REG-Gulf Keystone Petroleum Ltd 2025 Full Year Results Announcement
Yesterday 07:02
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Gulf Keystone Petroleum Ltd (GKP)
2025 Full Year Results Announcement
19-March-2026 / 07:00 GMT/BST
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19 March 2026
Gulf Keystone Petroleum Ltd. (LSE & OSE: GKP)
(“Gulf Keystone”, “GKP”, “the Group” or “the Company”)
2025 Full Year Results Announcement
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 2025.
Jon Harris, Gulf Keystone’s Chief Executive Officer, said:
“We delivered a strong operational and financial performance in 2025 in
line with guidance and another year of zero Lost Time Incidents. Free cash
flow generation enabled the continued execution of our strategy as we
balanced investments in production enhancing projects with $50 million of
dividends. Kurdistan pipeline exports restarted in September 2025,
representing a significant milestone for the Company and broader industry.
We started 2026 positively, with production increasing above 44,000 bopd
towards the end of February and consistent export payments generating cash
flow. We have also been making good progress towards a return to
international prices, with lower discounts to Brent visible in 2025 export
invoices.
Since the outbreak of the regional conflict, we have shut-in the Shaikan
Field as a precaution and taken measures to protect staff. We have also
suspended 2026 guidance until production restarts. We are hopeful that the
security situation will stabilise soon and we are ready to quickly restart
production and exports once it is safe to do so. We are in a strong
position to navigate the disruptions, with a robust, debt-free balance
sheet and significant flexibility to reduce expenditures.
Following careful consideration of these factors and the current outlook,
the Board has approved the declaration of a $12.5 million interim
dividend. I would like to thank all of GKP’s staff, shareholders and
broader stakeholder base for their continued support at this challenging
time.”
Highlights to 31 December 2025 and post reporting period
Operational
• Strong operational delivery in 2025:
◦ Gross average production of 41,560 bopd, up 2% relative to the
prior year (2024: 40,689 bopd) and towards the top end of
tightened 40,000 – 42,000 bopd guidance range
◦ Successful transition from trucking sales to pipeline exports via
the Iraq-Türkiye Pipeline (“ITP”) on 27 September 2025
◦ Sanction of water handling facilities at PF-2 to unlock future
production growth and reduce reservoir risk
◦ Safe operations, with zero Lost Time Incidents for over three
years despite busy work programme and security disruptions
• Gross average production of c.41,300 bopd in 2026 year to 28 February:
◦ Gross average production had increased above 44,000 bopd towards
the end of February 2026 reflecting the successful completion of
well workovers and interventions
• On 28 February 2026, the Shaikan Field was shut in as a safety
precaution following the strikes by the US and Israel on Iran and the
subsequent retaliatory strikes in the Middle East, including in
Kurdistan
◦ Gross average production of c.32,100 bopd in 2026 year to 17
March, with estimated annualised losses to date from the shut-in
of approximately 840 bopd a week
◦ The Company is ready to restart production and exports quickly
with an improvement in the security environment
Shaikan Field estimated reserves
• The Company estimates gross 2P reserves of 416 MMstb as at 31 December
2025 (31 December 2024 internal estimate: 443 MMstb)
◦ Reduction relative to prior year reflects gross production of 15
MMstb in 2025 and minor revisions of 12 MMstb
Financial
• Strong financial performance, with disciplined investment in
production enhancing projects, strict cost control and free cash flow
generation underpinning shareholder distributions
• Revenue based on sales invoices, a non-IFRS measure, increased 28% to
$193.1 million (2024 revenue: $151.2 million), reflecting the
production increase and average realised price of $33.9/bbl (2024:
$26.8/bbl)
◦ Average realised price of $50.5/bbl for 2025 exports sales, a
significant improvement on the price achieved from 2025 local
sales of $27.6/bbl and representing a $13.4/bbl discount to Dated
Brent
◦ Cash receipts for 2025 exports sales equated to $30/bbl as per
the interim exports agreements
• Adjusted EBITDA up 46% to $111.4 million in 2025 (2024: $76.1
million), driven by resilient production, cost control in line with
guidance and the sharp increase in realised prices visible in exports
sales invoices
◦ Stable gross Opex per barrel of $4.3/bbl relative to prior year
(2024: $4.4/bbl), with 18% reduction in other G&A expenses to
$9.3 million (2024: $11.4 million)
• Net capital expenditure of $38.8 million (2024: $18.3 million), in
line with guidance and reflecting investment in PF-2 safety upgrades,
