.
Chairman's statement
I'm pleased to be writing to you for the first time as Non-Executive Chairman
of Gulf Keystone Petroleum following my appointment at the Annual General
Meeting in June 2023. It was a privilege to take on the role after almost five
years on GKP's Board of Directors. I joined the company as Senior Independent
Director in July 2018 before also becoming Deputy Chairman from June 2019.
During that time, I was fortunate to work closely with Jaap Huijskes, who I
succeeded as Chairman. Jaap oversaw a period of significant value creation for
our shareholders and Kurdistan and provided strong leadership during periods
of significant volatility, in particular the COVID-19 pandemic.
My first few months as Chairman have been characterised by a challenging
operational and economic environment for the Company. The closure of the
Iraq-Turkey Pipeline ("ITP") and suspension of Kurdistan exports on 25 March
2023 compounded the impact of increasing delays to payments from the Kurdistan
Regional Government ("KRG"), prompting the Company to take decisive action to
protect its balance sheet. In adapting to this new environment, the management
team have demonstrated considerable agility and commitment in transitioning
the company away from Shaikan crude being exported by pipeline, with continued
execution of the development programme, to establishing sales of crude to
local buyers with 24-hour truck loading operations, whilst maintaining a
sustained focus on liquidity preservation. This has enabled the company to
more than cover its reduced monthly expenditures with local pre-paid sales
revenue.
I and the rest of GKP's Board have spent significant time since the ITP
closure analysing the geopolitical environment and the pathway to a potential
exports restart solution. It is our continued belief that crude exports from
the Kurdistan Region are of vital economic importance to both Kurdistan and
Federal Iraq. While it remains uncertain when exports will restart, progress
has been made in negotiations between the KRG and the Federal Government of
Iraq towards a solution and the Company has proactively made its voice heard
along with other companies operating in the region. The Company remains
focused on protecting shareholder interests by ensuring that current
Production Sharing Contract economics are preserved, clarity is provided
around the payment mechanism for future exports and a pathway to the repayment
of the Company's outstanding receivables is defined.
The Company has a strong team in place to navigate through the current
challenges. Collectively they have many years of experience working in
Kurdistan and other emerging market environments. They also have significant
technical expertise in fractured carbonate reservoirs. The Board has been
pleased to see the reservoir performing in line with expectations, enabling
the ramp up of production in recent weeks to respond to the current strong
demand in the local market. This has confirmed the Company's decision to
maintain the operational flexibility required to increase local sales quickly
and retain the optionality to restart exports at full capacity when required.
We were pleased to welcome Julien Balkany to the Board in July 2023 as a
non-independent non-executive director representing funds managed by Lansdowne
Partners Austria GmbH, replacing Garrett Soden. We are also looking forward to
welcoming Gabriel Papineau-Legris as he succeeds Ian Weatherdon as Chief
Financial Officer following his retirement at the 2024 AGM in June. On behalf
of the Board, I would like to thank Ian for his substantial contribution over
the past four years.
We are currently looking to recruit two new Non-Executive Directors to meet
the UK Corporate Governance Code and UK Listing Rules requirements in respect
of independence, gender and ethnic diversity, to broaden the operational and
technical experience of the Board, and to replace Kimberley Wood as current
Senior Independent Director following her previously announced intention to
stand down from the Board because of her time commitments to an executive role
she has recently taken on elsewhere. This recruitment process began in early
2023 but was suspended, until late in the year, following the ITP closure
given the then prevailing, uncertain geo-political and trading background and
the Company's necessary focus on short term liquidity.
The Board continued to engage with the Company's shareholders in 2023 and
welcomes ongoing interaction and feedback with all investors. We would like to
thank all of the Company's shareholders for their continued support. The
Company has demonstrated resilience and continues to take prudent actions to
protect the balance sheet, ensuring that it is well positioned to unlock the
Shaikan Field's significant value when pipeline exports restart and the
operating environment improves.
Martin Angle
Non-Executive Chairman
20 March 2024
Chief Executive Officer's review
GKP's operational and financial performance in 2023 was materially impacted by
the suspension of Kurdistan exports and delays to KRG oil sales payments. Our
actions to reduce capital expenditures and costs and safely transition our
operations to trucking and local sales have enabled us to protect our business
as we continue to engage with government stakeholders for an exports restart
solution.
The unexpected closure of the Iraq-Turkey Pipeline ("ITP") on 25 March 2023
was the consequence of a long running International Chamber of Commerce
arbitration case between Iraq and Turkey being awarded in Iraq's favour. With
no route to market, we shut-in the Shaikan Field on 13 April following
curtailed production into storage and moved swiftly to suspend the drilling
and development project that had driven gross production to highs of over
55,000 bopd on several days in March. Following the payment of a $25 million
interim dividend prior to the ITP closure, we suspended the ordinary annual
dividend. By taking decisive action, we were able to reduce monthly capex and
costs to below $6 million in the second half of the year. Despite the
significant disruption to our organisation, we have maintained our focus on
safe operations, with 430 days without a Lost Time Incident to date.
In July 2023, we started sales of Shaikan Field crude via truck to the local
downstream market. While volumes have fluctuated and realised prices have been
at steep discounts to Brent, all crude has been paid for in advance by buyers
and demand has been sufficient for us to more than cover our monthly costs and
significantly reduce accounts payable balances. Gross average sales were
23,331 bopd in the second half of 2023 from commencement on 19 July 2023. The
local market has been stronger in 2024, driven by increased demand for certain
refined products and the easing of seasonal logistic challenges. Gross average
sales in the year to 19 March have been c.33,300 bopd, with gross average
sales in March to date of c.43,000 bopd. Realised prices are currently
c.25/bbl, in line with local market pricing.
We continue to minimise our capital expenditures and costs, with our aggregate
monthly run rate expected to remain at or below c.$6 million in 2024. We
continue to focus on maximising local sales to cover our costs and strengthen
our balance sheet. While we continue to expect variable local sales demand in
2024, we see strong near-term demand. At current local sales levels, we are
cash generative, with our current low gross production breakeven of c.22,200
bopd providing downside protection.
While there remains no defined timeline, we are actively engaging with
government stakeholders to push for the restart of pipeline exports. Kurdistan
production, historically around 400,000 bopd, is integral to funding the Iraqi
Budget and represents a material source of global oil supply. The
re-establishment of a constructive environment for international investors is
also important to encourage foreign direct investment for both Kurdistan and
Iraq. Negotiations are ongoing between the KRG and Federal Government of Iraq
and the path forward appears to be linked to amending the Iraqi Budget to
integrate a more accurate reflection of the production and transportation
costs associated with the Kurdistan industry. We believe progress has been
made but continue to seek clarity, along with other International Oil
Companies, on how the industry will be compensated for future exports and when
outstanding receivables will be repaid, of which GKP is owed $151 million net.
We continue to strongly emphasise that the current economics in our Production
Sharing Contract must be preserved and have received contract sanctity
assurances from the KRG.
With the resumption of exports and normalisation of payments, we would
consider incremental field investment to realise Shaikan's potential. We also
continue to believe the return of excess cash by way of dividends or share
buybacks is important to reward shareholders and we will keep under review our
capability to reinstate distributions as the operating environment and
Company's liquidity position improves. While we are resilient and cash
generative at current local sales levels, we see the potential for significant
free cash flow generation once an exports restart solution has been achieved,
enabled by capital discipline, the continued recovery of previous costs and a
return to selling Shaikan Field crude at international oil prices, which could
more than double current realised prices.
Given delays experienced in the development of the Shaikan Field, current
internal estimates show an 8% reduction in gross 2P reserves at year end 2023
to 458 MMstb after adjusting for 2023 production, as explained in the
Operational Review. Nonetheless, the Shaikan Field remains a large,
underdeveloped asset, with more than enough barrels to underpin strong
production growth in our licence period. Our current reserves-to-production
ratio of around 28 years, based on estimated gross 2P reserves and our last
year of full production in 2022, underlines this fact.
As ever, I want to thank the entire team at GKP for their unwavering
commitment who have adapted well to the many changes we have experienced. I
continue to believe the normalisation of our operating environment and
opportunity to create significant value for our stakeholders is ahead of us.
I want to extend my thanks to Ian Weatherdon, GKP's Chief Financial Officer,
who will be retiring in the summer following the 2024 AGM. Ian has been
instrumental in guiding the Company through the COVID-19 pandemic and the past
year and has also overseen a period of industry leading returns, strong
production growth and the strengthening of our balance sheet through the
retirement of our $100 million bond in 2022. As previously announced, he will
be succeeded by Gabriel Papineau-Legris, currently Chief Commercial Officer,
who has been pivotal to GKP's success over the past seven years.
Jon Harris
Chief Executive Officer
20 March 2024
Operational review
2023 was a year of significant operational transition for Gulf Keystone. From
progressing the Jurassic reservoir expansion project and moving towards
sanction of the Shaikan Field Development Plan, we were forced to completely
change the direction of the business following the closure of the Iraq-Turkey
Pipeline ("ITP") in March 2023 and, after over three months of shut-in, switch
from pipeline exports to trucking operations in the second half of the year.
Despite these changes, we maintained a rigorous focus on safety. While we
unfortunately experienced a Lost Time Incident ("Lost Time Incident") in
January 2023 during drilling operations, we have been operating since then for
430 days without an LTI. Given the ever-changing environment, the team has
performed exceptionally, and with 24-hour truck loading operations running at
both production facilities in recent weeks, often in difficult weather
conditions, we remain focussed on extending this record.
2023 gross average production was 21,891 bopd, 50% lower year-on-year (2022:
44,202 bopd), primarily reflecting the shut-in of Shaikan Field production
from 13 April to 19 July 2023 prior to the commencement of local sales, which
were at a lower level than compared to when the Company was exporting.
Prior to the ITP closure gross production average 49,165 bopd, including five
days in excess of 55,000 bopd, as we progressed the Jurassic expansion
project, ramped up production from SH-16 and started up SH-17. Following the
ITP closure on 25 March 2023, production continued at curtailed rates into
storage prior to a full shut-in on 13 April 2023.
As it became apparent that pipeline exports were unlikely to resume in the
short term, we suspended all expansion activity. Following the completion of
SH-18, we released our drilling rig and suspended well workover activity. We
also halted all production facilities expansion activity, including the
installation of water handling, as well as the preparation of future well pads
and flowlines. Regrettably, we also had to take action to reduce the size of
the organisation. Our expat workforce was reduced by over 60% and around half
of our local workforce were placed on reduced working hours prior to the
start-up of local sales.
On 19 July 2023, we commenced local sales from PF-1 and started sales from
PF-2 in August, with gross average sales from 19 July to 31 December 2023 of
23,331 bopd. Volumes increased steadily from July to October as we signed up
new buyers following an extensive due diligence process. Lower levels of
demand and volumes followed in November and December as other producers in the
region ramped up supply, local refineries became constrained and winter
weather impacted trucking logistics and dampened appetite for certain refined
products.
Volumes have rebounded since the beginning of 2024, with gross average sales
in the year to 19 March 2024 of c.33,300 bopd and gross average sales in March
2024 to date of c.43,000 bopd. Subject to local sales demand and considering
our limited capital programme, we see the current gross production potential
of the Shaikan Field as between 43,000 - 45,000 bopd. As ever, we continue to
manage natural field declines, estimated at between 6-10% per annum, and the
productivity of wells to avoid traces of water. We see robust local sales
demand in the near term and are focused on maintaining our current strong
performance.
Shaikan Field estimated reserves
A few days prior to the ITP closure in March 2023, the Company published the
2022 Competent Person's Report ("2022 CPR"), an independent third-party
evaluation of the Shaikan Field's reserves and resources prepared by ERC
Equipoise ("ERCE"), as at 31 December 2022. The CPR confirmed the Shaikan
Field as a large, long-life asset, with 817 MMstb of estimated gross reserves
and resources, including 506 MMstb of estimated gross 2P reserves.
We have seen no degradation to the reservoir from the extended shut-in of
production in 2023 and the Field is performing in line with our expectations.
However, we do not expect to consider a return to development of the Shaikan
Field until exports have restarted and we have confidence in payments and the
commercial environment.
