REG-Gulf Keystone Petroleum Ltd 2024 Full Year Results Announcement
20/03/2025 07:15
============
Gulf Keystone Petroleum Ltd (GKP)
2024 Full Year Results Announcement
20-March-2025 / 07:00 GMT/BST
════════════════════════════════════════════════════════════════════════════════════
20 March 2025
Gulf Keystone Petroleum Ltd. (LSE: GKP)
(“Gulf Keystone”, “GKP”, “the Group” or “the Company”)
2024 Full Year Results Announcement
$25 million interim dividend declared & 2025 guidance reiterated
Gulf Keystone, a leading independent operator and producer in the Kurdistan Region
of Iraq, today announces its results for the full year ended 31 December 2024.
Jon Harris, Gulf Keystone’s Chief Executive Officer, said:
“2024 was a year of strong operational and financial delivery for Gulf Keystone. We
have sustained our positive momentum into 2025, with year to date gross average
production of c.46,400 bopd, strong local sales demand and a disciplined expenditure
programme supporting continued free cash flow generation. As a result, we are
pleased to announce today the declaration of a $25 million interim dividend as we
reiterate our 2025 operational and financial guidance. We remain focused on
facilitating a solution to restart oil exports as we continue to seek fair and
transparent agreements regarding payment surety, the repayment of receivables and
the preservation of current contract economics.”
Highlights to 31 December 2024 and post reporting period
Operational
• Zero Lost Time or Recordable incidents in 2024, well below the relevant
Kurdistan and international peer benchmarks, with safety track record extended
to over 790 LTI-free days as at 18 March 2025
• 2024 gross average production of 40,689 bopd, an 86% increase versus the prior
year (2023: 21,891 bopd)
◦ Reflects a full year of local sales in 2024 following the impact of the
suspension of pipeline exports in March 2023
◦ Despite temporary disruptions to truck availability during regional
holidays and elections and the impact of the planned PF-1 shutdown in
November 2024, strong local market demand from Q2 2024 onwards enabled the
return to production at full capacity in several months
◦ Average realised price for 2024 sales of $26.8/bbl, with prices stabilising
in a range of c.$27-$28/bbl in H2 2024
• 2025 year to date (to 18 March 2025) gross average production of c.46,400 bopd:
◦ Continued strong local market demand, with realised prices averaging
between $27-$29/bbl
Shaikan Field estimated reserves
• The Company estimates gross 2P reserves of 443 MMstb as at 31 December 2024,
reflecting the Company’s year end 2023 internal estimate of 458 MMstb reduced by
gross production of 15 MMstb in 2024
Financial
• Strong financial performance, with a full year of robust local sales combined
with capital and cost discipline underpinning a return to free cash flow
generation and the restart of shareholder distributions
• Adjusted EBITDA increased 52% to $76.1 million in 2024 (2023: $50.1 million) as
higher production more than offset the decline in realised prices related to the
transition from exports to discounted local sales
◦ Revenue increased 22% to $151.2 million (2023: $123.5m) as the increase in
2024 volumes more than offset the 34% decline in average realised price to
$26.8/bbl (2023: $40.9/bbl)
◦ Gross operating costs per barrel decreased 21% to $4.4/bbl (2023:
$5.6/bbl), primarily reflecting higher production and a continued focus on
efficient operations
• Net capital expenditure of $18.3 million (2023: $58.2 million), reflecting the
Company’s disciplined work programme comprised of safety critical upgrades at
PF-1 and production optimisation expenditures
• 2024 monthly average net capital expenditure, operating costs and other G&A of
$6.8 million, below the Company’s guidance of c.$7 million
• Free cash flow generation of $65.4 million, relative to a $13.1 million outflow
in 2023, funding the restart of shareholder distributions and preservation of a
robust, debt-free balance sheet:
◦ $45 million of shareholder distributions in 2024 consisting of $35 million
of dividends and $10 million of share purchases completed under the buyback
programme launched in May 2024
◦ 2024 year-end cash balance of $102 million (31 December 2023: $82 million)
◦ Cash balance as at 19 March 2025 of $115 million
Outlook
• 2025 operational and financial guidance reiterated:
◦ Gross average production of 40,000 – 45,000 bopd:
▪ Subject to local market demand remaining at current strong levels
▪ Continues to reflect assumptions regarding the planned PF-2 shut-in,
truck availability during regional holidays and field declines
▪ Should there be any significant unforeseen disruptions to demand or
the restart of pipeline exports, the Company will update its
production expectations as appropriate
◦ Net capital expenditure of $25-$30 million:
▪ c.$20 million: Safety and maintenance upgrades at PF-2, scheduled for
Q4 2025 and expected to require the shut-in of the facility for c.3
weeks, similar to PF-1 in 2024
▪ $5-$10 million: Production optimisation programme consisting of low
cost, quick payback well interventions
▪ Continue to explore range of additional plant initiatives to enhance
production, including water handling, with planned reviews later in
2025 based on the Company’s liquidity position and operating
environment
◦ Operating costs of $50-$55 million and other G&A expenses below $10 million
• $25 million interim dividend announced today, the first semi-annual dividend to
be paid under the shareholder distributions framework announced on 8 October
2024
◦ The dividend will be paid on 23 April 2025, based on a record date of 4
April 2025 and ex-dividend date of 3 April 2025
◦ USD and GBP rate per share to be announced ahead of the payment date based
on the Company’s latest total issued share capital
• The recent share buyback programme of up to $10 million, expiring 20 March 2025,
has not been renewed in light of the interim dividend declaration and the
strength of the Company’s share price
◦ Share buybacks will continue to be considered opportunistically by the
Board
• The Company continues to proactively engage with government stakeholders
regarding a solution to enable the restart of Kurdistan crude exports through
the Iraq-Türkiye Pipeline:
◦ Several recent meetings held with the Kurdistan Regional Government and
Federal Government of Iraq
◦ The Company remains ready to resume oil exports provided we have agreements
on payment surety for future oil exports, the repayment of outstanding
receivables and the preservation of current contract economics
Investor & analyst presentations
GKP’s management team will be hosting a presentation for analysts and investors at
10:00am (GMT) today via live audio webcast:
1 https://brrmedia.news/GKP_FY_2024
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.
2 https://www.investormeetcompany.com/gulf-keystone-petroleum-ltd/register-investor
Recordings of both presentations will be made available on GKP’s website.
This announcement contains inside information for the purposes of the UK Market
Abuse Regime.
Enquiries:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations
& Corporate Communications 3 aclark@gulfkeystone.com
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton
4 GKP@fticonsulting.com
Nick Hennis
or visit: 5 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: 6 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.
Chair’s statement
This is my first annual results statement as Chair of Gulf Keystone following my
appointment under sad circumstances in September 2024 after the passing of Martin
Angle. Martin was an excellent Chair, an outstanding professional and above all a
good friend with whom I worked for many years as a Non-Executive Director. He is
sorely missed by all of us at the Company. Thankfully, he has left behind an
experienced and diligent Board of Directors and a talented executive team focused on
driving shareholder value from the Company’s world-class asset, the Shaikan oil
field.
The last two years have been a challenging period for Gulf Keystone, catalysed by
the suspension of international crude oil exports from Kurdistan via the
Iraq-Türkiye Pipeline (“ITP”) in late March 2023 and the resultant requirement to
preserve the Company’s liquidity by accessing new local oil markets whilst cutting
costs and safely maintaining production. I am pleased to say that these challenges
have been met and, during 2024, the Company generated a significant amount of free
cash flow with a much leaner organisation and strong production levels. Production
during the year averaged 40,689 bopd gross which, given the relatively low level of
development activity, was a good outcome and again demonstrates the quality of the
Shaikan reservoir.
The improved cash flow position allowed for the settlement of all the Company’s
overdue invoices to our suppliers and service providers in Q1 2024 and for
shareholder distributions to recommence consistent with our stated policy. A $10
million share buyback programme was announced in May 2024 and, with continuing
strong local sales demand and improving liquidity, the Board approved the payment of
a total of $35 million of dividends in July and October 2024. The total shareholder
distributions completed during the year were $45 million.
Gulf Keystone’s strong operational and financial performance in 2024 reflected the
Company’s commitment to maximise shareholder value and positions it well to
capitalise on the potential restart of international oil exports when the ITP
reopens. GKP’s leadership team and Board continue to dedicate a significant amount
of time and effort to engaging with government and other stakeholders to move
towards a solution, both as a Company and alongside other IOCs operating in the
region. Engagement remains ongoing as we continue to seek agreements on payment
surety, the repayment of past receivables and the preservation of existing
commercial terms. We are hopeful of a swift resolution and remain ready to quickly
restart oil exports.