well workovers and initial expenditure on PF-2 water handling
installation
• Free cash flow of $29.1 million (2024: $65.4 million), with the
increase in Adjusted EBITDA offset by incremental net capex and a
working capital outflow related to 2025 exports sales receivables
◦ 2025 exports sales receivables reflect the timing difference of
around two months between production and payment and the
differential between invoiced realised prices and cash receipts
of $30/bbl
◦ The amounts receivable at the year-end related to the timing
difference of exports sales have since been collected as expected
in 2026
• $50 million returned to shareholders in 2025 through semi-annual
dividend payments in April and September
• 2025 year-end cash balance of $78.2 million (31 December 2024: $102.3
million) and no debt
◦ Cash balance as at 18 March 2026 of $89.1 million reflecting
consistent payments for exports sales in the year to date
Dual listing on Euronext Growth Oslo
• On 18 February 2026, the Company’s shares began trading on Euronext
Growth Oslo operated by the Oslo Stock Exchange ("OSE")
• Arrangements are being progressed to enable cross-border transfers of
the Company’s shares between Euronext Growth Oslo and the London Stock
Exchange (“LSE”) on or around 1 April 2026
Outlook
• Considering the deterioration of the regional security environment and
the production shut-in, the Company has placed under review its
previous 2026 gross average production guidance of 37,000 – 41,000
bopd
• The Company has also suspended its previous 2026 net capex, net
operating costs and other G&A expenses guidance (respectively $40-$50
million, $55-$60 million and less than $10 million)
• The Company retains a robust balance sheet and significant flexibility
to reduce its work programme and cost base if the production shut-in
persists
• The current interim exports agreements, which expire on 31 March 2026,
are expected to be extended while a review by an international
independent consultant of exports invoices and contractual
costs progresses
◦ On completion of the review, the Company anticipates a
reconciliation to full PSC entitlement at international prices,
both for future sales and volumes sold under the interim
agreements, as well as the negotiation of longer-term exports
agreements
• The Company continues to progress its negotiations with the Kurdistan
Regional Government (“KRG”) regarding a number of historical Shaikan
commercial matters, including the settlement of past oil sales arrears
and other KRG-related assets and liabilities
Shareholder distributions
• Gulf Keystone remains committed to distributing excess cash to
shareholders according to its established approach to shareholder
returns:
◦ The Board reviews the Company’s capacity to pay a dividend on a
semi-annual basis, considering the liquidity needs of the
business and the operating environment and
◦ share buybacks are considered opportunistically throughout the
year
• Consistent payments for export sales have continued in 2026 to date,
demonstrating the viability of the new export arrangements and
generating positive cash flow. However, the recent deterioration in
the regional security environment has impacted production and the
Shaikan Field remains shut-in as a precautionary measure
• The Board has carefully considered these factors, the current security
outlook, the Company’s debt-free balance sheet and ability to reduce
capex and costs. Consequently, it has decided to declare an interim
dividend of $12.5 million, equivalent to $0.0575 per Common Share
◦ The dividend will be paid on 27 April 2026, based on a record
date of 10 April 2026 and ex-dividend date of 9 April 2026
• The Board intends to review the feasibility of a supplementary
dividend payment following a restart of production, exports and
payment receipts
Investor & analyst presentation
Gulf Keystone’s management team will be hosting a presentation for
analysts and investors at 10:00am GMT (11:00am CET) today via live audio
webcast:
1 https://brrmedia.news/GKP_FY25
Sell-side analysts are requested to join the meeting via the dial-in
details provided to them separately and ask questions verbally. Investors
are encouraged to pre-submit written questions via the webcast
registration page, with the opportunity to submit questions live during
the presentation.
A recording of the presentation will be made available on Gulf Keystone’s
website.
Disclosure regulation:
This announcement contains information which is considered to be inside
information pursuant to the UK Market Abuse Regulation (“UK MAR”) and the
EU Market Abuse Regulation (“EU MAR”) and is subject to the disclosure
requirements pursuant to UK MAR, EU MAR article 17 and section 5-12 of the
Norwegian Securities Trading Act. This stock exchange announcement was
published on behalf of Gulf Keystone by Aaron Clark, Head of Investor
Relations and Corporate Communications of Gulf Keystone, at the date and
time as set out above.