To assess the impact of the production shut-in and suspension of expansion
activity on gross 2P reserves, we have prepared internal estimates that
incorporate an estimated return to facilities expansion, including water
handling, in 2025 and development drilling in H1 2026. This timeline is
subject to an improvement in the operating environment and restart of
Kurdistan exports, which for modelling purposes we assume occurs in Q4 2024,
and incorporates several months of preparatory and planning work in advance of
development activities.
Adjusting year end 2022 gross 2P reserves of 506 MMstb for 2023 production of
8 MMstb, we estimate that the development delay has reduced gross 2P reserves
by 40 MMstb or 8% to 458 MMstb at 31 December 2023, as recoverable volumes are
pushed beyond the end of the licence period in 2043. Based on 2022 gross
average production of 44,202 bopd, the last full year of export sales prior to
the ITP closure, the revised estimate of gross 2P reserves-to-production ratio
is around 28 years, underpinning the case for further investment.
We expect to commission an updated Competent Person's Report, including a
comprehensive independent assessment of 1P and 2P reserves and 2C resources,
at the appropriate time once the operating environment has normalised.
Sustainability strategy
We remain committed to building a more sustainable business. Our
sustainability strategy is focused on reducing emissions and protecting the
local environment, maintaining high standards of safety, ensuring a great
place to work for our people, generating significant economic value for
Kurdistan and doing business the right way with outstanding levels of
governance and ethical behaviour.
In 2023, progress against our strategy, in particular our focus on reducing
emissions, was impacted by the suspension of exports and reduction in
investment and costs across the business. While our Scope 1 emissions in the
year were 51% lower due to the decrease in Shaikan Field production, the Gas
Management Plan, which is an important component of the Shaikan Field
Development Plan, has been delayed. We have also paused the assessment and
development of a number of other decarbonisation projects, including an
initiative to eliminate methane venting from our storage tanks. As a result,
our previous emissions reduction targets, including reducing our scope 1
emissions intensity by >50% by 2025 against a 2020 baseline, have been
suspended.
We remain committed to significantly reducing our emissions and will review
and reinstate our targets when we have more clarity on the outlook. In the
meantime, we are in the early stages of exploring alternative options to the
Gas Management Plan, with a focus on optimising scope, implementation timing
and cost. We are also prioritising our list of additional decarbonisation
opportunities so we are ready to progress at the appropriate time.
Looking to the future, we remain committed to executing our sustainability
strategy and improving our performance. In the short term, we are acting
within the constraints of the current environment to extend our excellent
safety performance, assess more effective ways to decarbonise our business,
make GKP a better place to work for our employees and contractors and direct
as much support as possible to local communities and people. Full details will
be published in our 2023 Annual Report and Sustainability Report. With the
restart of exports and the re-establishment of a more constructive investment
environment for international oil companies, we will be able to return to
investment, reinvigorate our progress towards a more sustainable business and
unlock significant value for all stakeholders.
John Hulme
Chief Operating Officer
20 March 2024
Financial review
Key financial highlights
Six months ended Six months ended Year ended Year ended
30 June 2023 31 December 2023 31 December 2023 31 December 2022
Gross average production((1)) bopd 23,256 20,549 21,891 44,202
Dated Brent((2)) $/bbl 81.2 85.3 82.6 101.4
Realised price $/bbl 51.3 30.0 40.9 74.1
Discount to Dated Brent $/bbl 29.9 55.3 41.7 27.2
Revenue $m 79.6 44.0 123.5 460.1
Operating costs $m 18.9 17.2 36.1 41.9
Gross operating costs per barrel((1)) $/bbl 5.6 5.7 5.6 3.2
Other general and administrative expenses $m 9.1 1.3 10.5 12.2
Share option expense $m 8.4 2.4 10.8 13.8
Adjusted EBITDA((1)) $m 34.2 17.9 50.1 358.5
Profit/(loss) after tax $m (2.9) (8.6) (11.5) 266.1
Basic earnings/(loss) per share cents (1.3) (3.9) (5.3) 123.5
Revenue and arrears receipts((1)(3)) $m 65.7 43.5 109.2 450.4
Net capital expenditure((1)) $m 47.0 11.2 58.2 114.9
Free cash flow((1)) $m (9.9) (3.2) (13.1) 266.5
Dividends $m 25 - 25 215
Cash and cash equivalents $m 84.9 81.7 81.7 119.5
(1) Gross average production, realised price, gross operating costs per
barrel, Adjusted EBITDA, revenue and arrears receipts, net capital expenditure
and free cash flow are either non-financial or non-IFRS measures and, where
necessary, are explained in the summary of non-IFRS measures.
(2) For the period six months ended 31 December 2023, a simple average Dated
Brent price is provided as a comparator for realised price. Realised prices
for local sales are currently driven by supply and demand dynamics in the
local market, with no direct link to Dated Brent. For prior periods, Dated
Brent reflects the weighted average price used for export sales.
(3) Arrears receipts relate to historic receivables settled in H1 2022; all
receipts in 2023 were for current invoices.
While GKP started the year with production and development momentum, the
Company's financial performance in 2023 was significantly impacted by the
suspension of Kurdistan crude exports on 25 March 2023 and continued delays to
KRG payments. To protect our balance sheet, we took decisive action to
preserve liquidity by reducing net capital expenditures, operating costs and
other G&A expenses to a monthly run rate of less than $6 million in the
second half of the year. With the commencement of local sales in July, we have
been able to more than cover our monthly expenditures while significantly
reducing outstanding accounts payable. Looking ahead, we remain focused on
minimising costs while maintaining operational capability to maximise local
sales and fully capitalise on the restart of Kurdistan exports.
Adjusted EBITDA
Adjusted EBITDA declined to $50.1 million (2022: $358.5 million), driven by
the impact on production from the suspension of exports and lower realised
prices from local sales in H2 2023.
Gross average production was 21,891 bopd, 50% lower year-on-year (2022: 44,202
bopd) reflecting the shut-in of Shaikan Field production from 13 April to 19
July prior to the commencement of local sales, which were at lower levels than
export sales.
Revenue decreased to $123.5 million (2022: $460.1 million), reflecting no
revenue in the second quarter and lower local sales volumes and realised
prices in the second half of the year. Production in the second half of the
year was sold to local buyers at an average realised price of $30/bbl, well
below historical discounts to Dated Brent. Realised prices for local sales are
currently driven by supply and demand dynamics in the local market, with no
direct link to Dated Brent.
The Company took decisive action to reduce expenses following the suspension
of Kurdistan crude exports.
Operating costs of $36.1 million were 14% lower year-on-year (2022: $41.9
million), reflecting the shut-in of production for more than three months and
cost saving initiatives. The increase in gross operating costs per barrel to
$5.6/bbl in the year (2022: $3.2/bbl) reflected the halving of annual
production. The Company expects unit costs will decrease with increased local
sales or the resumption of pipeline exports.
Despite non-recurring corporate costs of $2.1 million in the first half of
2023, Other G&A has decreased by $1.7 million in 2023 to $10.5 million due
principally to costs savings and the Remuneration Committee's decision at the
end of the year to not pay a bonus to staff.
After the shut-in of the Iraq-Turkey Pipeline, GKP significantly reduced
contractual commitments related to expansion activities and monetised certain
drilling inventory with the suspension of the continuous drilling programme.
As a result, the Company incurred a one-off expense of $9.6 million, included
in cost of sales, related to the cancellation and suspension of contracts and
loss on sale and write-down of inventory held for sale. $4.1 million of the
expense was non-cash.
Share option related expense in the year of $10.8 million primarily reflected
the vesting of the 2020 LTIP award, most of which was non-cash. The 22%
decrease versus the prior period (2022: $13.8 million) reflected the final
vesting of the Value Creation Plan ("VCP") in 2022.
Profit/(loss) after tax
The Company generated a loss after tax of $11.5 million (2022: profit after
tax of $266.1 million), including an increase in the expected credit loss
provision of $21.4 million (2022: $2.0 million) on overdue receivables from
the KRG for the months of October 2022 to March 2023 totalling $151 million,
net of capacity building payments, on the basis of the KBT pricing mechanism.
The Company continues to expect to recover the full value of overdue
receivables.
Cash flows
In 2023, GKP's revenue receipts were $109.2 million (2022: $450.4 million).
Prior to the suspension of exports, $65.7 million was received from the KRG
related to invoices for crude sold in August and September 2022, received in
January and March 2023 respectively. In H2 2023, $43.5 million was generated
from local sales, with advance payments received for all crude.
Net capital expenditure in the year was $58.2 million (2022: $114.9 million),
primarily reflecting works related to the suspended Jurassic reservoir
expansion project, including the completion of SH-17 and SH-18, well
workovers, well pad preparation, long lead items and the expansion of
production facilities. Net capex decreased 76% to $11.2 million in H2 2023
relative to H1 2023, reflecting the focus on safety-critical works and
recurring capex only.
The Company paid a $25 million interim dividend at the beginning of March
2023. Following the suspension of exports, the Board cancelled the proposed
final 2022 ordinary annual dividend of $25 million to preserve liquidity.
The reduction in net capex, combined with reductions to operating costs and
Other G&A, enabled the Company to reduce monthly expenditures to below $6
million in H2 2023. Cash generated by local sales in the period more than
covered expenditures while providing flexibility to reduce accounts payable,
comprised of trade payables and accrued expenditures, to $26.0 million as at
31 December 2023 (30 June 2023: $48.1 million).
The free cash outflow in the year of $13.1 million (2022 free cash flow of
$266.5 million), combined with the payment of the interim dividend of $25
million, resulted in a reduction of GKP's cash balance from $119.5 million at
31 December 2022 to $81.7 million at 31 December 2023.
The Group performed a cash flow and liquidity analysis, including the current
uncertainty over the timing of the pipeline reopening and settlement of
outstanding amounts due from the KRG, and the fact that the outlook for local
sales volumes and pricing cannot be predicted, based on which the Directors
have a reasonable expectation that the Group has adequate resources to
continue to operate for twelve months. Therefore, the going concern basis of
accounting is used to prepare the financial statements.
Net entitlement
The Company shares Shaikan Field revenues with the KRG and our partner MOL,
based on the terms of the Shaikan Production Sharing Contract. GKP's net
entitlement includes the recovery of our investment in the Shaikan Field
through cost oil and a share of the profits through profit oil, less a
Capacity Building Payment owed to the KRG. The Company's net entitlement of
gross Shaikan Field sales was 36% in 2023 and as at 31 December 2023.
The unrecovered cost oil and R-factor are used to calculate monthly cost oil
and profit oil entitlements, respectively, owed to the Company from crude oil
sales. As at 31 December 2023, there was $224 million of gross unrecovered
cost oil, subject to potential cost audit by the KRG. The R-factor, calculated
as cumulative gross revenue receipts of $2,219 million divided by cumulative
gross costs of $1,878 million, was 1.18.
Outlook
To date in 2024, gross average sales volumes have averaged c.33,300 bopd at an
average realised price of c.$25/bbl, enabling us to cover our monthly capex
and costs and pay all overdue invoices, resulting in a roughly halving of
accounts payable of $26 million that were outstanding at year-end.
Looking ahead to the remainder of 2024, the Company remains focused on
maximising local sales and minimising costs to further improve our liquidity
position.
We expect to maintain the aggregate net capex, operating costs and other
G&A monthly run rate at or below c.$6 million in 2024 and continue to
review further cost reduction opportunities. Estimated 2024 net capex of c.$20
million comprises safety critical upgrades and production maintenance
expenditures, while gross Opex per barrel guidance remains suspended. We
continue to retain the operational capability to maximise local sales and
capitalise on a resumption of exports.
We continue to believe the distribution of excess cash by way of dividends or
share buybacks is important to reward shareholders. As the operating
environment and the Company's liquidity position improve, we will keep under
review our capability to reinstate distributions.
Ian Weatherdon
Chief Financial Officer
20 March 2024
Non-IFRS measures
The Group uses certain measures to assess the financial performance of its
business. Some of these measures are termed "non-IFRS measures" because they
exclude amounts that are included in, or include amounts that are excluded
from, the most directly comparable measure calculated and presented in
accordance with IFRS, or are calculated using financial measures that are not
calculated in accordance with IFRS. These non‑IFRS measures include
financial measures such as operating costs and non-financial measures such as
gross average production.