One of our primary areas of focus as a Board in 2024 was to ensure that we retain
the Company’s considerable talent to navigate through the current operational and
commercial environment in Kurdistan. At the same time, we oversaw a number of new
Director appointments which have deepened the experience and expertise of the Board
and also enabled us to meet the UK Corporate Governance Code and Listing Rules
requirements in respect of Board independence, gender and ethnic diversity.
In June 2024, we were pleased to welcome Gabriel Papineau-Legris as a Director
following his appointment as Chief Financial Officer at the 2024 AGM, replacing Ian
Weatherdon who retired. In October 2024, we also appointed Catherine Krajicek and
Marianne Daryabegui to the Board and together they bring many years of experience
working in the oil and gas industry, emerging markets, finance and M&A and also as
Non-Executive Directors. In addition to her other Board responsibilities, Marianne
has assumed the role of the Senior Independent Director for the Company. I am sure
that our new Board members will make a significant contribution to the Company and
look forward to working with them in the future.
I would like to take this opportunity to thank our shareholders for their continued
support through what has been a period of volatility and uncertainty for the
Company. We continue to actively engage with our shareholders and welcome all
feedback. Gulf Keystone has emerged as a fitter and stronger organisation and, with
the success of the local sales arrangements and safe maintenance and enhancement of
the Shaikan Field’s production capacity, has been able to restart shareholder
distributions with top quartile total shareholder return performance of 24% in 2024
relative to our peers (assuming dividends paid in the year were reinvested). The
Board and the Company are now focused on unlocking further upside value by securing
a commercial solution to restart oil exports while delivering on our operational and
financial guidance for the year.
David Thomas
Non-Executive Chair
19 March 2025
CEO review
2024 was a positive year for Gulf Keystone, characterised by strong operational and
financial delivery despite the challenging operating environment. As the local sales
market in Kurdistan developed, we returned to consistently strong production levels
which, combined with a lean work programme and strict cost control, enabled us to
generate significant free cash flow, facilitating the restart of shareholder
distributions and the preservation of our robust balance sheet.
2024 performance
Our performance was underpinned by the extension of our excellent safety track
record, with zero Lost Time or Recordable incidents in the year, well below the
relevant Kurdistan and international peer benchmarks. This was achieved despite 24/7
truck loading operations at both production facilities and the temporary shut-in of
PF-1, which involved close to 100,000 working hours of activity. We were pleased to
further extend our record of Lost Time Incident free days to over two years in
January 2025 and have been currently operating without an LTI for over 790 days as
at 18 March 2025.
2024 gross average production of 40,689 bopd was almost double 2023’s performance of
21,891 bopd as we returned to a full year of sales after the extended shut-in of the
Shaikan Field in Q2 2023 due to the suspension of Kurdistan crude exports. After a
slow start in Q1 2024, during which the local market was developing to absorb
increasing supply from producers in the region, we saw strong underlying demand from
the second quarter onwards. This enabled a number of months of high production at
levels we had last seen prior to the shut-in of the ITP, with September 2024
production of 48,458 bopd our best month on record.
Local market demand was tempered by temporary disruptions to truck availability
during regional holidays, in particular the two Eid celebrations in April and June
2024, and temporary road closures related to the Kurdistan regional elections in
October 2024. Production was also reduced as expected during the planned shutdown of
PF-1 in November 2024 as we installed safety upgrades and carried out maintenance.
Local sales realised prices averaged $26.8/bbl in 2024. As with production volumes,
we saw lower prices in Q1 2024 which then improved and stabilised in the second half
of the year. Prices have averaged between $27-$29/bbl in 2025 year to date, as at 18
March 2025.
Our ability to meet local market demand was supported by the execution of a
disciplined work programme focused on maintaining and enhancing the production
capacity of the Shaikan Field whilst preserving the future value of the field. The
successful completion of safety upgrades and maintenance at PF-1 have improved the
safety and reliability of the plant, while production optimisation expenditures on
existing wells enabled us to offset field declines in the year. The Shaikan Field
continues to perform extremely well after over ten years of operations and over 135
million barrels of production.
Higher production and the achievement of an average monthly capex and cost run rate
below $7 million, in line with guidance, enabled us to generate $65.4 million of
free cash flow. In line with our commitment to return excess cash to shareholders,
we distributed $45 million of dividends and share buybacks in the year, an excellent
outcome after we had been forced to suspend our ordinary dividend policy in 2023 due
to the suspension of exports.
Shaikan Field estimated reserves
The Company estimates gross 2P reserves of 443 MMstb as at 31 December 2024,
reflecting our year-end 2023 internal estimate of 458 MMstb reduced by gross
production of 15 MMstb in 2024.
We have estimated 2P reserves based on a number of modelling assumptions, including
a return to development drilling and the expansion of our production facilities from
2026. A return to field development continues to be predicated on the restart of
exports and establishment of a stable commercial and payments environment. This
would also likely be the point at which we would review the commissioning of an
updated Competent Person’s Report (“CPR”), including a comprehensive independent
assessment of 1P and 2P reserves and 2C resources. Our last independent CPR was
prepared by ERC Equipoise (“ERCE”) as at 31 December 2022.
2025 outlook
Gross production has averaged c.46,400 bopd in the year to date (1 January to 18
March 2025), supported by continued strong local sales demand, enabling us to
reiterate our gross average production guidance of 40,000 to 45,000 bopd. Our
full-year guidance is contingent on stable demand at current levels and a number of
other assumptions, including estimated field declines of around 6-10%, the expected
impact on production from the planned PF-2 shutdown later in the year and the
estimated reduction in truck availability during regional holidays. Should we see
any unforeseen disruptions in the local market or the restart of exports, we expect
to review the guidance.
We remain focused on balancing capital and cost discipline while maintaining safe
and reliable production capacity. We are executing a similar work programme to 2024,
with estimated net capital expenditures of $25-$30 million in 2025. The increase
relative to 2024 is driven by incremental expenditures on production optimisation,
accounting for $5-$10 million of the guidance, as we target quick payback, low-cost
and efficient interventions on existing wells to offset declines. Around $20 million
is expected to be spent on replicating the 2024 PF-1 safety upgrades and maintenance
at PF-2, currently scheduled for Q4 2025 and requiring the shut-in of the facility
for approximately three weeks.
In addition to our existing budget, we are actively exploring additional plant
initiatives to enhance production, including water handling. We have scheduled
reviews and expect to take appropriate actions later in 2025 considering the
Company’s liquidity position and operating environment at the time.
As we execute against delivering our annual guidance, we continue to actively pursue
a solution to restart the export of our crude to international markets via the ITP,
with a number of recent meetings between the IOCs, KRG and FGI, in which Gulf
Keystone has played an active role. As we approach the two-year anniversary of the
ITP’s closure on 25 March 2025, we remain hopeful that we are now nearing a
solution.
We continue to believe a return to international exports with the right agreements
in place regarding payment surety, receivables repayment and the preservation of our
contractual rights would be transformative for the Company, Kurdistan and Iraq, both
in unlocking additional revenue from a vital source of global oil supply which is
currently selling for significantly discounted prices but also by signalling that
Kurdistan and Iraq are open for business and are attractive destinations for foreign
investment.
Jon Harris
Chief Executive Officer
19 March 2025
Financial review
Key financial highlights
Year ended Year ended
31 December 2024 31 December 2023
Gross average production(1) bopd 40,689 21,891
Dated Brent(2) $/bbl 80.8 82.6
Realised price(1)(3) $/bbl 26.8 40.9
Discount to Dated Brent $/bbl 53.9 41.7
Revenue $m 151.2 123.5
Operating costs $m 52.4 36.1
Gross operating costs per barrel(1) $/bbl 4.4 5.6
Other general and administrative expenses $m 11.4 10.5
Share option expense $m 4.4 10.8
Adjusted EBITDA(1) $m 76.1 50.1
Profit/(loss) after tax $m 7.2 (11.5)
Basic earnings/(loss) per share cents 3.3 (5.3)
Revenue receipts(1) $m 144.1 109.2
Net capital expenditure(1) $m 18.3 58.2
Free cash flow(1) $m 65.4 (13.1)
Shareholder distributions(4) $m 45 25
Cash and cash equivalents $m 102.3 81.7
1. Represents either a non-financial or non-IFRS measure which are explained in the
summary of non-IFRS measures where applicable.
2. 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.
3. 2024 realised prices reflect a full year of local sales, 2023 realised prices
reflect export sales from 1 January to 24 March 2023 and local sales from 19
July to 31 December 2023.
4. 2024: $35 million of dividends and $10 million of completed share buybacks;
2023: $25 million dividend.
