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
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
This announcement contains inside
information for the purposes of the UK Market Abuse
Regime.
Enquiries:
or visit: 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
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
30 June 2023
|
Six months ended
31 December 2023
|
Year ended
31 December 2023
|
Year ended
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
$ million
|
2022
$
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
$ million
|
2022
$
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
$ million
|
2022
$
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
$ million
|
2022
$
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
|
123,514
|
460,113
|
Cost of sales
|
3
|
(93,953)
|
(158,651)
|
Increase of expected credit loss
provision on trade receivables
|
13
|
(21,378)
|
(1,960)
|
Gross profit
|
|
8,183
|
299,502
|
|
|
|
|
Other general and administrative
expenses
|
4
|
(10,466)
|
(12,202)
|
Share option related
expenses
|
5
|
(10,760)
|
(13,756)
|
(Loss)/profit from operations
|
|
(13,043)
|
273,544
|
|
|
|
|
Finance income
|
7
|
3,803
|
648
|
Finance costs
|
7
|
(1,765)
|
(9,655)
|
Foreign exchange
(loss)/gain
|
|
(384)
|
1,232
|
(Loss)/profit before tax
|
|
(11,389)
|
265,769
|
|
|
|
|
Tax (charge)/credit
|
8
|
(111)
|
325
|
(Loss)/profit after tax for the year
|
|
(11,500)
|
266,094
|
(Loss)/profit per share
(cents)
|
|
|
|
Basic
|
9
|
(5.28)
|
123.52
|
Diluted
|
9
|
(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
|
10
|
445,842
|
436,443
|
Deferred tax asset
|
17
|
1,545
|
1,576
|
|
|
590,418
|
442,326
|
|
|
|
|
Current assets
|
|
|
|
Inventories
|
12
|
9,901
|
6,372
|
Trade and other
receivables
|
13
|
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
|
14
|
(109,394)
|
(128,561)
|
Deferred income
|
14
|
(5,164)
|
-
|
|
|
(114,558)
|
(128,561)
|
|
|
|
|
Non-current
liabilities
|
|
|
|
Trade and other payables
|
14
|
(39)
|
(325)
|
Provisions
|
16
|
(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
|
Notes
|
Share
capital
|
Share
premium
|
Exchange translation
reserve
|
Accumulated
losses
|
Total
equity
|
$'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
|
24
|
-
|
(214,789)
|
-
|
-
|
(214,789)
|
Employee share schemes
|
23
|
-
|
-
|
-
|
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
|
-
|
(24,813)
|
-
|
|
(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
$'000
|
2022
$'000
|
|
|
|
|
Operating activities
|
|
|
|
Cash generated from
operations
|
20
|
47,520
|
383,846
|
Interest received
|
7
|
3,803
|
648
|
Interest paid
|
15
|
-
|
(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
|
20
|
(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. 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.
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 CO2
emissions by at least 50% versus the original 2020 baseline of 38
kgCO2e 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
$'000
|
2022
$'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
$'000
|
2022
$'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
$'000
|
2022
$'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
$'000
|
2022
$'000
|
|
|
|
Fees payable to the Company's
auditor for the audit of the Company's annual accounts
|
474
|
430
|
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
$'000
|
2022
$'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
in
December
|
Number
of full-time equivalents 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
$'000
|
2022
$'000
|
|
|
|
Wages and salaries
|
37,645
|
46,879
|
Social security costs
|
1,826
|
2,503
|
Pension costs
|
468
|
420
|
Share-based payment (see note
23)
|
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
$'000
|
2022
$'000
|
|
|
|
Notes interest expense (see note
15)
|
-
|
(5,833)
|
Unwinding of finance and arrangement
fees (see note 15)
|
-
|
(879)
|
Notes repayment fee (see note
15)
|
-
|
(2,000)
|
Finance lease interest
|
(66)
|
(77)
|
Unwinding of discount on provisions
(see note 16)
|
(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
$'000
|
2022
$'000
|
|
|
|
Current year credit
|
-
|
216
|
Prior year adjustment
|
195
|
-
|
Deferred UK corporation tax
(charge)/credit (see note 17)
|
(306)
|
109
|
Tax (charge)/credit attributable to
the Company and its subsidiaries
|
(111)
|
325
|
The Group is not required to pay
taxes in Bermuda on either income or capital gains. The Group has
received an undertaking from the Minister of Finance in Bermuda
exempting it from any such taxes at least until the year
2035.
In the KRI, the Group is subject
to corporate income tax on its income from petroleum operations
under the Kurdistan PSC. Under the Shaikan PSC, any corporate
income tax arising from petroleum operations will be paid from the
KRG's share of petroleum profits. Due to the uncertainty over the
payment mechanism for oil sales in Kurdistan, it has not been
possible to measure reliably the taxation due that has been paid on
behalf of the Group by the KRG and therefore the notional tax
amounts have not been included in revenue or in the tax charge.
This is an accounting presentational issue and there is no taxation
to be paid.
The annual UK corporation tax rate
for the year ended 31 December 2023 was 19% on profits up to £50k
tapered to 25% on profits above £250k (2022: flat rate of
19.0%).
Deferred tax is provided for due to
the temporary differences, which give rise to such a balance in
jurisdictions subject to income tax. All deferred tax arises in the
UK.
9.
Earnings per share
The calculation of the basic and
diluted loss per share is based on the following data:
|
2023
|
2022
|
(Loss)/profit after tax for basic
and diluted per share calculations ($'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
assets
$'000
|
Fixtures
and
equipment
$'000
|
Right of use
assets
$'000
|
Total
$'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). 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).
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
6th floor
New Fetter Place
8-10 New Fetter Lane
London EC4A 1AZ
|
United
Kingdom
|
100%
|
Management, support, geological,
geophysical and engineering services
|
Gulf Keystone Petroleum
International Limited
Cedar House, 3rd
Floor
41 Cedar Avenue
Hamilton HM12
Bermuda
|
Bermuda
|
100%
|
Exploration, evaluation,
development and production activities in Kurdistan
|
Name of joint operation
|
Location
|
Proportion of ownership
interest
|
Principal
activity
|
Shaikan
|
Kurdistan
|
80%
|
Production and development
activities
|
12.
Inventories
|
2023
$'000
|
2022
$'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
$'000
|
2022
$'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
$'000
|
2022
$'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
$'000
|
2022
$'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
$'000
|
2022
$'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
$'000
|
2022
$'000
|
Non-current lease liability (see
note 21)
|
39
|
325
|
15.
Long term borrowings
|
2023
$'000
|
2022
$'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
Decommissioning provision
|
2023
$'000
|
2022
$'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
$'000
|
Share-based
payments
$'000
|
Tax losses carried
forward
$'000
|
Total
$'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
$'000
|
2022
$'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),
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), 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). 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 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
$'000
|
2022
$'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 (including the right
of use assets)
|
|
40,409
|
80,883
|
Amortisation of intangible
assets
|
|
1,648
|
859
|
Increase of provision for impairment
of trade receivables
|
13
|
21,378
|
1,960
|
Share-based payment
expense
|
23
|
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
$'000
|
2022
$'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
$'000
|
2022
$'000
|
|
|
|
Current liabilities (note
14)
|
359
|
385
|
Non-current liabilities (note
14)
|
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
$'000
|
2022
$'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
Number of
share
options
'000
|
2022
Number
of
share
options
'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
Number
of
share
options
'000
|
2022
Number
of
share
options
'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
Number
of
share
options
'000
|
2022
Number
of
share
options
'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
$'000
|
2022
$'000
|
|
|
|
Short-term employee
benefits
|
3,463
|
4,725
|
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.