The Group uses such measures to measure and monitor operating performance and
liquidity, and as a basis for strategic planning and forecasting. The
Directors believe that these and similar measures are used widely by certain
investors, securities analysts and other interested parties as supplemental
measures of performance and liquidity.
The non-IFRS measures may not be comparable to other similarly titled measures
used by other companies and have limitations as analytical tools and should
not be considered in isolation or as a substitute for analysis of the Group's
operating results as reported under IFRS. An explanation of the relevance of
each of the non-IFRS measures and a description of how they are calculated is
set out below. Additionally, a reconciliation of the non-IFRS measures to the
most directly comparable measures calculated and presented in accordance with
IFRS and a discussion of their limitations is set out below, where applicable.
The Group does not regard these non-IFRS measures as a substitute for, or
superior to, the equivalent measures calculated and presented in accordance
with IFRS or those calculated using financial measures that are calculated in
accordance with IFRS.
Gross operating costs per barrel
Gross operating costs are divided by gross production to arrive at operating
costs per barrel.
2023 2022
Gross production (MMbbls) 8.0 16.1
Gross operating costs ($ million)((1)) 45.1 52.3
Gross operating costs per barrel ($ per bbl) 5.6 3.2
((1) )Gross operating costs equate to operating costs (see note 3 to the
consolidated financial statements) adjusted for the Group's 80% working
interest in the Shaikan Field.
Adjusted EBITDA
Adjusted EBITDA is a useful indicator of the Group's profitability, which
excludes the impact of costs attributable to tax (expense)/credit, finance
costs, finance revenue, depreciation, amortisation and impairment of
receivables.
2023 2022
$ million $ million
(Loss)/profit after tax (11.5) 266.1
Finance costs 1.8 9.7
Finance revenue (3.8) (0.6)
Tax (charge)/credit 0.1 (0.3)
Depreciation of oil and gas assets 39.5 80.2
Depreciation of other PPE assets and amortisation of intangibles 2.6 1.4
Impairment of receivables 21.4 2.0
Adjusted EBITDA 50.1 358.5
Net cash
Net cash is a useful indicator of the Group's financial flexibility because it
indicates the level of cash and cash equivalents less cash borrowings within
the Group's business. Net cash is defined as cash less borrowings.
2023 2022
$ million $ million
Cash 81.7 119.5
Borrowings - -
Net cash 81.7 119.5
The Company was debt free at 31 December 2023 and 31 December 2022.
Net capital expenditure
Net capital expenditure is the value of the Group's additions to oil and gas
assets excluding the change in value of the decommissioning asset or any asset
impairment.
2023 2022
$ million $ million
Net capital expenditure (note 10 to the consolidated financial statements) 58.2 114.9
Free cash flow
Free cash flow represents the Group's cash flows, before any dividends, share
buybacks and notes redemption, including related fees.
2023 2022
$ million $ million
Net cash generated from operating activities 51.3 374.3
Net cash used in investing activities (63.9) (107.4)
Payment of leases (0.5) (0.4)
Free cash flow (13.1) 266.5
Consolidated income statement
For the year ended 31 December 2023
Notes 2023 2022
$'000 $'000
Revenue 2 (#_2_Revenue) 123,514 460,113
Cost of sales 3 (#_3_Cost_of) (93,953) (158,651)
Increase of expected credit loss provision on trade receivables 1 (#_14_Trade_and) 3 (21,378) (1,960)
Gross profit 8,183 299,502
Other general and administrative expenses 4 (#_4_General_and) (10,466) (12,202)
Share option related expenses 5 (#_5_Share_option) (10,760) (13,756)
(Loss)/profit from operations (13,043) 273,544
Finance income 7 (#_7_Finance_costs) 3,803 648
Finance costs 7 (#_7_Finance_costs) (1,765) (9,655)
Foreign exchange (loss)/gain (384) 1,232
(Loss)/profit before tax (11,389) 265,769
Tax (charge)/credit 8 (#_8_Income_tax) (111) 325
(Loss)/profit after tax for the year (11,500) 266,094
(Loss)/profit per share (cents)
Basic 9 (#_9_Profit/(loss)_per) (5.28) 123.52
Diluted 9 (#_9_Profit/(loss)_per) (5.28) 118.62
Consolidated statement of comprehensive income
For the year ended 31 December 2023
2023 2022
$'000 $'000
(Loss)/profit after tax for the year (11,500) 266,094
Items that may be reclassified to the income statement in subsequent periods:
Exchange gain/(loss) on translation of foreign operations 952 (1,950)
Total comprehensive (loss)/income for the year (10,548) 264,144
Consolidated balance sheet
As at 31 December 2023
Notes 31 December 2023 31 December 2022
$'000 $'000
Non-current assets
Trade receivables 13 140,218 -
Intangible assets 2,813 4,307
Property, plant and equipment 1 (#_11_Property,_plant) 0 445,842 436,443
Deferred tax asset 1 (#_18_Deferred_tax) 7 1,545 1,576
590,418 442,326
Current assets
Inventories 1 (#_13_Inventories) 2 9,901 6,372
Trade and other receivables 13 (#_14_Trade_and) 15,118 176,203
Cash 81,709 119,456
106,728 302,031
Total assets 697,146 744,357
Current liabilities
Trade and other payables 1 (#_154_Trade_and) 4 (109,394) (128,561)
Deferred income 14 (5,164) -
(114,558) (128,561)
Non-current liabilities
Trade and other payables 14 (#_154_Trade_and) (39) (325)
Provisions 1 (#_17_Provisions) 6 (35,312) (42,546)
(35,351) (42,871)
Total liabilities (149,909) (171,432)
Net assets 547,237 572,925
Equity
Share capital 19 222,443 216,247
Share premium 19 503,312 528,125
Exchange translation reserve (3,766) (4,718)
Accumulated losses (174,752) (166,729)
Total equity 547,237 572,925
The financial statements were approved by the Board of Directors and
authorised for issue on 20 March 2024 and signed on its behalf by:
Jon Harris
Chief Executive Officer
Ian Weatherdon
Chief Financial Officer
Consolidated statement of changes in equity
For the year ended 31 December 2023
Attributable to equity holders of the Company
Share Exchange translation reserve Accumulated losses Total
Share premium equity
capital
Notes
$'000 $'000 $'000 $'000 $'000
Balance at 1 January 2022 213,731 742,914 (2,768) (432,173) 521,704
Profit after tax for the year - - - 266,094 266,094
Exchange difference on translation of foreign operations - - (1,950) - (1,950)
Total comprehensive income for the year - - (1,950) 266,094 264,144
Dividends paid 2 (#_24_Dividend) 4 - (214,789) - - (214,789)
Employee share schemes 2 (#_23_Share-based_payments) 3 - - - 1,866 1,866
Share issues 19 2,516 - - (2,516) -
Balance at 31 December 2022 216,247 528,125 (4,718) (166,729) 572,925
Loss after tax for the year - - - (11,500) (11,500)
Exchange difference on translation of foreign operations - - 952 - 952
Total comprehensive loss for the year - - 952 (11,500) (10,548)
Dividends paid 24 (#_24_Dividend) - (24,813) - (24,813)
Employee share schemes 23 - - - 9,673 9,673
Share issues 19 6,196 - - (6,196) -
Balance at 31 December 2023 222,443 503,312 (3,766) (174,752) 547,237
Consolidated cash flow statement
For the year ended 31 December 2023
Notes 2023 2022
$'000 $'000
Operating activities
Cash generated from operations 2 (#_21_Cash_flow) 0 47,520 383,846
Interest received 7 (#_7_Finance_costs_1) 3,803 648
Interest paid 1 (#_7_Finance_costs_1) 5 - (10,194)
Net cash generated from operating activities 51,323 374,300
Investing activities
Purchase of intangible assets - (2,074)
Purchase of property, plant and equipment 2 (#_21_Cash_flow) 0 (65,386) (105,291)
Sale of drilling stock 1,449 -
Net cash used in investing activities (63,937) (107,365)
Financing activities
Payment of dividends 24 (24,813) (214,789)
Payment of leases 21 (503) (458)
Notes redemption 15 - (100,000)
Notes repayment fee 15 - (2,000)
Net cash used in financing activities (25,316) (317,247)
Net decrease in cash (37,930) (50,312)
Cash at beginning of year 119,456 169,866
Effect of foreign exchange rate changes 183 (98)
Cash at end of the year being bank balances and cash on hand 81,709 119,456
Summary of material accounting policies
General information
Gulf Keystone Petroleum Limited (the "Company") is domiciled and incorporated
in Bermuda (registered address: Cedar House, 3rd Floor, 41 Cedar Avenue,
Hamilton, HM12, Bermuda); together with its subsidiaries it forms the "Group".
On 25 March 2014, the Company's common shares were admitted, with a standard
listing, to the Official List of the United Kingdom Listing Authority ("UKLA")
and to trading on the London Stock Exchange's Main Market for listed
securities. Previously, the Company was quoted on Alternative Investment
Market, a market operated by the London Stock Exchange. The Company serves as
the holding company for the Group, which is engaged in oil and gas
exploration, development and production, operating in the Kurdistan Region of
Iraq.
The financial information set out in this results announcement does not
constitute the Company's annual report and accounts for the years ended 31
December 2022 or 2023 but is derived from those accounts. The auditors have
reported on those accounts; their reports were unqualified and did not draw
attention to any matters by way of emphasis without qualifying their report.
Amendments to International Financial Reporting Standards ("IFRS") that are
mandatorily effective for the current year
In the current year, the Group has applied a number of amendments to IFRS
issued by the International Accounting Standards Board (IASB) that are
mandatorily effective for an accounting period that begins on or after 1
January 2023.
The following new accounting standards, amendments to existing standards and
interpretations are effective on 1 January 2023: IFRS 17 Insurance Contracts,
Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS Practice
Statement 2), Definition of Accounting Estimates (Amendments to IAS 8),
Deferred Tax related to Assets and Liabilities arising from a Single
Transaction (Amendments to IAS 12), Initial Application of IFRS 17 and IFRS 9
- Comparative Information (Amendment to IFRS 17). These standards do not and
are not expected to have a material impact on the Company's results or
financials statement disclosures in the current or future reporting periods.
New and revised IFRSs issued but not yet effective
At the date of approval of these financial statements, the Group has not
applied the following new and revised IFRSs that have been issued but are not
yet effective by United Kingdom adopted International Accounting Standards:
IFRS S1 General Requirements for Disclosure of Sustainability-related Financial
Information
IFRS S2 Climate-related Disclosures
Amendments to IAS 1 Classification of Liabilities as Current or Non-current; Classification of
Liabilities as Current or Non-current - Deferral of Effective Date;
Non-current Liabilities with Covenants
Amendments to IFRS 16 Lease Liability in a Sale and Leaseback
Amendments to IAS 7 and IFRS 7 Qualitative and quantitative information about supplier finance
arrangements.
Amendments to IAS 21 Lack of Exchangeability: when a currency is exchangeable and how to
determine the exchange rate when it is not.
Amendments to the SASB standards Amendments to the SASB standards to enhance their international
applicability without substantially altering industries, topics or metrics
The directors do not expect that the adoption of the Standards listed above
will have a material impact on the financial statements of the Group in future
periods.
Statement of compliance
The financial statements have been prepared in accordance with United Kingdom
adopted International Accounting Standards.
Basis of accounting
The financial statements have been prepared using the going concern basis of
accounting and under the historical cost basis except for the valuation of
hydrocarbon inventory which has been measured at net realisable value and the
valuation of certain financial instruments which have been measured at fair
value. Equity-settled share-based payments are recognised at fair value at the
date of grant and are not subsequently revalued. The principal accounting
policies adopted are set out below.
Going concern
The Group's business activities, together with the factors likely to affect
its future development, performance and position, are set out in the
Chairman's statement, the Chief Executive Officer's review, the Operational
review and the Management of principal risks and uncertainties. The financial
position of the Group at the year end and its cash flows and liquidity
position are included in the Financial review.