GKP delivered a strong financial performance in 2024, with a full year of robust
local sales combined with capital and cost discipline underpinning a return to free
cash flow generation and the restart of shareholder distributions. We are pleased to
declare, alongside the 2024 full-year results, a $25 million interim dividend, the
first semi-annual dividend to be paid under the shareholder distributions framework
announced in October 2024. Looking ahead, stable local sales demand and the delivery
of our guidance should enable material free cash flow generation in 2025, with
significant improvements in cash flow generation to be potentially unlocked through
the restart of exports at the current level of net entitlement.
Adjusted EBITDA
Adjusted EBITDA increased 52% to $76.1 million in 2024 (2023: $50.1 million). Higher
production more than offset the decline in realised prices related to the transition
from exports to discounted local sales and higher operating costs related to a full
year of production after the temporary shut-in of the Shaikan Field during Q2 2023.
Gross average production increased 86% to 40,689 bopd (2023: 21,891 bopd) reflecting
a full year of local sales in 2024 following the impact of the suspension of
pipeline exports in 2023.
Revenue increased 22% to $151.2 million (2023: $123.5m) as the increase in 2024
volumes more than offset the 34% decline in average realised price to $26.8/bbl
(2023: $40.9/bbl). Realised prices for local sales remain driven by supply and
demand dynamics in the local market, with no direct link to Dated Brent. Prices have
averaged between $27-$29/bbl in 2025 year to date, as at 18 March 2025.
The Company continued to exercise strict cost control in 2024 while maintaining and
enhancing the production capacity of the Shaikan Field. Gross operating costs per
barrel decreased 21% to $4.4/bbl (2023: $5.6/bbl) and operating costs increased to
$52.4 million (2023: $36.1 million), primarily reflecting higher production but also
the higher allocation of staff-related costs to operating expenditure due to the
lower level of capital expenditure in the year.
Other G&A expenses were $11.4 million in 2024 (2023: $10.5 million). The increase
versus the prior year primarily reflects the reinstatement of performance-based
staff bonuses for 2024, compared to a small recognition payment in 2023, and the
payment of one-off retention awards. These payments were partly offset by the
absence of non-recurring corporate costs incurred in H1 2023. In line with industry
practice, all direct Shaikan Field related expenditure, such as Shaikan Field G&A
which was immaterial in 2024, is now categorised as either operating or capital
expenditure as appropriate.
Share option expense of $4.4 million was 59% lower year-on-year (2023: $10.8
million), principally reflecting the reduced vesting of the 2021 LTIP award in 2024
relative to the vesting of the 2020 LTIP award in 2023.
Cash flows
Revenue receipts, which reflect cash received in the year for the Company’s net
entitlement of production sales, were $144.1 million, 32% higher than the previous
year (2023: $109.2 million) primarily driven by higher production but also supported
by pre-payments for local sales.
Net capital expenditure in 2024 was $18.3 million (2023: $58.2 million), in line
with annual guidance and reflecting the Company’s disciplined work programme
comprised of safety-critical upgrades at PF-1 and production optimisation
expenditures. 2024 expenditures were the lowest since 2017, with the 69% decrease
relative to 2023 reflecting the termination of expansion activity following the
suspension of Kurdistan exports in March 2023.
Free cash flow generation in 2024 was $65.4 million, compared to a $13.1 million
outflow in 2023. Revenues generated by local sales more than covered the Company’s
aggregate net capex and costs, which on an average monthly basis were $6.8 million,
below the Company’s guidance of c.$7 million. Low-cost production and capital
discipline provide significant downside protection even at discounted local sales
prices.
The Company continued to engage with the KRG regarding the payment mechanism of the
overdue October 2022 to March 2023 invoices. The total owed to GKP amounts to $151.1
million (comprising of $120.4 million cost oil and $30.7 million profit oil net to
GKP after capacity building payment (‘CBP’) deduction). The total owed to GKP and
MOL (who form together the ‘Shaikan Contractor’ or the ‘Contractor’) amounts to
$192.8 million (comprising $150.5 million cost oil and $42.3 million profit oil).
The Company continues to expect to recover the invoices in full (see ‘Net
entitlement’ section below for further detail).
With improving liquidity and strong local sales demand, on 13 May 2024 the Company
announced the launch of a $10 million share buyback programme, which was completed
on 23 July 2024. The buyback was supplemented with the payment of two dividends in
July and October 2024 respectively, totalling $35 million, increasing completed
shareholder distributions in the year to $45 million. A second share buyback
programme of up to $10 million was also launched in October 2024, although limited
purchases were made due to the subsequent increase in the Company’s share price. In
light of this and the announced declaration of a $25 million interim dividend today,
the Company has decided not to renew the buyback programme which expired on 20 March
2025.
GKP’s cash balance was $102.3 million as at 31 December 2024 (31 December 2023:
$81.7 million) with no outstanding debt. Continued free cash flow generation from
local sales in Q1 2025 to date have led to a further increase in the Company’s cash
balance to $115 million as at 19 March 2025.
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 has
fluctuated in the past and may be difficult to predict, based on which the Directors
have a reasonable expectation that the Group has adequate resources to continue to
operate for at least 12 months. Therefore, the going concern basis of accounting is
used to prepare the financial statements.
Net entitlement
The Company shares Shaikan Field revenues with its partner, MOL, and the KRG, based
on the terms of the Shaikan Production Sharing Contract (‘Shaikan PSC’). GKP and
MOL’s revenue entitlement is described as ‘Contractor entitlement’ and GKP’s
entitlement alone is described as ‘net’. GKP’s net entitlement includes its share of
the recovery of the Company’s investment in the Shaikan Field, comprising capital
expenditure and operating costs, through cost oil and a share of the profits through
profit oil, less a CBP owed to the KRG.
The unrecovered cost oil balance (or ‘Cost Pool’) and R-factor are used to calculate
monthly cost oil and profit oil entitlements, respectively, owed to the Shaikan
Contractor from crude oil sales. Unrecovered cost oil owed to the Shaikan Contractor
increases with the addition of incurred expenditures deemed recoverable under the
Shaikan PSC and is depleted on a cash basis as crude sales are paid. As at 31
December 2024, there was $162.9 million of unrecovered cost oil for the Shaikan
Contractor ($130.3 million net to GKP), subject to potential cost audit by the KRG.
The R-factor, calculated as cumulative Contractor revenue receipts of $2,417 million
divided by cumulative Contractor costs of $1,963 million, was 1.23, resulting in a
share in the profit oil for the Contractor of 26.5%.
GKP’s net entitlement of total Shaikan Field sales was 36% in 2024. Looking ahead,
the Company expects its net entitlement to remain around 36% in 2025 in a continuing
local sales environment. Should exports restart, increases in realised price, cash
receipt of payments for international sales and the potential implementation by the
KRG of a repayment mechanism for past overdue invoices would accelerate the
depletion of the Cost Pool upon receipt of payment. This would shorten the period
that the Company’s net entitlement is expected to remain around 36% provided that
investment in the Shaikan Field does not increase.
The outlook for the Company’s net entitlement assumes receipt of the cost oil
portion of the outstanding October 2022 to March 2023 receivable balance due from
the KRG to the Shaikan Contractor, which comprises $150.5 million of the total
unrecovered cost oil of $162.9 million as at 31 December 2024 (or on a net basis to
GKP, $120.4 million of the unrecovered cost oil of $130.3 million). Recovery of the
receivable cost oil is expected to begin in the first half of 2025 with regular
payment from either local or export sales. Recovery will in turn lead to a
corresponding reduction in the receivable balance due from the KRG, with $30.7
million of profit oil (net to GKP after CBP deduction) expected to be fully repaid
by the KRG as part of a repayment mechanism.
Outlook
The Company plans to invest net capital expenditure of $25-$30 million in 2025,
which includes $20 million on the implementation of safety upgrades and maintenance
at PF-2, currently scheduled to take place in Q4 2025, and $5-$10 million on the
Company’s ongoing production optimisation programme. While maintaining a strong
focus on capital discipline, the Company continues to explore a range of additional
plant initiatives to preserve and enhance production, including water handling.
The Company expects its cost base to remain stable in 2025, with expected operating
costs of $50-$55 million and other G&A expenses forecast below $10 million in 2025.
Strict cost control combined with capital discipline should enable material free
cash flow generation in 2025 provided local sales demand and pricing remain stable.
Gulf Keystone remains committed to returning excess cash to shareholders via
dividends and/or share buybacks, subject to the liquidity needs of the business and
the operating environment. In October 2024, the Company set out a framework for
shareholder distributions to enable investors to better evaluate the prospect of
future returns in a local sales environment.
The Board will review the Company’s capacity to declare an interim dividend on a
semi-annual basis around the time of the full-year results and half-year results and
will consider share buybacks on an opportunistic basis throughout the year.
Distribution capacity will be determined with reference to the Company’s operating
environment and liquidity needs, typically the next year of capital expenditures and
costs but also the potential liquidity required to transition from pre-paid local
sales to the restart of exports and the normalisation of KRG payments.
In line with this framework, the Company is pleased to announce the declaration of a
$25 million interim dividend. The dividend will be paid on 23 April 2025, based on a
record date of 4 April 2025 and ex-dividend date of 3 April 2025. Shareholders will
have the option of being paid the dividend in either GBP or USD, with the default
currency GBP. The USD and GBP rate per share will be announced ahead of the payment
date based on the Company’s latest total issued share capital.
Gabriel Papineau-Legris
Chief Financial Officer
19 March 2025
Non-IFRS measures
The Group uses certain measures to assess the financial performance of its business.
Some of these measures exclude amounts that are included in, or include amounts that
are excluded from, the most directly comparable measure calculated and presented in
accordance with International Financial Reporting Standards (“IFRS”), or are
calculated using financial measures that are not calculated in accordance with IFRS.
As a result, these measures are termed “non‑IFRS measures” and 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, in presentations to the Board 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, measures
that are equivalent to financial measures that are calculated or presented in
accordance with IFRS.
Gross operating costs per barrel
Gross operating costs are divided by gross production to arrive at operating costs
per barrel.
2024 2023
Gross production (MMbbls) 14.9 8.0
Gross operating costs ($ million)(1) 65.5 45.1
Gross operating costs per barrel ($ per bbl) 4.4 5.6
(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, and excludes the
impact of the costs noted below.
2024 2023
$ million $ million
Profit/(loss) after tax 7.2 (11.5)
Finance costs 1.7 1.8
Finance income (4.1) (3.8)
Tax charge 0.7 0.1
Depreciation of oil and gas assets 75.8 39.5
Depreciation of other PPE assets and amortisation of intangibles 3.0 2.6
(Decrease)/increase of expected credit loss provision on trade (8.2) 21.4
receivables
Adjusted EBITDA 76.1 50.1
Net cash
Net cash is a useful indicator of the Group’s indebtedness and financial flexibility
indicating the level of cash and cash equivalents less cash borrowings within the
Group.
2024 2023
$ million $ million
Cash 102.3 81.7
Borrowings - -
Net cash 102.3 81.7
The Company was debt free at 31 December 2024 and 31 December 2023.
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.
2024 2023
$ million $ million
Net capital expenditure (see note 10 to the consolidated 18.3 58.2
financial statements)
Free cash flow
Free cash flow represents the Group’s cash flows before any dividends and share
buybacks including related fees.
2024 2023
$ million $ million
Net cash generated from operating activities 93.5 51.3
Net cash used in investing activities (27.6) (63.9)
Payment of leases (0.5) (0.5)
Free cash flow 65.4 (13.1)
Consolidated income statement
For the year ended 31 December 2024
Notes 2024 2023
$’000 $’000
Revenue 7 2 151,208 123,514
Cost of sales 8 3 (138,866) (93,953)
Decrease/(increase) of expected credit loss provision on 9 13 8,191 (21,378)
trade receivables
Gross profit 20,533 8,183
Other general and administrative expenses 10 4 (11,412) (10,466)
Share option related expenses 11 5 (4,419) (10,760)
Profit/(loss) from operations 4,702 (13,043)
Finance income 12 7 4,116 3,803
Finance costs 13 7 (1,676) (1,765)
Foreign exchange gain/(loss) 724 (384)
Profit/(loss) before tax 7,866 (11,389)
Tax charge 14 8 (708) (111)
Profit/(loss) after tax for the year 7,158 (11,500)
Profit/(loss) per share (cents)
Basic 15 9 3.26 (5.28)
Diluted 16 9 3.13 (5.28)
Consolidated statement of comprehensive income
For the year ended 31 December 2024
2024 2023
$’000 $’000
Profit/(loss) after tax for the year 7,158 (11,500)
Items that may be reclassified to the income statement in
subsequent periods:
Exchange (loss)/gain on translation of foreign operations (517) 952
Total comprehensive income/(loss) for the year 6,641 (10,548)
Consolidated balance sheet
As at 31 December 2024
Notes 31 December 2024 31 December 2023
$’000 $’000
Non-current assets
Trade receivables 13 138,175 140,218
Intangible assets 1,255 2,813
Property, plant and equipment 17 10 388,450 445,842
Deferred tax asset 18 16 825 1,545
528,705 590,418
Current assets
Inventories 19 12 9,852 9,901
Trade and other receivables 20 13 26,779 15,118
Cash 102,346 81,709
138,977 106,728
Total assets 667,682 697,146
Current liabilities
Trade and other payables 21 14 (117,277) (109,394)
Deferred income 14 (716) (5,164)
(117,993) (114,558)
Non-current liabilities
Trade and other payables 22 14 (1,112) (39)
Provisions 23 15 (36,247) (35,312)
(37,359) (35,351)
Total liabilities (155,352) (149,909)
Net assets 512,330 547,237
Equity
Share capital 18 217,005 222,443
Share premium 18 463,985 503,312
Exchange translation reserve (4,283) (3,766)
Accumulated losses (164,377) (174,752)
Total equity 512,330 547,237
The financial statements were approved by the Board of Directors and authorised for
issue on 19 March 2025 and signed on its behalf by:
Jon Harris
Chief Executive Officer
Gabriel Papineau-Legris
Chief Financial Officer
Consolidated statement of changes in equity
For the year ended 31 December 2024
Attributable to equity holders of the Company
Share Exchange Total
Share translation Accumulated
premium reserve losses equity
capital
Notes $’000 $’000 $’000 $’000 $’000
Balance at 1 January 2023 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 - - 952 - 952
operations
Total comprehensive loss - - 952 (11,500) (10,548)
for the year
Dividends paid 24 22 - (24,813) - - (24,813)
Employee share schemes 25 21 - - - 9,673 9,673
Share issues 18 6,196 - - (6,196) -
Balance at 31 December 2023 222,443 503,312 (3,766) (174,752) 547,237
Profit after tax for the - - - 7,158 7,158
year
Exchange difference on
translation of foreign - - (517) - (517)
operations
Total comprehensive profit - - (517) 7,158 6,641
for the year
Dividends paid 26 22 - (34,933) - - (34,933)
Employee share schemes 21 - - - 3,472 3,472
Share issues 18 255 - - (255) -
Repurchase of ordinary 18 (5,693) (4,394) - - (10,087)
shares
Balance at 31 December 2024 217,005 463,985 (4,283) (164,377) 512,330
Consolidated cash flow statement
For the year ended 31 December 2024
2024 2023
Notes
$’000 $’000
Operating activities
Cash generated from operations 19 89,427 47,520
Interest received 27 7 4,116 3,803
Net cash generated from operating activities 93,543 51,323
Investing activities
Purchase of intangible assets (420) -
Purchase of property, plant and equipment 19 (27,178) (65,386)
Sale of drilling stock - 1,449
Net cash used in investing activities (27,598) (63,937)
Financing activities
Payment of dividends 22 (34,933) (24,813)
Share buyback (10,087) -
Payment of leases (452) (503)
Net cash used in financing activities (45,472) (25,316)
Net increase/(decrease) in cash 20,473 (37,930)
Cash at beginning of year 81,709 119,456
Effect of foreign exchange rate changes 164 183
Cash at end of the year being bank balances and cash on hand 102,346 81,709
Summary of material accounting policies
General information
Gulf Keystone Petroleum Limited (the “Company”) is domiciled and incorporated in
Bermuda (registered address: c/o Carey Olsen Services Bermuda Limited, 5th Floor,
Rosebank Centre, 11 Bermudiana Road, Pembroke, HM08 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. On 29th July 2024, new Listing Rules came into effect for the
London Stock Exchange. The former categories for Main Market listed companies of
Premium and Standard Listed were ceased (GKP being a Standard Listed company up
until this point). From that date, GKP moved to the Equity Shares – Transition
category. The Company serves as the parent 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 2023 or
2024 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 2024.
The following new accounting standards, amendments to existing standards and
interpretations are effective on 1 January 2024: Classification of Liabilities as
Current or Non-Current & Non-current Liabilities with Covenants (Amendments to IAS
1), Lease Liability in a Sale and Leaseback (Amendments to IFRS 16), and Supplier
Finance Arrangements (Amendments to IAS 7 and IFRS 7). 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
IFRS 19 Subsidiaries without Public Accountability: Disclosures
Amendments IFRS 9 and IFRS Classification and measurement of financial instruments;
7 Contracts Referencing Nature-dependent Electricity
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 Amendments to the SASB standards to enhance their
standards 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.
IFRS 18 replaces IAS 1, carrying forward many of the requirements in IAS 1 unchanged
and complementing them with new requirements. In addition, some IAS 1 paragraphs
have been moved to IAS 8 and IFRS 7. Furthermore, the IASB has made minor amendments
to IAS 7 and IAS 33 Earnings per Share.