As at 20 March 2024 the Group had $86 million of cash and no debt. The Group
continues to closely monitor and manage its liquidity. Cash forecasts are
regularly produced and sensitivities are run for different scenarios
including, but not limited, to changes in sales volumes, commodity price
fluctuations, timing of export pipeline restart, delays to revenue receipts
and cost optimisations. The Group remains focused on taking appropriate
actions to preserve its liquidity position.
As a result of closure of the ITP, the Group significantly reduced
expenditures to preserve liquidity. In the current year, further consideration
has been given to the impact on the Group's working capital position due to a
potential decline in local sales, and potential delays in KRG revenue receipts
once the ITP has been reopened:
· Local sales: The Group commenced local sales on 19 July 2023 with
payments from buyers required in advance following extensive due diligence. In
2023 the Group received $43.5m related to local sales. Local sales volumes
have fluctuated and remain difficult to predict, and
· Export sales: While political negotiations and commercial
negotiations are ongoing between the Government of Iraq and the KRG, the
timing of reopening the ITP and payment mechanism remain uncertain.
The Directors believe an agreement will ultimately be reached to reopen the
ITP, and we reasonably expect that overdue balances will be paid and receipts
from the KRG will return to a more regular basis. However, a reduction in
local sales or reopening of the pipeline with a deferral of revenue receipts
could result in liquidity pressures within the 12-month going concern period.
The Directors have considered sensitivities, including local sales volumes and
potential delays in KRG revenue receipts once the ITP reopens, to assess the
impact on the Group's liquidity position and believe sufficient mitigating
actions are available to withstand such impacts within the 12-month going
concern period. Specifically, the Directors considered stress tests that
included no further local sales or KRG revenue receipts and confirmed that
cost reduction opportunities exist to ensure that the Group can continue to
discharge its liabilities for a period of at least 12-months.
As explained in Note 14, although the Group has recognised current liabilities
of around $75 million payable to the KRG, it does not expect these will be
cash settled.
Overall, the Group's forecasts, taking into account the applicable risks,
stress test scenarios and potential mitigating actions, show that it has
sufficient financial resources for the 12 months from the date of approval of
the 2023 annual report and accounts.
Based on the analysis performed, the Directors have a reasonable expectation
that the Group has adequate resources to continue to operate for the
foreseeable future. Thus the going concern basis of accounting is used to
prepare the annual consolidated financial statements.
Basis of consolidation
The consolidated financial statements incorporate the financial statements of
the Company and enterprises controlled by the Company (its subsidiaries) made
up to 31 December each year. Control is achieved where the Company has the
power to govern the financial and operating policies of an investee entity, so
as to obtain benefits from its activities.
Joint arrangements
The Group is engaged in oil and gas exploration, development and production
through unincorporated joint arrangements; these are classified as joint
operations in accordance with IFRS 11. The Group accounts for its share of the
results and net assets of these joint operations. Where the Group acts as
Operator of the joint operation, the gross liabilities and receivables
(including amounts due to or from non-operating partners) of the joint
operation are included in the Group's balance sheet.
Sales revenue
The recognition of revenue is considered to be a key accounting judgement.
Revenue is earned based on the entitlement mechanism under the terms of the
Shaikan Production Sharing Contract ("PSC"). Entitlement has two components:
cost oil, which is the mechanism by which the Company recovers its costs
incurred, and profit oil, which is the mechanism through which profits are
shared between the Company, its partner and the Kurdistan Regional Government
("KRG"). The Company is liable for capacity building payments calculated as a
proportion of profit oil entitlement. Entitlement from cost oil and profit oil
are reported as revenue, and capacity building payments are included in cost
of sales.
Prior to the shut-in of the Iraq-Turkey pipeline ("ITP") on 25 March 2023, all
oil was sold by the Shaikan Contractor (the Company and Kalegran BV, a
subsidiary of MOL Hungarian Oil & Gas Plc, ("MOL")) to the KRG, who in
turn resold the oil. The selling price was determined in accordance with the
principles of the crude oil lifting agreement. On 19 July 2023, the Shaikan
Contractor commenced sales to the local market by restarting trucking
operations. The selling price is determined in accordance with crude sales
agreements with local customers.
Under IFRS 15: Revenue from contracts with customers, GKP considers that
control of crude oil is transferred from the Shaikan Contractor to the KRG or
local buyer at the delivery point as defined in the lifting agreement or crude
sales agreement; at this point the Shaikan Contractor is due economic benefits
which can be reliably measured and are probable to be received.
For sales up to the shut-in of the ITP on 25 March 2023, the delivery point
was the export pipeline and the consideration was variable and is dependent
upon the monthly average oil market price with deductions for quality and
transportation fees, with other fees and royalties due as determined by
commercial agreements; revenue was reported net of these deductions. For sales
to the local market from 19 July 2023, the delivery point is the point at
which crude oil is loaded into the buyers' nominated trucks. The consideration
is determined by reference to the crude sales agreement, with other fees and
royalties due as determined by commercial agreements; revenue is reported net
of these deductions.
Effective September 1, 2022, the KRG proposed a new pricing mechanism for
crude oil export sales, which continued in the year until 25 March 2023 when
the ITP was shut-in. Under the new pricing mechanism, the realised export
sales price for a month was based on the average market price realised by the
KRG for the Kurdistan blend (KBT) sold at Ceyhan, Turkey, as advised by the
KRG. The change in the benchmark market price from dated Brent to KBT has not
been agreed and no lifting agreement has been in place since 1 September 2022.
Nonetheless, the Shaikan Contractor continued production and the KRG accepted
delivery of oil at the delivery points. GKP considers that the control of
crude oil was transferred at the delivery points despite no commercial
agreement being in place and as such has recognised revenue, for the period
until 25 March 2023, based on the proposed new pricing terms. A summary of the
currently estimated financial impact of the proposed change in pricing
mechanism is detailed in note 2 to the consolidated financial statements.
Income tax arising from the Company's activities under its PSC is settled by
the KRG on behalf of the Company. Since the Company is not able to measure the
amount of income tax that has been paid on its behalf the notional income tax
amounts have not been included in revenue or in the tax charge.
Finance revenue
Finance income is recognised on an accruals basis, by reference to the
principal outstanding and at the effective rate of interest applicable, which
is the rate that exactly discounts estimated future cash receipts through the
expected life of the financial asset to that asset's net carrying amount on
initial recognition.
Intangible assets
Intangible assets include computer software and are measured at cost and
amortised over their expected useful economic lives of three years.
Property, plant and equipment ("PPE")
Oil and gas assets
Development and production assets
Development and production assets are accumulated on a field-by-field basis
and represent the costs of acquisition and developing the commercial reserves
discovered and bringing them into production, together with the exploration
and evaluation expenditure incurred in finding commercial reserves, directly
attributable overheads and costs for future restoration and decommissioning.
These costs are capitalised as part of PPE and depreciated based on the
Group's depreciation of oil and gas assets policy.
The net book values of producing assets are depreciated generally on a
field-by-field basis using the unit of production ("UOP") basis which uses the
ratio of oil and gas production in the period to the remaining commercial
reserves plus the production in the period. Costs used in the calculation
comprise the net book value of the field and estimated future development
expenditures required to produce those reserves.
Commercial reserves are proven and probable ("2P") reserves which are
estimated using standard recognised evaluation techniques. The reserves
estimate used in the depreciation, depletion and amortisation ("DD&A")
calculation in 2023 was based on the December 2022 Competent Person's Report
("CPR") reserves report completed by ERC Equipoise as at 31 December 2022.
Other property, plant and equipment
Other property, plant and equipment are principally equipment used in the
field which are separately identifiable to development and production assets,
and typically have a shorter useful economic life. Assets are carried at cost,
less any accumulated depreciation and accumulated impairment losses. Costs
include purchase price, construction and installation costs.
These assets are expensed on a straight-line basis over their estimated useful
lives of three-years from the date they are put in use.
Fixtures and equipment
Fixtures and equipment assets are stated at cost less accumulated depreciation
and any accumulated impairment losses. These assets are expensed on a
straight-line basis over their estimated useful lives of five-years from the
date they are available for use.
Impairment of PPE and intangible non-current assets
At each balance sheet date, the Group reviews the carrying amounts of its
tangible and intangible assets to determine whether there is any indication
that those assets have suffered an impairment loss. If any such indication
exists, the recoverable amount of the asset, or group of assets, is estimated
in order to determine the extent of the impairment loss (if any).
For assets which do not generate cash flows that are independent from other
assets, the Group estimates the recoverable amount of the cash-generating unit
to which the asset belongs.
Recoverable amount is the higher of fair value less costs to sell ("FVLCTS")
and value in use. In assessing FVLCTS and value in use, the estimated future
cash flows are discounted to their present value using a post-tax discount
rate that reflects current market assessments of the time value of money and
the risks specific to the asset for which the estimates of future cash flows
have not been adjusted.
Any impairment identified is immediately recognised as an expense. Conversely,
any reversal of an impairment is immediately recognised as income.
Borrowing costs
Borrowing costs directly relating to the acquisition or construction of
qualifying assets, which are assets that necessarily take a substantial period
of time to get ready for their intended use or sale, are capitalised and added
to the cost of those assets, until such time as the assets are substantially
ready for their intended use or sale.
Investment income earned on the temporary investment of specific borrowings
pending their expenditure on qualifying assets is deducted from the borrowing
costs eligible for capitalisation.
All other borrowing costs are recognised in the income statement in the period
in which they are incurred.
Taxation
Tax expense or credit represents the sum of tax currently payable or
recoverable and deferred tax.
Tax currently payable or recoverable is based on taxable profit or loss for
the year. Current tax assets and liabilities are measured at the amount
expected to be recovered from or paid to the taxation authorities, based on
tax rates and laws that are enacted or substantively enacted by the balance
sheet date.
As described in the revenue accounting policy section above, it is not
possible to calculate the amount of notional tax in relation to any tax
liabilities settled on behalf of the Group by the KRG.
Deferred tax is the tax expected to be payable or recoverable on differences
between the carrying amounts of assets and liabilities in the financial
statements and the corresponding tax bases used in the computation of taxable
profit and is accounted for using the balance sheet liability method. Deferred
tax liabilities are generally recognised for all taxable temporary differences
and deferred tax assets are recognised to the extent that it is probable that
future taxable profits will be available against which deductible temporary
differences can be utilised. Such assets and liabilities are not recognised if
the temporary difference arises from the initial recognition of goodwill or
from the initial recognition of other assets and liabilities in a transaction
that affects neither the taxable profit nor the accounting profit and does not
give rise to equal taxable and deductible temporary differences.
The carrying amount of deferred tax assets is reviewed at each balance sheet
date and reduced to the extent that it is no longer probable that sufficient
future taxable profits will be available to allow all or part assets to be
recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the
period when the liability is settled or the asset is realised based on tax
laws and rates that have been enacted or substantively enacted by the balance
sheet date. Deferred tax is charged or credited in the income statement,
except when it relates to items charged or credited directly to equity, in
which case the deferred tax is also recognised in equity.
Foreign currencies
The individual financial statements of each company are presented in the
currency of the primary economic environment in which it operates (its
functional currency). For the purpose of the consolidated financial
statements, the results and the financial position of the Group are expressed
in US dollars, which is the presentation currency for the consolidated
financial statements.
In preparing the financial statements of the individual companies,
transactions in currencies other than the entity's functional currency are
recorded at the rates of exchange prevailing on the dates of the transactions.
At each balance sheet date, monetary assets and liabilities that are
denominated in foreign currencies are retranslated at the rates prevailing on
the balance sheet date. Non-monetary assets and liabilities carried at fair
value that are denominated in foreign currencies are translated at the rates
prevailing at the date when the fair value was determined. Gains and losses
arising on retranslation are included in the income statement for the year.
On consolidation, the assets and liabilities of the Group's foreign operations
which use functional currencies other than US dollars are translated at
exchange rates prevailing on the balance sheet date. Income and expense items
are translated at the average exchange rates for the period. Exchange
differences arising, if any, are recognised in other comprehensive income and
accumulated in equity in the Group's translation reserve. On the disposal of a
foreign operation, such translation differences are reclassified to profit or
loss.