IFRS 18 introduces new requirements to:
• present specified categories and defined subtotals in the statement of profit or
loss
• provide disclosures on management-defined performance measures (MPMs) in the
notes to the financial statements
• improve aggregation and disaggregation
An entity is required to apply IFRS 18 for annual reporting periods beginning on or
after 1 January 2027, with earlier application permitted. The amendments to IAS 7
and IAS 33, as well as the revised IAS 8 and IFRS 7, become effective when an entity
applies IFRS 18. IFRS 18 requires retrospective application with specific transition
provisions.
The Directors of the company anticipate that the application of these amendments may
have an impact on the Group's consolidated financial statements 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 Chair’s statement,
the Chief Executive Officer’s 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 19 March 2025 the Group had $115 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 the closure of the Iraq-Türkiye pipeline (“ITP”) in March 2023, the
Group significantly reduced expenditures to preserve liquidity and continues to
closely monitor costs with minimal capital investment committed while the pipeline
remains closed. Throughout 2024 and up to the date of this report in 2025, due to
the stabilising of local sales volumes, the Group has significantly improved its
working capital position, including settling all legacy supplier invoices from prior
to the suspension of exports, and it was able to distribute $45 million to
shareholders in 2024 via buybacks and dividends, with a further $25 million interim
dividend declared in March 2025.
Nonetheless, the Group is aware there could be a potential decline in local sales,
and potential delays in Kurdistan Regional Government (“KRG”) revenue receipts once
the ITP has been reopened.
The key uncertainties of the alternative crude sale methods are summarised below:
• Local sales: the Group continues local sales with payments from buyers required
in advance following extensive due diligence. During 2024 the Group received
over $144 million related to local sales. However, local sales volumes (average
c.40,700 bopd in 2024) and prices have fluctuated in the past and may be
difficult to predict; and
• Export sales: In February 2025, the Iraqi Parliament approved an amendment to
Article 12 of the Iraqi 2023-2025 Budget Law regarding the compensation for
Kurdistan’s oil production and transportation costs, potentially facilitating
the resumption of Kurdistan's oil exports. Whilst the approval of the amendment
is a key step towards the resumption of Kurdistan oil exports, a number of key
details remain outstanding regarding payment surety for future oil exports, the
repayment of outstanding receivables and the preservation of current contract
economics. As such, the timing of the reopening of the ITP and payment mechanism
remain uncertain.
The Directors believe an agreement will ultimately be reached to reopen the ITP, and
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 $81 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 2024 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 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.
For sales to the local market from 19 July 2023 onwards, including all of 2024, 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.
Prior to the shut-in of the 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.
Effective September 1, 2022, the KRG proposed a new pricing mechanism for crude oil
export sales, which continued 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, Türkiye, 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 was in place
for oil sales from 1 September 2022 until the ITP shut-in referenced above.
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 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 income
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 2024 was based
on the December 2022 Competent Person’s Report (“CPR”), a reserves report completed
by ERC Equipoise as at 31 December 2022; this estimate combined with the Group’s
subsequent production and economic modelling formed the basis of the updated
estimate used in the year.
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.
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 ECL is updated at each reporting date to reflect changes in credit risk
since initial recognition of the respective financial instrument.
The Group considers a counterparty to be in default if it can no longer be
reasonably expected to recover receivable amounts at a future date; no
counterparties are currently considered to be in default.
The Group recognises lifetime ECL for trade receivables, contract assets and lease
receivables. The ECL 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 ECL that will result from all possible default events
over the expected life of a financial instrument; this is known as a stage 2
receivable and GKP’s trade outstanding receivable is classified within this
category. 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; this is known as a stage 1 receivable.
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.
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 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 28 21. 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 29 21.
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.
Production sharing contract 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 the comparative financial
statements for 2023 considered whether it was appropriate to recognise export
revenue for deliveries from 1 January to 25 March 2023 based on the proposed new
pricing mechanism, notwithstanding that there was no signed lifting agreement for
that period and the pricing mechanism. 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. No adjustments were made in 2024 in respect of the
above as revenue was earned via local sales, with no agreement yet reached in
respect of the export period mentioned above.
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 Group 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 Group.
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. See note 14 for further details.
The Group expects to confirm with the MNR whether to proceed with a formal amendment
to the PSC to reflect current invoice terms.
Material 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 is the basis for 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.
In making this judgement, a weighted average has been applied to modelled receipt
profiles, upon which a counterparty default allowance has been applied to derive the
ECL. When modelling receipt profiles management have made a number of key estimates
that are dependent upon uncertain future events including: the KRG’s deemed credit
rating, the export pipeline reopening date, the unrecovered cost pool is depleted on
a cash basis as invoices for crude sales are paid which can be recovered through
local and export sales, estimated timeline of cost oil and profit oil recoveries via
commercial terms which have not yet been agreed with the KRG, future oil price
including an estimate of both local and export prices, future oil production, and
the probabilities allocated to various scenarios incorporating the aforementioned
variables. Management has estimated the KRG’s probability of default based on credit
default swap ratings (“CDS”) applicable to sovereign nations with similar
characteristics to the KRG. Material sensitivities of the ECL to discrete variables
are summarised in note 13.
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 Group performed an estimate of the value of obligations and
costs to decommission the asset as at 31 December 2023, which was reviewed by ERC
Equipoise, an independent third party; this estimate formed the basis of the updated
estimate of the current value of obligations and costs at 31 December 2024.
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,
there is also uncertainty regarding the inflation and discount rates used. For the
carrying amount of the item, see note 15.
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 ‘Impairment of Assets’. 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, estimated production volumes,
the cost of development and production, post-tax discount rates that reflect the
current market assessment of the time value of money and risks specific to the
asset, commercial reserves and inflation. The key assumptions are subject to change
based on 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 2024 was the Shaikan Field with a carrying
value, being Oil and Gas assets less capitalised decommissioning provision, of
$348.9 million (2023: $408.0 million). The Group performed an impairment indicator
evaluation as at 31 December 2024 and concluded that no impairment indicators arose.
The key areas of estimation in assessing the potential impairment indicators are as
follows:
• While the date of the re-opening of the ITP remains uncertain, management have
assessed a re-opening date of October 2025 as being reasonable. Although the
estimated re-opening date is one year later than the base case assessment at 31
December 2023, management previously performed sensitivities of up to two years
with no impairment, therefore this delay to the projected re-opening was not
assessed to be an impairment trigger;
• The Group’s netback oil price applied only to export pipeline sales was based on
the Brent forward curve and market participants’ consensus, including banks,
analysts and independent reserves evaluators, as at 31 December 2024 for the
period 2025 to 2030 with inflation of 2.50% per annum thereafter, less
transportation costs and quality adjustments. Brent consensus prices are as
follows
Scenario ($/bbl – nominal) 2024 2025 2026 2027 2028 2029 2030
31 December 2024 – base case n/a 74.0 72.0 74.0 75.0 73.0 80.0
31 December 2024 – stress case n/a 66.6 64.8 66.6 67.5 65.7 72.0
31 December 2023 – base case 83.0 80.0 77.0 77.0 77.0 80.0 81.8
31 December 2023 – stress case 74.7 72.0 69.3 69.3 69.3 72.0 73.6
• Management have previously applied sensitivities in reviewing stress case
pricing including a 10% reduction from base case pricing to derive a stress case
price with no impairment impact. The stress case pricing is noted above;
• Discount rates are adjusted to reflect risks specific to the Shaikan Field and
the Kurdistan Region of Iraq. Management assessed changes to the key variables
that could impact discount rate and concluded no change was necessary. The
post-tax nominal discount rate was estimated to be 16%, unchanged from 31
December 2023;
• Operating costs and capital expenditure are based on financial budgets and
internal management forecasts. Costs assumptions incorporate management
experience and expectations, as well as the nature and location of the operation
and the risks associated therewith. There were no indicators that costs will
increase in comparison to 31 December 2023 impairment assessment;
• No adverse changes were noted for commercial reserves and production profiles;
• No changes were noted in the operating environment such as local market
conditions, tax or other legal or regulatory changes. Specifically, management
considered if there had been any update with respect to the Iraqi Federal
Supreme Court ruling announced in 2022 and concluded there was no movement in
the period which would impact the impairment analysis; and
• 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 intensity 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 scenario portrays a pathway for the global energy sector to
reach net zero CO2 emissions by 2050 which is consistent with limiting long-term
global warming to 1.5 °C with limited overshoot. The estimated re-opening date
is one year later than the base case assessment at 31 December 2023, management
previously performed sensitivities of up to two years. There was no impairment
under the APS scenario, but a potential impairment under the NZE scenario. While
the IEA oil price assumptions incorporate carbon prices, the IEA 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, but a potential impairment under the NZE scenario.
Notes to the consolidated financial statements
1. Geographical information
The Chief Operating Decision Maker, as per the definition in IFRS 8 ‘Operating
Segments’, 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% (2023:
100%) 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 consolidated statement of
comprehensive income, the consolidated balance sheet, the consolidated statement of
changes in equity, the consolidated cash flow statement and these related notes.
2. Revenue
2024 2023
$’000 $’000
Oil sales via export pipeline - 78,955
Local oil sales 151,208 44,559
151,208 123,514
The Group’s accounting policy for revenue recognition is set out in the ‘Summary of
material accounting policies’, with revenue recognised upon crude oil passing the
delivery points, either being entry into pipeline or delivered into trucks.
Local oil sales (from 19 July 2023 and throughout 2024)
In July 2023, GKP began selling oil to local buyers at negotiated prices. The
realised price achieved in 2024 was $27/bbl (July to December 2023: $30/bbl). Local
buyers are contracted to pay GKP in advance of receipt of oil; such amounts are
recognised as deferred income (see note 14) until a customer’s receipt of oil at the
delivery point.
Oil sales via export pipeline (from 1 January - 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.
From 1 September 2022 until shut-in of the ITP on 25 March 2023 there was no lifting
agreement in place between the Shaikan Contractor and the KRG. The KRG proposed a
new pricing mechanism based upon the average monthly KBT sales price realised by the
KRG at Ceyhan; formerly the pricing mechanism was based upon Dated Brent. The Group
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 Group 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 KBT price, the realised price in this period was $51.3/bbl. The revenue
impact of using the proposed KBT pricing mechanism instead of Dated Brent for the
export sales period in 2023 is estimated to be a reduction of revenue by $12.0
million; taking into account the associated reduction in capacity building payments
results in a total reduction of profit after tax for the export sales period in 2023
of $11.4 million.
Information about major customers
Customers making up greater than 10% of revenue are as follows:
2024 2023
Kurdistan Regional Government 0% 68%
Customer A 88% <10%
Customer B <10% 11%
Customer C <10% 0%
Customer D 0% 10%
Customer E 0% 10%
3. Cost of sales
2024 2023
$’000 $’000
Operating costs 52,435 36,082
Capacity building payments 10,818 8,872
Change in oil inventory value (168) (75)
Depreciation of oil and gas assets and operational assets 75,781 39,470
Contract termination costs - 5,525
Provision against inventory held for sale - 2,627
Loss on disposal of drilling stock - 1,452
138,866 93,953
Capacity building payments from 1 January until 25 March 2023 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.
The Group accounting policy for 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 material accounting policies section.
The depreciation charge in 2024 is based upon internal reserves and development cost
estimates. The 2023 depreciation charge was derived from the CPR prepared by ERC
Equipoise as at 31 December 2022. The increase in charge compared to the
corresponding period in 2023 is principally derived from higher production in 2024.
Contract termination, provision against inventory held for sale and loss on disposal
of drilling stocks in 2023 relate to non-recurring activities undertaken following
the ITP export pipeline suspension in March 2023.
4. Other general and administrative expenses
2024 2023
$’000
$’000
Depreciation and amortisation 3,033 2,652
Auditor’s remuneration (see below) 679 635
Other general and administrative costs 7,700 7,179
11,412 10,466
2024 2023
$’000 $’000
Fees payable to the Company’s auditor for the audit of the Company’s 530 474
annual accounts
Fees payable to the Company’s auditor for other services to the Group
- audit of the Company’s subsidiaries pursuant to legislation 32 26
Total audit fees 562 500
Other assurance services (including a half year review) 117 135
Total fees 679 635
5. Share option related expense
2024 2023
$’000 $’000
Share-based payment expense 3,472 9,673
Payments related to share options exercised 704 797
Share-based payment related provision for taxes 243 290
4,419 10,760
Under the Long Term Incentive Plan (“LTIP”) schemes, GKP awards share options to
employees annually that have a three-year vesting period, the share price at the
date of award is a significant determinant of the number of shares issued to
employees (see note 21).
In the event the Company pays dividends to shareholders during the vesting period,
upon vesting the Company would compensate employees for an amount equivalent to the
dividends paid during the vesting period and such amount would be settled at the
Company’s discretion with shares or cash. Given the financial challenges following
the ITP closure, the Company used its discretion in 2023 to pay the dividend
equivalent predominantly in shares to preserve liquidity. The significant decrease
in share-based payment expense in 2024 is due to the decrease in shares issued in
2024 versus 2023 as compensation related to dividends paid in the vesting periods of
the 2021 LTIP and 2020 LTIP.
6. Staff costs
The average number of employees, including Executive directors, and contractors
employed by the Group was 411 (2023: 471); the number of full-time equivalents of
these workers was 274 (2023: 303).
Average number of employees Average number of full-time equivalents
2024 2023 2024 2023
Kurdistan 387 444 250 276
United Kingdom 24 27 24 27
Total 411 471 274 303
Staff costs as follows are shown net of amounts recharged to joint operations:
2024 2023
$’000 $’000
Wages and salaries 37,833 37,645
Social security costs 2,723 1,826
Pension costs 472 468
Share-based payment (see note 30 21) 4,419 10,760
45,447 50,699
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
2024 2023
$’000 $’000
Lease interest (48) (66)
Unwinding of discount on provisions (see note 31 15) (1,628) (1,699)
Total finance costs (1,676) (1,765)
Finance income 4,116 3,803
Net finance income 2,440 2,038
Since redemption of $100m notes on 2 August 2022, the Group has remained debt free.
8. Income tax
2024 2023
$’000 $’000
Prior year adjustment - 195
Deferred UK corporation tax charge (see note 32 16) (708) (306)
Tax (charge)/credit attributable to the Company and its subsidiaries (708) (111)
The Group is not required to pay taxes in Bermuda on either income or capital gains.
The Group has received an undertaking from the Minister of Finance in Bermuda
exempting it from any such taxes at least until the year 2035.
In the KRI, the Group is subject to corporate income tax on its income from
petroleum operations under the Kurdistan PSC. Under the Shaikan PSC, any corporate
income tax arising from petroleum operations will be paid from the KRG’s share of
petroleum profits. Due to the uncertainty over the payment mechanism for oil sales
in Kurdistan, it has not been possible to measure reliably the taxation due that has
been paid on behalf of the Group by the KRG and therefore the notional tax amounts
have not been included in revenue or in the tax charge. This is an accounting
presentational issue and there is no taxation to be paid.
The annual UK corporation tax rate for the years ended 31 December 2024 and 31
December 2023 was 19% on profits up to £50k tapered to 25% on profits above £250k.
Deferred tax is provided for due to the temporary differences, which give rise to
such a balance in jurisdictions subject to income tax. All deferred tax arises in
the UK.
9. Earnings per share
The calculation of the basic and diluted profit/(loss) per share is based on the
following data:
2024 2023
Profit/(loss) after tax for basic and diluted per share 7,158 (11,500)
calculations ($’000)
Number of shares (‘000s):
Basic weighted average number of ordinary shares 219,562 217,992
Basic EPS (cents) 3.26 (5.28)
The Group followed the steps specified by IAS 33 in determining whether potential
common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
2024 2023
Number of shares (‘000s)
Basic weighted average number of ordinary shares outstanding 219,562 217,992
Effect of potential dilutive share options(1) 9,134 -
Diluted number of ordinary shares outstanding 228,696 217,992
Diluted EPS (cents)(1) 3.13 (5.28)
(1) At the reporting date, the Company had 9,134k dilutive (2023: 8,224k
antidilutive) ordinary shares relating to outstanding share options. Earnings per
share are 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”) of 0.1 million, (2023: 0.2 million).
10. Property, plant and equipment
Total
Oil and gas Fixtures and Right of use
assets
assets equipment
$’000
$’000 $’000
$’000
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 - 5 27 32
differences
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
Year ended 31 December 2024
Opening net book value 443,393 2,066 383 445,842
Additions 18,252 284 1,559 20,095
Disposals’ cost - - (2,040) (2,040)
Revision to decommissioning asset (693) - - (693)
Depreciation charge (75,781) (576) (394) (76,751)
Disposals’ depreciation - - 2,004 2,004
Foreign currency translation - (1) (6) (7)
differences
Closing net book value 385,171 1,773 1,506 388,450
At 31 December 2024
Cost 1,010,429 9,687 1,701 1,021,817
Accumulated depreciation (625,258) (7,914) (195) (633,367)
Net book value 385,171 1,773 1,506 388,450
The net book value of oil and gas assets at 31 December 2024 is comprised of
property, plant and equipment relating to the Shaikan block with a carrying value of
$385.2 million (2023: $443.4 million).
The additions to the Shaikan asset amounting to $18.3 million during the year
included safety critical upgrades at PF-1 and production optimisation expenditures.