Inventories
Inventories, except for hydrocarbon inventories, are stated at the lower of
cost and net realisable value. Cost comprises direct materials and, where
applicable, direct labour costs and those overheads that have been incurred in
bringing the inventories to their present location and condition. Cost is
calculated using the weighted average cost method. Hydrocarbon inventories are
recorded at net realisable value with changes in the value of hydrocarbon
inventories being adjusted through cost of sales.
Financial instruments
Financial assets and financial liabilities are recognised on the Group's
balance sheet when the Group has become a party to the contractual provisions
of the instrument.
Trade receivables
Trade receivables are measured at amortised cost using the effective interest
method less any impairment.
Cash
Cash comprises cash on hand and demand deposits that are not subject to a risk
of changes in value other than foreign exchange gain or loss.
Impairment of financial assets
The Group recognises a loss allowance for expected credit losses ("ECL") on
trade receivables and contract assets, as well as on financial guarantee
contracts. The amount of expected credit losses is updated at each reporting
date to reflect changes in credit risk since initial recognition of the
respective financial instrument.
The Group recognises lifetime expected credit losses for trade receivables,
contract assets and lease receivables. The expected credit losses on these
financial assets are estimated based on observed market data and convention,
existing market conditions and forward-looking estimates at the end of each
reporting period.
For all other financial instruments, the Group recognises lifetime ECL when
there has been a significant increase in credit risk since initial
recognition. However, if the credit risk on the financial instrument has not
increased significantly since initial recognition, the Group measures the loss
allowance for that financial instrument at an amount equal to 12-month ECL.
Lifetime ECL represents the expected credit losses that will result from all
possible default events over the expected life of a financial instrument. In
contrast, 12-month ECL represents the portion of lifetime ECL that is expected
to result from default events on a financial instrument that are possible
within 12 months after the reporting date.
Financial liabilities and equity
Financial liabilities and equity instruments are classified according to the
substance of the contractual arrangements entered into. An equity instrument
is any contract that evidences a residual interest in the assets of the Group
after deducting all of its liabilities.
Equity instruments
Equity instruments issued by the Company are recorded at the proceeds
received, net of direct issue costs, which are charged to share premium.
Borrowings
Interest-bearing loans and overdrafts are recorded at the fair value of
proceeds received, net of transaction costs. Finance charges, including
premiums payable on settlement or redemption, are accounted for on an accrual
basis and are added to the carrying amount of the instrument to the extent
that they are not settled in the year in which they arise. The liability is
carried at amortised cost using the effective interest rate method until
maturity.
Trade payables
Trade payables are stated at amortised cost.
Provisions
Provisions are recognised when the Group has a present obligation as a result
of a past event which it is probable will result in an outflow of economic
benefits that can be reliably estimated.
Decommissioning provision
Provision for decommissioning is recognised in full when there is an
obligation to restore the site to its original condition. The amount
recognised is the present value of the estimated future expenditure for
restoring the sites of drilled wells and related facilities to their original
status. A corresponding amount equivalent to the provision is also recognised
as part of the cost of the related oil and gas asset. The amount recognised is
reassessed each year in accordance with local conditions and requirements. Any
change in the present value of the estimated expenditure is dealt with
prospectively. The unwinding of the discount is included as a finance cost.
Share-based payments
Equity-settled share-based payments to employees and others providing similar
services are measured at the fair value of the instruments at the grant date.
Details regarding the determination of the fair value of equity-settled
share-based transactions are set out in note 24 (#_23_Share-based_payments) .
The fair value determined at the grant date of the equity-settled share-based
payments is expensed on a straight-line basis over the vesting period, based
on the Group's estimate of equity instruments that will eventually vest. At
each balance sheet date, the Group revises its estimate of the number of
equity instruments expected to vest as a result of the effect of non-market
based vesting conditions. The impact of the revision of the original
estimates, if any, is recognised in profit or loss such that the cumulative
expense reflects the revised estimate, with a corresponding adjustment to
equity reserve.
For cash-settled share-based payments, a liability is recognised for the goods
or services acquired, measured initially at the fair value of the liability.
At each balance sheet date until the liability is settled, and at the date of
settlement, the fair value of the liability is re-measured, with any changes
in fair value recognised in profit or loss for the period. Details regarding
the determination of the fair value of cash-settled share-based transactions
are set out in note 24 (#_23_Share-based_payments) .
Leases
The Group assesses whether a contract contains a lease at inception of the
contract. The Group recognises a right-of-use asset and corresponding lease
liability in the consolidated balance sheet for all lease arrangements longer
than twelve months, where it is the lessee and has control of the asset. For
all other leases, the Group recognises the lease payments as an operating
expense on a straight-line basis over the term of the lease.
The lease liability is initially measured at the present value of the future
lease payments from the commencement date of the lease. The lease payments are
discounted using the interest rate implicit in the lease or, if not readily
determinable, the company specific incremental borrowing rate.
The lease liability is subsequently measured by increasing the carrying amount
to reflect interest on the lease liability (using the effective interest
method) and by reducing the carrying amount to reflect the lease payments
made. The lease liability is recognised in creditors as current or non-current
liabilities depending on underlying lease terms.
The right-of-use assets are initially recognised on the balance sheet at cost,
which comprises the amount of the initial measurement of the corresponding
lease liability, adjusted for any lease payments made at or prior to the
commencement date of the lease and any lease incentive received.
For short-term leases (periods less than 12 months) and leases of low value,
the Group has opted to recognise lease expense on a straight-line basis.
Critical accounting judgements and key sources of estimation uncertainty
In the application of the accounting policies described above, the Group is
required to make judgements, estimates and assumptions about the carrying
amounts of assets and liabilities that are not readily apparent from other
sources. The estimates and associated assumptions are based on historical
experience and other factors that are considered to be relevant. Actual
results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis.
Revisions to accounting estimates are recognised in the period in which the
estimate is revised if the revision affects only that period or in the period
of revision and future periods if the revision affects both current and future
periods.
Critical judgements in applying the Group's accounting policies
The following are the critical judgements, apart from those involving
estimations (which are presented separately below), that the directors have
made in the process of applying the Group's accounting policies and that have
the most significant effect on the amounts recognised in financial statements.
PSC entitlement: Revenue and capacity building payments
The recognition of revenue, particularly the recognition of revenue from
pipeline exports, is considered to be a key accounting judgement. The Group
began commercial production from the Shaikan Field in July 2013 and
historically made sales to both the domestic and export markets. The Group
considers that revenue can be reliably measured as it passes the delivery
point into the export pipeline or truck, as appropriate. The critical
accounting judgement applied in preparing the 2023 financial statements is
that it is appropriate to recognise export revenue for deliveries from 1
January to 25 March 2023 based on the proposed new pricing mechanism,
notwithstanding that there is no signed lifting agreement for that period and
the pricing mechanism has not yet been agreed. Further details of this
judgement are provided in the sales revenue accounting policy above. In making
this judgement, consideration was given to the fact that the Group received
payment for September 2022 deliveries at an amount that was consistent with
the proposed new pricing terms; no further receipts for the period of pipeline
exports from 1 October 2022 to 25 March 2023 have been received.
A summary of the currently estimated financial impact of the proposed change
in pricing mechanism is detailed in Note 2.
Any future agreements between the Company and the KRG might change the amounts
of revenue recognised.
During past PSC negotiations with the Ministry of Natural Resources ("MNR"),
it was tentatively agreed that the Shaikan Contractor would provide the KRG a
20% carried working interest in the PSC. This would result in a reduction of
GKP's working interest from 80% to 61.5%. To compensate for such decrease,
capacity building payments expense would be reduced to 20% of profit
petroleum. While the PSC has not been formally amended, it was agreed that
GKP would invoice the KRG for oil sales based on the proposed revised terms
from October 2017. The financial statements reflect the proposed revised
working interest of 61.5%. Relative to the PSC terms, the proposed revised
invoicing terms result in a decrease in both revenue and cost of sales and on
a net basis are slightly positive for the Company.
As part of earlier PSC negotiations, on 16 March 2016, GKP signed a bilateral
agreement with the MNR (the "Bilateral Agreement"). The Bilateral Agreement
included a reduction in the Group's capacity building payment from 40% to 30%
of profit petroleum. Subsequent to signing the Bilateral Agreement, further
negotiations resulted in the capacity building payment rate being reduced from
30% to 20%, which has formed the basis for all oil sales invoices to date as
noted above. Since PSC negotiations have not been finalised, GKP has included
a non-cash payable for the difference between the capacity building rate of
20% and 30%, which is recognised in cost of sales and other payables.
The Company expects to confirm with the MNR whether to proceed with a formal
amendment to the PSC to reflect current invoice terms.
Key sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation
uncertainty at the reporting period that may have a significant risk of
causing a material adjustment to the carrying amounts of assets and
liabilities within the next financial year, are discussed below.
Expected credit loss ("ECL")
The recoverability of receivables is a key accounting judgement. The
difference between the nominal value of receivables and the expected value of
receivables after allowing for counterparty default risk gives the ECL. In
making this judgement, management has estimated the timing of the receipt of
receivables which will be dependent upon uncertain future events, in
particular the expected timing of the re-opening of the ITP. Management have
considered scenarios for recovering receivables and assigned probabilities to
these scenarios. A weighted average has been applied to receipt profiles, upon
which a counterparty default allowance has been applied to derive the ECL.
This ECL is offset against current and non-current receivable amounts as
appropriate within the balance sheet with the change in the receivable balance
during the period recognised in the income statement.
Decommissioning provision
Decommissioning provisions are estimated based upon the obligations and costs
to be incurred in accordance with the PSC at the end of field life in 2043.
There is uncertainty in the decommissioning estimate due to factors including
potential changes to the cost of activities, potential emergence of new
techniques or changes to best practice. The Company commissioned ERC Equipoise
to perform an assessment of the Company's estimate of the current value of
such obligations and costs at 31 December 2023 (2022: internal estimate).
Management have increased these costs by estimated compound interest rates, to
future value in 2043, and reduced to present value by an estimated discount
rate (note 16), there is also uncertainty regarding the inflation and discount
rates used.
Carrying value of producing assets
In line with the Group's accounting policy on impairment, management performs
an impairment review of the Group's oil and gas assets at least annually with
reference to indicators as set out in IAS 36. The Group assesses its group of
assets, called a cash-generating unit ("CGU"), for impairment, if events or
changes in circumstances indicate that the carrying amount of an asset may not
be recoverable. Where indicators are present, management calculates the
recoverable amount using key estimates such as future oil prices, PSC
commercial terms, cost recovery, estimated production volumes, the timing of
revenue receipts and field development activities, the cost of development and
production, potential climate change transition risk impacts, pre-tax discount
rate that incorporate risks specific to the asset and inflation. The key
assumptions are subject to change based on geopolitical factors, market trends
and economic conditions. Where the CGU's recoverable amount is lower than the
carrying amount, the CGU is considered impaired and is written down to its
recoverable amount.
The Group's sole CGU at 31 December 2023 was the Shaikan Field with a carrying
value, being Oil and Gas assets less capitalised decommissioning provision, of
$408.0 million (2022: $391.0 million). The Group performed an impairment
trigger assessment and concluded that the shutdown of the Iraq Turkey Pipeline
("ITP") in March 2023 following the ITP Arbitration ruling was a potential
indicator of impairment. Accordingly, an impairment evaluation was completed,
and it was concluded that no impairment write-down was required.