The $0.7 million (2023: $8.9 million) decrease in decommissioning asset value
relates to a $1.1 million decrease in changes to inflation and discount rates (2023:
$13.1 million), offset by an increase of $0.4 million relating to facilities work
(2023: $4.2 million).
The DD&A charge of $75.8 million (2023: $39.5 million) on oil and gas assets has
been included within cost of sales (see note 33 3). The depreciation charge of $0.6
million (2023: $0.6 million) on fixtures and equipment and $0.4 million (2023: $0.4
million) on right of use assets has been included in general and administrative
expenses (see note 34 4).
Right of use assets at 31 December 2024 of $1.5 million (2023: $0.4 million)
consisted principally of buildings, with a new office lease entered into in 2024.
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 material accounting policies.
11. Group companies
Details of the Company’s subsidiaries and joint operations at 31 December 2024 is as
follows:
Place of Principal
Name of subsidiary incorporation Proportion of
ownership activity
interest
Gulf Keystone
Petroleum (UK) Limited
1st Floor United Kingdom 100% Management, support, geological,
geophysical and engineering
Brownlow Yard services
7 Roger Street
London, WC1N 2JU
Gulf Keystone
Petroleum
International Limited
c/o Carey Olsen
Services Bermuda
Limited Bermuda 100% Exploration, evaluation,
development and production
5th Floor activities in Kurdistan
Rosebank Centre
11 Bermudiana Road
Pembroke, HM08 Bermuda
Name of joint Principal
operation Location Proportion of ownership
interest activity
Shaikan Kurdistan 80% Production and development
activities
12. Inventories
2024 2023
$’000 $’000
Warehouse stocks and materials 6,829 6,900
Crude oil 234 374
Inventory held for sale 2,789 2,627
9,852 9,901
13. Trade and other receivables
Non-current receivables
2024 2023
$’000 $’000
Trade receivables – non-current 138,175 140,218
Non-current trade receivables relate 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 Reconciliation of trade receivables below).
Current receivables
2024 2023
$’000 $’000
Trade receivables 16,583 6,350
Underlift - 3,806
Other receivables 7,291 3,080
Prepayments and accrued income 2,905 1,882
Total current receivables 26,779 15,118
Total receivables 164,954 155,336
Reconciliation of trade receivables
2024 2023
$’000 $’000
Gross carrying amount 171,026 171,026
Less: Impairment allowance (16,267) (24,458)
Carrying value at 31 December 154,759 146,568
Gross trade receivables relating to export sales of $171.0 million (2023: $171.0
million) are comprised of invoiced amounts due, based upon KBT pricing, from the KRG
for crude oil sales totalling $158.8 million (2023: $158.8 million) related to
October 2022 – March 2023 and a share of Shaikan amounts due from the KRG that GKP
purchased from MOL amounting to $12.2 million (2023: $12.2 million). Although no
legal right of offset exists, the net balance due from the KRG comprises $158.8
million (2023: $158.8 million) included in trade receivables and $7.7 million (2023:
$7.7 million) included within current liabilities (see note 14), resulting in a net
receivable balance due from the KRG relating to crude oil sales of $151.1 million
(2023: $151.1 million).
As detailed in the Sales Revenue accounting policies, 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 KRG. The outstanding receivable balance of
$151.1 million above, comprises $120.4 million cost oil and $30.7 million profit oil
(net of Capacity Building Payment).
While GKP expects to recover the full value of the outstanding invoices and
purchased revenue arrears, an ECL of $16.3 million (2023: $24.5 million) was
provided against the trade receivables balance in accordance with IFRS 9 ‘Financial
Instruments’. During the year, a $8.2 million credit was recognised due to the
decrease in the ECL provision (2023: charge of $21.4 million) arising from the
earlier repayment profile estimated compared to the prior year. During 2025 the
Company expects to begin recovering the cost oil component of the trade receivables
balance due from the KRG via the settlement of invoices (inclusive of both cost and
profit oil) due from oil sales to local customers as the outstanding cost pool
balance declines to a level at or below the trade receivable balance. Following the
export pipeline reopening the remaining overdue trade receivables is expected to be
recovered from the KRG including both the outstanding cost oil balance at that time
and the full profit oil balance referenced above.
As detailed in the Summary of material 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 variables listed within the Summary of material accounting policies,
the only variables with a significant impact upon the profit before tax, when varied
reasonably, are the estimation of the KRG's credit rating for which no official
market data exists and the estimated date of the re-opening of the ITP.
For the purpose of GKP’s ECL calculation, the KRG's deemed CDS was estimated to be
4.88%. An increase of the CDS of 2% would increase the ECL provision by $6.1
million, conversely a decrease of the CDS by 2% would decrease the ECL provision by
$6.4 million.
GKP estimates that the re-opening of the ITP will occur in October 2025, should this
be delayed by 12 months there would be a $7.5 million increase in the ECL provision.
All other variables listed within the Summary of material accounting policies, when
individually reasonably varied, do not have a material impact upon the ECL
valuation.
Other receivables
Included within Other receivables is an amount of $0.5 million (2023: $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 2024 (2023: nil). No
impairments of other receivables have been recognised during the year (2023: nil).
14. Current liabilities
Trade and other payables
2024 2023
$’000 $’000
Trade payables 1,746 11,953
Accrued expenditures 22,228 14,009
Amounts due to KRG not expected to be cash settled 80,905 74,703
Capacity building payment due to KRG on trade receivables 7,687 7,687
Other payables 4,080 683
Lease obligations 395 359
Overlift 236 -
Total trade and other payables 117,277 109,394
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. The stabilising of local sale revenues during 2024 enabled
the Group to settle all overdue trade payables in the first quarter of 2024.
Amounts due to KRG not expected to be cash settled of $80.9 million (2023: $74.7
million) include:
• $40.1 million (2023: $37.7 million) expected to be offset against oil sales to
the KRG up to 2018, together with other amounts since due from the KRG, that
have not been recognised in the financial statements as management consider that
the criteria for revenue recognition have not been satisfied.
• $40.8 million (2023: $37.0 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 Group 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
$40.8 million.
Overlift is the volumes owed by the Company to the KRG through the lifting of
volumes in excess of contractual entitlement in accordance with the PSC. The
overlift is valued at the year-end sales price. The overlift was temporary and the
KRG lifted the volumes in 2025.
Deferred income
At 31 December 2024, deferred income of $0.7 million (2023: $5.2 million) related to
cash advances paid by local oil buyers in advance of lifting oil (See note 2).
Non-current liabilities
2024 2023
$’000 $’000
Non-current lease liability 1,112 39
15. Provisions
2024 2023
Decommissioning provision $’000 $’000
At 1 January 35,312 42,546
New provisions and changes in estimates (693) (8,933)
Unwinding of discount 1,628 1,699
At 31 December 36,247 35,312
The $0.7 million decrease in new provisions and changes in estimates (2023: $8.9
million decrease) comprises an increase relating to new drilling and facilities work
of $0.4 million (2023: $4.2 million), offset by a reduction of $1.1 million (2023:
$13.1 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 at 2.5 % (2023: 2.25%) and discounted at 4.9 % (2023: 4.6%),
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.
16. 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.
Share-based Total
Accelerated tax payments Tax losses
depreciation carried
forward
$’000
$’000 $’000
$’000
At 1 January 2023 (572) 1,181 967 1,576
(Charge)/credit to income 882 (741) (447) (306)
statement
Exchange differences (17) 42 250 275
At 31 December 2023 293 482 770 1,545
(Charge)/credit to income (271) 238 (675) (708)
statement
Exchange differences - (11) (1) (12)
At 31 December 2024 22 709 94 825
17. Financial instruments
2024 2023
$’000 $’000
Financial assets
Cash 102,346 81,709
Receivables 161,426 152,709
263,772 234,418
Financial liabilities
Trade and other payables 118,152 109,433
118,152 109,433
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 $16.3 million provision against trade
receivables (2023: $24.5 million) (see note 13). All financial assets 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 previous years) and equity
attributable to equity holders of the parent. Equity comprises issued capital,
reserves and accumulated losses as disclosed in note 18 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.
Material Accounting Policies
Details of the material 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 material 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 2024, 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 2024, the
maximum exposure to credit risk from a trade receivable outstanding from one
customer is $171.0 million (2023: $171.0 million). Although the Group is confident
in the recovery of the trade receivables balance, a provision of $16.3 million
(2023: $24.5 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.
18. Share capital
2024 2023
$’000 $’000
Authorised:
Common shares of $1 each 292,105 292,105
Common shares
No. of shares Share capital Share premium Total amount
‘000 $’000 $’000 $’000
Balance 1 January 2023 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
Dividends paid - - (34,933) (34,933)
Shares issued 255 255 - 255
Repurchase of ordinary shares (5,693) (5,693) (4,394) (10,087)
Balance 31 December 2024 217,005 217,005 463,985 680,990
At 31 December 2024, a total of 0.1 million common shares at $1 each were held by
the EBT (2023: 0.2 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
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
(iv) 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.
19. Cash flow reconciliation
2024 2023
Notes $’000 $’000
Cash flows from operating activities
Profit/(loss) from operations 4,702 (13,043)
Adjustments for:
Depreciation, depletion and amortisation of property, plant 76,752 40,409
and equipment (including the right of use assets)
Amortisation of intangible assets 1,980 1,648
(Decrease)/Increase of provision for impairment of trade 35 13 (8,191) 21,378
receivables
Share-based payment expense 36 21 3,472 9,673
Provision against inventory held for sale 3 34 2,627
Operating cash flows before movements in working capital 78,749 62,692
Decrease/(Increase) in inventories 49 (7,605)
Increase in trade and other receivables (1,290) (10,741)
Increase in trade and other payables 11,919 3,107
Income taxes received - 67
Cash generated from operations 89,427 47,520
Reconciliation of property, plant and equipment additions to cash flows from
purchase of property, plant and equipment:
2024 2023
$’000 $’000
Associated cash flows
Additions to property, plant and equipment 20,102 58,652
Movement in working capital 7,083 6,764
Non-cash movements
Foreign exchange differences (7) (30)
Purchase of property, plant and equipment 27,178 65,386
20. 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 2024, gross capital commitments
in relation to the Shaikan Field were estimated to be $9.2 million (2023: $2.2
million).
21. Share-based payments
2024 2023
$’000 $’000
Total share options charge 3,472 9,673
The share options charge of $3.5 million (2023: $9.6 million) is comprised of $3.2
million (2023: $9.1 million) related to the LTIP plan and $0.3 million (2023: $0.6
million) 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 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.
In July 2024, Gulf Keystone Petroleum introduced the 2024 LTIP. Under this plan,
Executive Directors were awarded shares consistent with the 2014 LTIP, with the
addition of a two-year post-vesting holding period, during which vested awards
cannot be sold except to cover the tax liability upon exercise. Similarly, the 2024
LTIP granted to senior management follows the 2014 LTIP guidelines, featuring a
three-year vesting period from the grant date, without a post-vesting holding
period, and subject to specific performance conditions. The 2024 LTIP granted to
other staff members consists of nil-cost options with one, two, and three-year
vesting periods, with no post-vesting holding periods or performance conditions
attached.
2024 2023
Number of Number of
share options share options
’000 ’000
Outstanding at 1 January 8,004 8,785
Granted during the year 3,590 6,295
Exercised during the year (516) (6,383)
Forfeited during the year (288) (211)
Expired during the year (1,872) (482)
Outstanding at 31 December 8,918 8,004
Exercisable at 31 December - -
The weighted average share price at the date of exercise for share options exercised
during the year was £1.48 (2023: £1.17).
The inputs into the calculation of fair values of the share options granted during
the year are as follows:
2024 2023
Weighted average share price £1.11 £1.07
Weighted average exercise price Nil Nil
Expected volatility 56.1% 52.5%
Expected life 3 years 3 years
Risk-free rate 4.3% 3.3%
Expected dividend yield (on the basis dividends equivalents Nil Nil
received)
The options outstanding at 31 December 2024 had a weighted average remaining
contractual life of two years (2023: two years).
The aggregate of the estimated fair value of options granted in 2024 is $4.6 million
(2023 $4.6 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).
2024 2023
Number of Number of
share options share options
’000 ’000
Outstanding at 1 January 216 218
Exercised during the year - (180)
Granted during the year - 178
Outstanding at 31 December 216 216
Exercisable at 31 December - -
There were no options exercised during the year under the Deferred Bonus Plan (2023:
the weighted average share price at the date of exercise for share options exercised
was £1.37).
During the year no options were granted to employees under the Deferred Bonus Plan
(2023: 177,832 options granted).
The options outstanding at 31 December 2024 had a weighted average remaining
contractual life of one year (2023: two years).
22. Dividends
During 2024, a total of $35 million dividends (16.048 US cents per Common Share),
being interim dividends, were declared and paid to shareholders. In 2023, a total of
$25 million dividends (11.561 US cents per Common Share).
An interim dividend of $25 million was declared in March 2025.
23. 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 Directors and Officers who served during the year ended 31 December 2024 were as
follows:
M Angle – Chairman (deceased September 2024)
D Thomas – Non-Executive Director became Deputy Chair June 2023, became Interim
Chair September 2024 and became Chair October 2024
J Balkany – Non-Executive Director
M Daryabegui – Non-Executive Director (appointed October 2024)
C Krajicek – Non-Executive Director (appointed October 2024)
W Mwaura – Non-Executive Director
K Wood – Non-Executive Director (resigned June 2024)
J Harris – Chief Executive Officer and Executive Director
G Papineau-Legris – Chief Commercial Officer appointed as Chief Financial Officer
and Executive Director (effective June 2024)
I Weatherdon – Chief Financial Officer and Executive Director (resigned June 2024)
C Kinahan – Chief Human Resources Officer
J Hulme – Chief Operating Officer
A Robinson – Chief Legal Officer and Company Secretary
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 values below are calculated in accordance with IAS 19 and IFRS 2.
2024 2023
$’000 $’000
Short-term employee benefits 7,196 3,463
Share-based payment - options 1,493 4,065
8,689 7,528
Further information about the remuneration of individual Directors is provided in
the Directors’ Emoluments section of the Remuneration Committee report.
24. Contingent Liabilities
The Group has a contingent liability of $27.3 million (2023: $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 resolved as part of those negotiations.
════════════════════════════════════════════════════════════════════════════════════
Dissemination of a Regulatory Announcement, transmitted by EQS Group.
The issuer is solely responsible for the content of this announcement.
════════════════════════════════════════════════════════════════════════════════════
ISIN: BMG4209G2077
Category Code: MSCM
TIDM: GKP
LEI Code: 213800QTAQOSSTNTPO15
Sequence No.: 379576
EQS News ID: 2103402
End of Announcement EQS News Service
══════════════════════════════════════════════════════════════════════════
References
Visible links
1. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=7537a7fbdfc57d30e0441a8d6aa9054d&application_id=2103402&site_id=reuters~~~6aa99418-46f7-48b9-89fd-959a8d2e4912&application_name=news
2. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=61a0d0d3c3695e0228d832bb72706515&application_id=2103402&site_id=reuters~~~6aa99418-46f7-48b9-89fd-959a8d2e4912&application_name=news
3. mailto:aclark@gulfkeystone.com
4. mailto:GKP@fticonsulting.com
5. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=8d526d3701dabe9a2ff9507b71394df8&application_id=2103402&site_id=reuters~~~6aa99418-46f7-48b9-89fd-959a8d2e4912&application_name=news
6. https://eqs-cockpit.com/cgi-bin/fncls.ssp?fn=redirect&url=6965f2bb1ddcf50ad2dd09b21a93cfc7&application_id=2103402&site_id=reuters~~~6aa99418-46f7-48b9-89fd-959a8d2e4912&application_name=news
7. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_2_Revenue
8. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_3_Cost_of
9. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_14_Trade_and
10. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_4_General_and
11. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_5_Share_option
12. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_7_Finance_costs
13. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_7_Finance_costs
14. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_8_Income_tax
15. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_9_Profit__loss__per
16. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_9_Profit__loss__per
17. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_11_Property__plant
18. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_18_Deferred_tax
19. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_13_Inventories
20. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_14_Trade_and
21. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_154_Trade_and
22. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_154_Trade_and
23. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_17_Provisions
24. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_24_Dividend
25. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_23_Share-based_payments
26. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_24_Dividend
27. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_7_Finance_costs_1
28. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_23_Share-based_payments
29. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_23_Share-based_payments
30. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_23_Share-based_payments
31. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_167_Provisions
32. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_17_Deferred_tax
33. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_3_Cost_of
34. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_4_Other_general
35. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_14_Trade_and
36. file:///data/ucdp/tmp/xhtmlconvert_parsn_eqs_6BIJKltz.html#_23_Share-based_payments
============Recent news on Gulf Keystone Petroleum
See all newsREG-Gulf Keystone Petroleum Ltd Director / PDMR Shareholdings
AnnouncementREG-Gulf Keystone Petroleum Ltd Interim Dividend Exchange Rate
AnnouncementREG-Gulf Keystone Petroleum Ltd Director / PDMR Shareholdings
AnnouncementREG-Gulf Keystone Petroleum Ltd Long Term Incentive Plan (“LTIP”) Award
AnnouncementREG-Gulf Keystone Petroleum Ltd Publication of 2024 Annual Report and Accounts & Sustainability Report
Announcement