In accordance with accounting standards, the impairment assessment was
prepared based on available information combined with management estimates as
at 31 December 2023. This includes a number of key assumptions, some of which
have a high degree of uncertainty. The key areas of estimation in assessing
the potential impairment indicators are as follows:
· While the date of the re-opening of the ITP remains uncertain, the
impairment calculation base case assumes that local sales contracts, whilst
short-term in nature, will continue until the ITP reopens and exports resume
in October 2024. Given the reopening date remains uncertain, we have applied
sensitivities of up to a further two-year delay in the re-opening of the ITP
and no impairment was identified except under the Net Zero Emissions climate
scenario as described below;
· The Group's netback oil price was based on the forward curve and
market participants' consensus, including banks, analysts and independent
reserves evaluators, as at 31 December 2023 for the period 2024 to 2029 with
inflation of 2.25% per annum thereafter, less transportation costs and quality
adjustments. Prices at 31 December 2022 were based on the dated brent forward
curve as at December 2022 for the period 2023 to 2028 with inflation of 2% per
annum thereafter, less transportation and quality adjustments. The stress case
reflects a 10% reduction in base case oil prices;
Scenario ($/bbl - nominal) 2023 2024 2025 2026 2027 2028 2029
31 December 2023 - base case n/a 83.0 80.0 77.0 77.0 77.0 80.0
31 December 2023 - stress case n/a 74.7 72.0 69.3 69.3 69.3 72.0
31 December 2022 - base case 83.4 78.2 74.5 71.7 69.6 68.1 69.5
31 December 2022 - stress case 75.1 70.4 67.1 64.5 62.6 61.3 62.5
· Cost assumptions used in the assessment were based on an updated
Jurassic development plan commencing in 2025 and the estimated cost of a Gas
Management Plan with investment commencing in 2026. Further development
remains contingent upon the reopening of the ITP and normalisation of KRG
payments. Cost assumptions incorporated management's experience and
expectations, including the nature and location of the operations and the
associated risks. The impact of near-term inflationary pressures were also
considered and no impairment was identified;
· The Group continues to develop its assessment of the potential
impacts of climate change and the associated risks of the transition to a
low‑carbon future. Our ambition to reduce scope one per barrel CO(2)
emissions by at least 50% versus the original 2020 baseline of 38 kgCO(2)e per
barrel is dependent on the timing of sanction and implementation of the Gas
Management Plan. The International Energy Agency's ("IEA") most recent
Announced Pledges Scenario ("APS") and Net Zero Emissions ("NZE") climate
scenario oil prices and carbon taxes were used to evaluate the potential
impact of the principal climate change transition risks. The APS scenario
assumes that governments will meet, in full and on time, all of the
climate‑related commitments that they have announced, including longer term
net zero emissions targets and pledges in Nationally Determined Contributions
("NDCs") to reduce national emissions and adapt to the impacts of climate
change leading to a global temperature rise of 1.7°C in 2100. NZE is the
normative scenario pathway to the stabilisation of global average temperatures
at 1.5°C above pre‑industrial levels. Under the APS and NZE scenarios there
was no impairment. However, while the IEA oil price assumptions incorporate
carbon prices, it has not disclosed the assumed average carbon intensity per
barrel of production. Therefore, the Group has performed a sensitivity to
conservatively include IEA carbon pricing on all production which results in
no impairment under the APS scenario. Under the NZE scenario, there was a
potential impairment; however, if the Group's assumed future average carbon
intensity per barrel of production is in fact at or below the undisclosed IEA
carbon intensity per barrel of production, there would have been no
impairment;
· Discount rates that are adjusted to reflect risks specific to the
Shaikan Field and the Kurdistan Region of Iraq. The post-tax nominal discount
rate was estimated to be 16% (2022: 15%). The impact of an increase in
discount rate to 20% was considered as a sensitivity to reflect potential
increased geopolitical risks and no impairment was identified;
· Commercial reserves and production profiles used are based on
internal estimates; and
· Timing of revenue receipts.
Notes to the consolidated financial statements
1. Geographical information
The Chief Operating Decision Maker, as per the definition in IFRS 8, is
considered to be the Board of Directors. The Group operates in a single
segment, that of oil and gas exploration, development and production, in a
single geographical location, the Kurdistan Region of Iraq ("KRI"); 100%
(2022: 99%) of the group's non-current assets, excluding deferred tax assets
and other financial assets, are located in the KRI. The financial information
of the single segment is materially the same as set out in the condensed
consolidated statement of comprehensive income, the condensed consolidated
balance sheet, the condensed consolidated statement of changes in equity, the
condensed consolidated cash flow statement and the related notes.
2. Revenue
2023 2022
$'000 $'000
Oil sales via export pipeline 78,955 460,113
Local oil sales 44,559 -
123,514 460,113
The Group's accounting policy for revenue recognition is set out in the
'Summary of significant accounting policies', with revenue recognised upon
crude oil passing the delivery points, either being entry into pipeline or
delivered into trucks.
Oil sales via export pipeline (until 25 March 2023)
The International Court of Arbitration in Paris ruled on the long running ITP
arbitration case in Iraq's favour, which led to the shut-in of the ITP on 25
March 2023. Negotiations are ongoing to reopen the pipeline.
Since 1 September 2022, there has been no lifting agreement in place between
the Shaikan Contractor and the KRG. The KRG proposed a new pricing mechanism
based upon the average monthly Kurdistan blend ("KBT") sales price realised by
the KRG at Ceyhan; formerly the pricing mechanism was based upon Dated Brent.
The Company has not accepted the proposed contract modification and continued,
until suspension of the export pipeline, to invoice the KRG for oil sales
based on the pre-1 September 2022 pricing formula. Considering the uncertainty
with respect to the variable consideration within the pricing mechanism, the
Company has concluded that it is an appropriate judgement to recognise revenue
based on the proposed contract modification for the period to the pipeline
shutdown on 25 March 2023.
Export sales covering the period from 1 January to 25 March 2023 were based
upon the monthly Kurdistan blend ("KBT") price. The realised price in this
period was $51.3/bbl (2022: full year $84.3/bbl).
The revenue impact of using the proposed KBT pricing mechanism instead of
Dated Brent for the year is estimated to be a reduction of $12.0 million
(2022: $23.4 million). Taking into account the associated reduction in
capacity building payments results in a total reduction of profit after tax
for the year of $11.4 million (2022: $21.7 million). Any difference between
the proposed and final pricing mechanism will be reflected in future periods.
Local oil sales (from 19 July 2023)
In July 2023, GKP began selling oil to local buyers at negotiated prices. The
realised price achieved in 2023 was $30/bbl (2022: not applicable). Local
buyers pay GKP in advance of receipt of oil; such amounts are recognised as
deferred income (see note 14).
Information about major customers
In 2023, 68% (2022: 100%) of oil sales were made to the KRG. Additionally, 31%
of revenue (2022: 0%) was attributable to three local customers comprising
10%, 10% and 11% of revenue individually.
3. Cost of sales
2023 2022
$'000 $'000
Operating costs 36,082 41,835
Capacity building payments 8,872 34,927
Change in oil inventory value (75) 555
Depreciation of oil and gas assets and operational assets 39,470 80,225
Contract termination costs 5,525 -
Provision against inventory held for sale 2,627 -
Loss on disposal of drilling stock 1,452 -
Impairment of surplus drilling stock - 1,109
93,953 158,651
Capacity building payments have been recorded in line with the proposed
pricing mechanism (see note 2); any difference between the proposed and final
pricing mechanism will be reflected in future periods.
Further details on the depreciation of oil and gas assets and operational
assets, as well as the recognition of capacity building payments, are set out
in the Summary of significant accounting policies section.
For purposes of calculating the DD&A per barrel of production in 2023, a
Competent Person's Report from ERC Equipoise Limited with 2P reserves
estimates at 31 December 2022 was used in conjunction with the Group's
economic forecasts to determine entitlement production, commercial reserves
and capital costs for Shaikan.
Following ITP shut-in, GKP reacted quickly to preserve liquidity and
significantly reduce expenditures. This led to the termination of certain
contracts, drilling stock sales less than carrying value and a provision for
inventory items held for sale.
4. Other general and administrative expenses
2023 2022
$'000
$'000
Depreciation and amortisation 2,652 1,563
Auditor's remuneration (see below) 635 703
Other general and administrative costs 7,179 9,936
10,466 12,202
Of the $10.5 million (2022: $12.2 million) of general and administrative
expenses, $3.4 million (2022: $5.2 million) were incurred in relation to the
Shaikan Field.
2023 2022
$'000 $'000
Fees payable to the Company's auditor for the audit of the Company's annual 474 430
accounts
Fees payable to the Company's auditor for other services to the Group
- audit of the Company's subsidiaries pursuant to legislation 26 26
Total audit fees 500 456
Advisory services - 112
Other assurance services (including a half year review) 135 135
Total fees 635 703
5. Share option related expense
2023 2022
$'000 $'000
Share-based payment expense 9,673 3,266
Payments related to share options exercised 797 8,690
Share-based payment related provision for taxes 290 1,800
10,760 13,756
The 2022 payments related to share options exercised includes the final year
of the legacy Value Creation Plan ("VCP") share options awarded to former
Directors. There will be no further awards under the plan.
6. Staff costs
The average number of employees and contractors (including Executive
directors) employed by the Group was 471 (2022: 460); the number of full-time
equivalents of these workers was 303 (2022: 317), reflecting the increase in
staff in 2022 to progress expansion activities and the decrease in staff after
the ITP was shut-in on 25 March 2023.
Average number of employees Average number of full-time equivalents Number of employees Number of full-time equivalents in December
in December
2023 2022 2023 2022 2023 2022 2023 2022
Kurdistan 438 421 272 280 379 472 247 312
United Kingdom 33 39 31 37 27 40 26 38
Total 471 460 303 317 406 512 273 350
Staff costs as follows are shown net of amounts recharged to joint operations:
2023 2022
$'000 $'000
Wages and salaries 37,645 46,879
Social security costs 1,826 2,503
Pension costs 468 420
Share-based payment (see note 2 (#_23_Share-based_payments) 3) 10,760 4,260
50,699 54,062
Staff costs include costs relating to contractors who are long-term workers in
key positions and are included in PPE additions, cost of sales and other
general and administrative expenditure depending on the nature of such costs.
Staff costs are shown net of amounts recharged to joint operations.
7. Finance costs and finance income
2023 2022
$'000 $'000
Notes interest expense (see note 15 (#_156_Long_term) ) - (5,833)
Unwinding of finance and arrangement fees (see note 15 (#_156_Long_term) ) - (879)
Notes repayment fee (see note 15) - (2,000)
Finance lease interest (66) (77)
Unwinding of discount on provisions (see note 16 (#_167_Provisions) ) (1,699) (866)
Total finance costs (1,765) (9,655)
Finance income 3,803 648
Net finance income/(costs) 2,038 (9,007)
Since redemption of $100m notes on 2 August 2022, the Group has remained debt
free (see note 15).
8. Income tax
2023 2022
$'000 $'000
Current year credit - 216
Prior year adjustment 195 -
Deferred UK corporation tax (charge)/credit (see note 17 (#_17_Deferred_tax) ) (306) 109
Tax (charge)/credit attributable to the Company and its subsidiaries (111) 325
The Group is not required to pay taxes in Bermuda on either income or capital
gains. The Group has received an undertaking from the Minister of Finance in
Bermuda exempting it from any such taxes at least until the year 2035.
In the KRI, the Group is subject to corporate income tax on its income from
petroleum operations under the Kurdistan PSC. Under the Shaikan PSC, any
corporate income tax arising from petroleum operations will be paid from the
KRG's share of petroleum profits. Due to the uncertainty over the payment
mechanism for oil sales in Kurdistan, it has not been possible to measure
reliably the taxation due that has been paid on behalf of the Group by the KRG
and therefore the notional tax amounts have not been included in revenue or in
the tax charge. This is an accounting presentational issue and there is no
taxation to be paid.
The annual UK corporation tax rate for the year ended 31 December 2023 was 19%
on profits up to £50k tapered to 25% on profits above £250k (2022: flat rate
of 19.0%).
Deferred tax is provided for due to the temporary differences, which give rise
to such a balance in jurisdictions subject to income tax. All deferred tax
arises in the UK.
9. Earnings per share
The calculation of the basic and diluted loss per share is based on the
following data:
2023 2022
(Loss)/profit after tax for basic and diluted per share calculations ($'000) (11,500) 266,094
Number of shares ('000s):
Basic weighted average number of ordinary shares 217,992 215,420
Basic EPS (cents) (5.28) 123.52
The Group followed the steps specified by IAS 33 in determining whether
potential common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
2023 2022
Number of shares ('000s)
Basic weighted average number of ordinary shares outstanding 217,992 215,420
Effect of potential dilutive share options - 8,909
Diluted number of ordinary shares outstanding 217,992 224,329
Diluted EPS (cents)((1)) (5.28) 118.62
((1)) At the reporting date, the Company had 8,224k antidilutive (2022: 8,909k
dilutive) ordinary shares relating to outstanding share options. EPS is
calculated on the assumption of conversion of all potentially dilutive
ordinary shares however, during a period where a company makes a loss,
anti-dilutive shares are not included in the loss per share calculation as
they would reduce the reported loss per share.
The weighted average number of ordinary shares in issue excludes shares held
by Employee Benefit Trustee ("EBT").
10. Property, plant and equipment
Oil and gas Fixtures and Right of use assets Total
assets equipment $'000
$'000 $'000
$'000
Year ended 31 December 2022
Opening net book value 402,094 1,033 1,078 404,205
Additions 114,909 1,595 - 116,504
Impairment of surplus drilling stocks (1,109) - - (1,109)
Revision to decommissioning asset (2,161) - - (2,161)
Depreciation charge (80,177) (359) (347) (80,883)
Foreign currency translation differences - (12) (101) (113)
Closing net book value 433,556 2,257 630 436,443
At 31 December 2022
Cost 943,563 8,946 2,145 954,654
Accumulated depreciation (510,007) (6,689) (1,515) (518,211)
Net book value 433,556 2,257 630 436,443
Year ended 31 December 2023
Opening net book value 433,556 2,257 630 436,443
Additions 58,240 453 86 58,779
Disposals' cost - - (70) (70)
Revision to decommissioning asset (8,933) - - (8,933)
Depreciation charge (39,470) (649) (356) (40,475)
Disposals' depreciation - - 66 66
Foreign currency translation differences - 5 27 32
Closing net book value 443,393 2,066 383 445,842
At 31 December 2023
Cost 992,870 9,404 2,188 1,004,462
Accumulated depreciation (549,477) (7,338) (1,805) (558,620)
Net book value 443,393 2,066 383 445,842
The net book value of oil and gas assets at 31 December 2023 is comprised of
property, plant and equipment relating to the Shaikan block with a carrying
value of $443.4 million (2022: $433.6 million).
The additions to the Shaikan asset amounting to $58.2 million during the year
include the costs of completing SH-17 and the drilling and completion of
SH-18, well workovers, well pad preparation, long lead items and expansion of
production facilities.
The decrease in the decommissioning asset represents the change in accounting
estimates as detailed in note 16 partially offset by additional
decommissioning liabilities arising from capital projects completed during the
year.
The DD&A charge of $39.5 million (2022: $80.2 million) on oil and gas
assets has been included within cost of sales (note 3 (#_3_Cost_of) ). The
depreciation charge of $0.6 million (2022: $0.4 million) on fixtures and
equipment and $0.4 million (2022: $0.3 million) on right of use assets has
been included in general and administrative expenses (note 4
(#_4_Other_general) ).
Right of use assets at 31 December 2023 of $0.4 million (2022: $0.6 million)
consisted principally of buildings.
For details of the key assumptions and judgements underlying the impairment
assessment, refer to the "Critical accounting estimates and judgements"
section of the Summary of significant accounting policies.
11. Group companies
Details of the Company's subsidiaries and joint operations at 31 December 2023
is as follows:
Name of subsidiary Place of incorporation Proportion of ownership interest Principal
activity
Gulf Keystone Petroleum (UK) Limited United Kingdom 100% Management, support, geological, geophysical and engineering services
6(th) floor
New Fetter Place
8-10 New Fetter Lane
London EC4A 1AZ
Gulf Keystone Petroleum International Limited Bermuda 100% Exploration, evaluation, development and production activities in Kurdistan
Cedar House, 3(rd) Floor
41 Cedar Avenue
Hamilton HM12
Bermuda
Name of joint operation Location Proportion of ownership interest Principal
activity
Shaikan Kurdistan 80% Production and development activities
12. Inventories
2023 2022
$'000 $'000
Warehouse stocks and materials 6,900 6,074
Crude oil 374 298
Inventory held for sale 2,627 -
9,901 6,372
13. Trade and other receivables
Non-current receivables
2023 2022
$'000 $'000
Trade receivables - non-current 140,218 -
Non-current trade receivables relates to overdue amounts due from the KRG,
after deducting the expected credit loss, that are expected to be received
more than 12 months from the reporting date (see below).
Current receivables
2023 2022
$'000 $'000
Trade receivables 6,350 158,032
Underlift 3,806 -
Other receivables 3,080 16,828
Prepayments and accrued income 1,882 1,343
Total current receivables 15,118 176,203
Total receivables 155,336 176,203
Underlift is the volumes owed to the Company by the KRG who lifted volumes in
excess of their contractual entitlement in accordance with the PSC. The
underlift is valued at the year-end sales price. The underlift was temporary
and the group lifted the volumes in 2024.
Reconciliation of Trade Receivables
2023 2022
$'000 $'000
Gross carrying amount 171,026 161,112
Less: Impairment allowance (24,458) (3,080)
Carrying value at 31 December 146,568 158,032
Gross trade receivables of $171.0 million (2022: $161.1 million) are comprised
of invoiced amounts due, based upon KBT pricing, from the KRG for crude oil
sales totalling $158.8 million (2022: $148.9 million) related to October 2022
- March 2023 and a share of Shaikan amounts due from the KRG that the Group
purchased from MOL amounting to $12.2 million (2022: $12.2 million). Trade
receivables net of capacity building payments payable of $7.7 million (2022:
$7.1 million) are $151.1 million (2022: $141.8 million).
While the Group expects to recover the full value of the outstanding invoices
and purchased revenue arrears, an ECL of $24.5 million (2022: $3.1 million)
was provided against the trade receivables balance in accordance with IFRS 9.
During the year, a $21.4 million charge was recognised due to the increase in
the ECL provision (2022: $2.0 million).
As detailed in the Summary of significant accounting policies and Note 2, the
outstanding sales invoices from October 2022 - March 2023 receivable have been
recognised based on a proposed pricing mechanism, which GKP has not accepted.
ECL sensitivities
Considering the receipt profile scenarios, the only variable expected to
materially change profit before tax is the timing of receipt. If the pipeline
reopening is delayed beyond October 2024 resulting in the receipt of past-due
trade receivables being delayed by a further 12 months, then the ECL would
increase by $10.7 million. Conversely, if the repayment profile was brought
forward by 6 months then the ECL would decrease by $6.2 million.
The Group's profit before tax was not materially sensitive to a movement of
±10% in the default spread or recovery rate.
Other receivables
Other receivables includes an amount relating to advances to suppliers of $0.4
million (FY 2022: $11.5 million). $0.4 million (FY 2022: $10.6 million of the
$11.5 million) relates to advances for capital expenditure and is included
within investing activities in the consolidated cash flow statement.
Also included within Other receivables is an amount of $0.4 million (2022:
$0.4 million) being the deposits for leased assets which are receivable after
more than one year. There are no receivables from related parties as at 31
December 2023 (2022: nil). No impairments of other receivables have been
recognised during the year (2022: nil).
14. Current liabilities
Trade and other payables
2023 2022
$'000 $'000
Trade payables 11,953 3,499
Accrued expenditures 14,009 40,642
Amounts due to KRG not expected to be cash settled 74,703 70,740
Capacity building payment due to KRG on trade receivables 7,687 7,131
Other payables 683 6,164
Lease obligations 359 385
Total trade and other payables 109,394 128,561
Trade payables and accrued expenditures principally comprise amounts
outstanding for trade purchases and ongoing costs and the directors consider
that carrying amounts approximate fair value.
Amounts due to KRG not expected to be cash settled of $74.7 million (2022:
$70.7 million) include:
· $37.7 million (2022: $36.5 million) expected to be offset against
oil sales to the KRG up to 2018, that have not been recognised in the
financial statements as management consider that the criteria for revenue
recognition have not been satisfied.
· $37.0 million (2022: $34.2 million) related to an accrual for the
difference between the capacity building rate of 20%, as per the invoicing
basis in effect since October 2017, and 30% as per the 2016 Bilateral
Agreement. The working interest under the 2016 bilateral agreement is 80%
whereas the invoicing basis is 61.5%. If the commercial position were to
revert to the full terms of the executed amended PSC and the 2016 Bilateral
Agreement, the Company would not expect to cash settle this balance as a more
than offsetting increase in GKP's net entitlement is expected to result in
revenue being due to GKP (see critical accounting judgements), the value of
which is expected to exceed the accrued $37.0 million.
Deferred income
At 31 December 2023, deferred income of $5.2 million (2022: $nil) relates to
cash advances paid by local oil buyers in advance of lifting oil (See note 2).
Non-current liabilities
2023 2022
$'000 $'000
Non-current lease liability (see note 2 (#_22_Lease_Liabilities) 1) 39 325
15. Long term borrowings
2023 2022
$'000 $'000
Liability component at 1 January - 103,482
Interest expense, including unwinding of finance & arrangement fees - 8,712
Interest paid during the year - (10,194)
Principal repaid in year - (100,000)
Settlement of notes early repayment fee - (2,000)
Liability component at 31 December - -
On 2 August 2022 the Group redeemed the $100m bond and paid a 2% early
repayment fee.
16. Provisions
2023 2022
Decommissioning provision $'000 $'000
At 1 January 42,546 43,841
New provisions and changes in estimates (8,933) (2,161)
Unwinding of discount 1,699 866
At 31 December 35,312 42,546
The $8.9 million decrease in new provisions and changes in estimates (2022:
$2.2 million) comprises an increase relating to new drilling and facilities
work of $4.2 million (2022: $7.6 million), offset by a reduction of $13.1
million (2022: $9.8 million) due to changes in inflation and discount rates.
The provision for decommissioning is based on the net present value of the
Group's estimated share of expenditure, inflated in line with the table below
and discounted at 4.6% (2022: 3.8%), which may be incurred for the removal and
decommissioning of the wells and facilities currently in place and restoration
of the sites to their original state. Most expenditures are expected to take
place towards the end of the PSC term in 2043.
Annual Inflation Assumption (%)
2023 2022
2023 n/a 5.00%
2024 2.25% 3.00%
2025 2.25% 2.75%
2026 - 2043 2.25% 2.75%
17. Deferred tax asset
The following are the major deferred tax liabilities and assets recognised by
the Group and movements thereon during the current and prior reporting
periods. The deferred tax assets arise in the United Kingdom.
Accelerated tax depreciation Share-based payments Tax losses carried forward Total
$'000 $'000
$'000
$'000
At 1 January 2022 (495) 1,049 831 1,385
(Charge)/credit to income statement (139) 241 223 325
Exchange differences 62 (109) (87) (134)
At 31 December 2022 (572) 1,181 967 1,576
Credit/(charge) to income statement 882 (741) (447) (306)
Exchange differences (17) 42 250 275
At 31 December 2023 293 482 770 1,545
18. Financial instruments
2023 2022
$'000 $'000
Financial assets
Cash 81,709 119,456
Receivables 152,709 162,990
234,418 282,446
Financial liabilities
Trade and other payables 109,433 128,886
109,433 128,886
All financial liabilities, except for non-current lease liabilities (see note
14 (#_154_Trade_and) ), are due to be settled within one year and are
classified as current liabilities. All financial liabilities are recognised at
amortised cost.
Fair values of financial assets and liabilities
With the exception of the receivables from the KRG which the Group expects to
recover in full (see note 13 (#_14_Trade_and) ), the Group considers the
carrying value of all its financial assets and liabilities to be materially
the same as their fair value.
The financial assets balance includes a $24.5 million provision against trade
receivables (2022: $3.1 million) (see note 13 (#_14_Trade_and) ). All
financial assets, except derivatives designated as a hedge, are measured at
amortised cost which is materially the same as fair value.
Capital Risk Management
The Group manages its capital to ensure that the entities within the Group
will be able to continue as going concerns while maximising the return to
shareholders through the optimisation of the debt and equity structure. The
capital structure of the Group consists of cash, cash equivalents, notes (in
prior year) and equity attributable to equity holders of the parent. Equity
comprises issued capital, reserves and accumulated losses as disclosed in note
20 (#_20_Share_capital) and the Consolidated statement of changes in equity.
Capital Structure
The Company's Board of Directors reviews the capital structure on a regular
basis and will make adjustments in light of changes in economic conditions. As
part of this review, the Board considers the cost of capital and the risks
associated with each class of capital.
Significant Accounting Policies
Details of the significant accounting policies and methods adopted, including
the criteria for recognition, the basis of measurement and the basis on which
income and expenses are recognised, in respect of each class of financial
asset, financial liability and equity instrument are disclosed in the Summary
of significant accounting policies.
Financial Risk Management Objectives
The Group's management monitors and manages the financial risks relating to
the operations of the Group. These financial risks include market risk
(including commodity price, currency and fair value interest rate risk),
credit risk, liquidity risk and cash flow interest rate risk.
As at year end, the Group did not hold any derivative assets to hedge against
commodity price declines or any other financial risks. The Group does not use
derivative financial instruments for speculative purposes.
The risks are closely reviewed by the Group's management under the oversight
of the Board on a regular basis and, where appropriate, steps are taken to
ensure these risks are minimised.
Market risk
The Group's activities expose it primarily to the financial risks of changes
in oil prices, foreign currency exchange rates and changes in interest rates
in relation to the Group's cash balances.
There have been no changes to the Group's exposure to other market risks. The
risks are monitored by the Group's management under the oversight of the Board
on a regular basis.
The Group conducts and manages its business predominantly in US dollars, the
operating currency of the industry in which it operates. The Group also
purchases the operating currencies of the countries in which it operates
routinely on the spot market. Cash balances are held in other currencies to
meet immediate operating and administrative expenses or to comply with local
currency regulations.
At 31 December 2023, a 10% weakening or strengthening of the US dollar against
the other currencies in which the Group's monetary assets and monetary
liabilities are denominated would not have a material effect on the Group's
net assets or profit.
Interest rate risk management
The Group's policy on interest rate management is agreed at the Board level
and is reviewed on an ongoing basis. The current policy is to maintain a
certain amount of funds in the form of cash for short-term liabilities and
have the rest on short-term deposits to maximise returns and accessibility.
Based on the exposure to interest rates for cash at the balance sheet date, a
0.5% increase or decrease in interest rates would not have a material impact
on the Group's profit.
Credit risk management
Credit risk refers to the risk that a counterparty will default on its
contractual obligations resulting in financial loss to the Group. As at 31
December 2023, the maximum exposure to credit risk from a trade receivable
outstanding from one customer is $171.0 million (2022: $161.1 million).
Although the Group is confident in the recovery of the trade receivables
balance, a provision of $24.5 million (2022: $3.1 million) was recognised
against the trade receivables balance.
The credit risk on liquid funds is limited because the counterparties for a
significant portion of the cash at the balance sheet date are banks with
investment grade credit ratings assigned by international credit-rating
agencies.
Liquidity risk management
Ultimate responsibility for liquidity risk management rests with the Group's
management under the oversight of the Board of Directors. It is the Group's
policy to finance its business by means of internally generated funds,
external share capital and debt. The Group seeks to raise further funding as
and when required.
19. Share capital
2023 2022
$'000 $'000
Authorised
Common shares of $1 each 292,105 231,605
Non-voting shares of $0.01 each - 500
Preferred shares of $1,000 each - 20,000
Series A Preferred shares of $1,000 each - 40,000
292,105 292,105
Common shares
No. of shares Share capital Share premium Total amount
'000 $'000 $'000 $'000
Balance 1 January 2022 213,731 213,731 742,914 956,645
Dividends paid - - (214,789) (214,789)
Shares issued 2,516 2,516 - 2,516
Balance 31 December 2022 216,247 216,247 528,125 744,372
Dividends paid - - (24,813) (24,813)
Shares issued 6,196 6,196 - 6,196
Balance 31 December 2023 222,443 222,443 503,312 725,755
At 31 December 2023, a total of 0.2 million common shares at $1 each were held
by the EBT (2022: 0.4 million at $1 each). These common shares were included
within reserves.
Rights attached to share capital
The holders of the common shares have the following rights (subject to the
other provisions of the Byelaws):
(i) entitled to one vote per common share;
(ii) entitled to receive notice of, and attend and vote at, general meetings of the
Company;
(iii) entitled to dividends or other distributions; and
(iv) in the event of a winding-up or dissolution of the Company, whether voluntary
or involuntary or for a reorganisation or otherwise or upon a distribution of
capital, entitled to receive the amount of capital paid up on their common
shares and to participate further in the surplus assets of the Company only
after payment of the Series A Liquidation Value (as defined in the Byelaws) on
the Series A Preferred Shares.
20. Cash flow reconciliation
2023 2022
Notes $'000 $'000
Cash flows from operating activities
(Loss)/profit from operations (13,043) 273,544
Adjustments for:
Depreciation, depletion and amortisation of property, plant and equipment 40,409 80,883
(including the right of use assets)
Amortisation of intangible assets 1,648 859
Increase of provision for impairment of trade receivables 1 (#_14_Trade_and) 3 21,378 1,960
Share-based payment expense 2 (#_23_Share-based_payments) 3 9,673 1,866
Provision against inventory held for sale 3 2,627 -
Impairment of PPE items 3 - 1,109
Operating cash flows before movements in working capital 62,692 360,221
Increase in inventories (7,605) (354)
Decrease/(Increase) in trade and other receivables (10,741) 11,640
Increase in trade and other payables 3,107 12,339
Income taxes received 67 -
Cash generated from operations 47,520 383,846
Reconciliation of property, plant and equipment additions to cash flows from
purchase of property, plant and equipment:
2023 2022
$'000 $'000
Associated cash flows
Additions to property, plant and equipment 58,652 116,617
Movement in working capital 6,764 (11,214)
Non-cash movements
Foreign exchange differences (30) (112)
Purchase of property, plant and equipment 65,386 105,291
21. Lease Liabilities
During 2023, the total cash outflows relating to leased assets was $0.5
million (2022: $0.5 million); this amount is the total of capital repayments,
interest charges and foreign exchange impact.
2023 2022
$'000 $'000
Current liabilities (note 1 (#_154_Trade_and) 4) 359 385
Non-current liabilities (note 14 (#_154_Trade_and) ) 39 325
398 710
Lease liability maturity analysis
Year 1 359 385
Year 2 19 325
Year 3 20 -
Amounts payable under leases
Within one year 377 436
In the second to fifth year inclusive 42 339
419 775
Less future interest charges (21) (65)
Net present value of lease obligations 398 710
22. Commitments
Exploration and development commitments
Additions to property, plant and equipment are generally funded with the cash
flow generated from the Shaikan Field. As at 31 December 2023, gross capital
commitments in relation to the Shaikan Field were estimated to be $2.2 million
(2022: $41.9 million).
23. Share-based payments
2023 2022
$'000 $'000
Total share options charge 9,673 3,266
The share options charge of $9.6 million is comprised of $9.1 million (2022:
$3.1 million) related to the LTIP plan and $0.6 million (2022: nil) related to
the deferred bonus plan.
See note 5 for other share option related expenses charged to the consolidated
income statement.
Long Term Incentive Plan
The Gulf Keystone Petroleum 2014 Long Term Incentive Plan ("LTIP") is designed
to reward members of staff through the grant of share options at a
zero-exercise price, that vest three-years after grant, subject to the
fulfilment of specified performance conditions. These performance conditions
are 50% Total Shareholder Return ("TSR") over the vesting period and 50% of
the Group's TSR relative to a bespoke group of comparators over the vesting
period.
2023 2022
Number of Number of
share options share options
'000 '000
Outstanding at 1 January 8,785 8,275
Granted during the year 6,295 2,278
Exercised during the year (6,383) (586)
Forfeited during the year (693) (1,182)
Outstanding at 31 December 8,004 8,785
Exercisable at 31 December - -
The weighted average share price at the date of exercise for share options
exercised during the year was £1.17 (2022: £2.44).
The inputs into the calculation of fair values of the share options granted
during the year are as follows:
2023 2022
Weighted average share price £1.07 £1.67
Weighted average exercise price Nil Nil
Expected volatility 52.5% 57.7%
Expected life 3 years 3 years
Risk-free rate 3.3% 1.4%
Expected dividend yield (on the basis dividends equivalents received) Nil Nil
The options outstanding at 31 December 2023 had a weighted average remaining
contractual life of two years (2022: two years).
The aggregate of the estimated fair value of options granted in 2023 is $4.6
million (2022 $5.0 million).
Deferred Bonus Plan
At the Company's AGM in June 2019, shareholders approved the Deferred Bonus
Plan. This provides for 30% of the annual bonus attributable to executive
directors to be paid in the form of nil cost options that can be exercised any
time after the three-year vesting period. There are no performance conditions
other than the executive director must continue to be employed for this period
(subject to certain limited exceptions).
2023 2022
Number of Number of
share options share options
'000 '000
Outstanding at 1 January 218 113
Exercised during the year (180) -
Granted during the year 178 105
Outstanding at 31 December 216 218
Exercisable at 31 December - -
The weighted average share price at the date of exercise for share options
exercised during the year was £1.37 (2022: not applicable).
During the year 177,832 options (2022: 104,968) were granted to employees
under the Deferred Bonus Plan.
The options outstanding at 31 December 2023 had a weighted average remaining
contractual life of two years.
Value Creation Plan ("VCP")
The VCP was approved by shareholders in December 2016. In 2022, certain nil
cost share option awards vested in accordance with the VCP rules, with the
Company achieving a TSR of at least 8% compound annual growth. There will be
no further awards under the plan.
2023 2022
Number of Number of
share options share options
'000 '000
Outstanding at 1 January - 3,508
Exercised during the year - (3,508)
Outstanding at 31 December - -
Exercisable at 31 December - -
24. Dividends
During 2023, a total of $25 million dividends (11.561 US cents per Common
Share) were declared and paid to shareholders. In 2022, a total of $215
million dividends were declared and paid to shareholders including an ordinary
dividend of $25 million (11.561 US cents per Common Share), a special dividend
of $50 million (23.12 US cents per Common Share) and interim dividends
totalling $140 million (65.27 US cents per Common Share).
To date in 2024, no dividends have been declared or paid.
25. Related party transactions
The Company has a related party relationship with its subsidiaries and in the
ordinary course of business, enters into various sales, purchase and service
transactions with joint operations in which the Company has a material
interest. These transactions are under terms that are no less favourable to
the Group than those arranged with third parties.
Remuneration of Directors and Officers
The remuneration of the Directors and Officers who are considered to be key
management personnel is set out below in aggregate for each of the categories
specified in IAS 24 Related Party Disclosures. The Directors and Officers who
served during the year ended 31 December 2023 were as follows:
J Huijskes - Non-Executive Chairman (resigned June 2023)
M Angle - prior Deputy Chairman who became Non-Executive Chairman June 2023
K Wood - Non-Executive Director became Deputy Chair June 2023
D Thomas - Non-Executive Director
W Mwaura - Non-Executive Director
J Balkany - Non-Executive Director (appointed July 2023)
G Soden - Non-Executive Director (resigned June 2023)
J Harris - Chief Executive Officer and Director
I Weatherdon - Chief Financial Officer and Director
G Papineau-Legris - Chief Commercial Officer
C Kinahan - Chief Human Resources Officer
A Robinson - Chief Legal Officer and Company Secretary
J Hulme - Chief Operating Officer
The values below are calculated in accordance with IAS 19 and IFRS 2.
2023 2022
$'000 $'000
Short-term employee 3,463 4,725
benefits
Share-based payment - options 4,065 1,499
7,528 6,224
Further information about the remuneration of individual Directors is provided
in the Directors' Emoluments section of the Remuneration Committee report.
26. Contingent Liabilities
The Group has a contingent liability of $27.3 million (2022: $27.3 million) in
relation to the proceeds from the sale of test production in the period prior
to the approval of the original Shaikan Field Development Plan ("FDP") in June
2013. The Shaikan PSC does not appear to address expressly any party's rights
to this pre-FDP petroleum. The sales were made based on sales contracts with
domestic offtakers which were approved by the KRG. The Group believes that the
receipts from these sales of pre-FDP petroleum are for the account of the
Contractor, rather than the KRG and accordingly recorded them as test revenue
in prior years. However, the KRG has requested a repayment of these amounts
and the Group is involved in negotiations to resolve this matter. The Group
has received external legal advice and continues to maintain that pre-FDP
petroleum receipts are for the account of the Contractor. This contingent
liability forms part of the Shaikan PSC amendment negotiations and it is
likely that it will be settled as part of those negotiations.
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