Enquiries:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations
& Corporate Communications 2 aclark@gulfkeystone.com
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton
3 GKP@fticonsulting.com
Nick Hennis
or visit: 4 www.gulfkeystone.com
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE & OSE: GKP) is a leading independent
operator and producer in the Kurdistan Region of Iraq. Further information
on Gulf Keystone is available on its website: 5 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
Gulf Keystone delivered a strong operational and financial performance in
2025, with gross average production of 41,560 bopd reflecting an increase
of 2% compared to the prior year. This was despite some operational
disruptions in the summer due to trucking shortages and security issues
related to neighbouring oil fields which caused a temporary field
shutdown. Net capital expenditure and operating costs were delivered in
line with annual guidance, and an important project to install produced
water handling facilities at PF-2 was sanctioned during the year using
lease financing to minimise upfront expenditures. I am pleased to report
that the Company’s safety performance has also remained exemplary, with
another year without a Lost Time Incident.
The robust operational performance, coupled with the Company’s disciplined
approach to capital and operating cost management, meant that significant
free cash flow was generated during the year and this enabled the Company
to distribute $50 million in dividends to our shareholders.
A highlight of 2025 was the successful restart of international pipeline
exports from the Shaikan Field on 27 September 2025. The reopening of the
Iraq-Türkiye Pipeline was the result of two and a half years of sustained
engagement by the Company and other International Oil Companies with key
Government stakeholders. When the pipeline closed in 2023, the Company had
to rapidly respond to the revenue shortage by winding down a large
development programme, reducing its cost base and re-establishing a
presence in the local sales market. The signing of a tripartite interim
export agreement with the Kurdistan Regional Government (“KRG”) and
Federal Government of Iraq (“FGI”), as well as the commencement of
consistent crude oil liftings and payments by an international oil trading
company, is expected to allow a normalisation of export operations with
improved cash generation.
The Company is now working to negotiate and finalise long term export
agreements and to secure payment arrangements with the KRG and FGI, which
are commensurate with the Shaikan PSC terms. These developments should
unlock an improved investment environment for the Kurdistan oil and gas
industry and a strong foundation for future field development. With the
Shaikan Field’s large remaining reserves and resources base, there is a
significant opportunity ahead to invest in profitable production growth
and create additional shareholder value.
We were pleased to announce in September 2025 that the Company was
exploring a potential dual listing of the Company’s shares on Euronext
Growth Oslo, operated by the Oslo Stock Exchange (“OSE”). On 13 February
2026, the Company completed a small retail offering connected with the
listing of just over 500,000 shares, welcoming around 700 new
shareholders. On 18 February 2026, GKP’s shares began trading on Euronext
Growth Oslo for the first time.
The Oslo listing will provide investors active in the Norwegian markets
with better access to GKP’s shares and is expected to improve the
liquidity of the Company’s share capital. It will also enable the Company
to attract new institutional and retail investors from a capital market
that knows GKP and Kurdistan well and who have been very proactive in
financing the oil and gas industry in the region. In early April,
cross-border transfers to Oslo will become possible for all holders of the
UK-listed shares and, in due course, the Company expects to upgrade its
listing to the OSE’s Main Market. As a Board, we are excited about
engaging with new investors in Norway and would like to thank the existing
GKP shareholders for their support during the dual listing process.
While the Company’s medium-term outlook and potential for value creation
remain strong, we are currently adapting to the recent deterioration in
the regional security environment following the strikes by the US and
Israel on Iran on 28 February 2026 and subsequent retaliatory strikes in
the Middle East, including in Kurdistan. The Company’s assets have not
been impacted as at the date of this report and measures have been taken
to protect staff. However, production has been shut-in as a precautionary
measure since the hostilities began, in line with other oil fields in
Kurdistan and Federal Iraq. GKP is in a strong position to weather the
storm, with a robust balance sheet, and we are hopeful that the security
situation will stabilise in the near future and production and exports can
resume. Notwithstanding this, the Company is taking prudent steps to
identify initiatives to reduce capital, operating and running costs if
this proves to be necessary.
Balancing investment in profitable production growth with shareholder
distributions remains central to the Company’s strategy and our
established approach to shareholder distributions is to review the
capacity for dividend payments around the full and half year results,
while considering share buybacks opportunistically throughout the year.
Consistent with this approach, the Board has carefully considered the
regional security outlook and the Company’s current cash position and
proven ability to significantly reduce costs if required. Following this
review, the Board has decided to declare an interim dividend of $12.5
million, to be paid on 27 April 2026, and will consider the feasibility of
a supplementary dividend payment following the restart of production,
exports and payment receipts.
Finally, in June 2025, along with the other members of the GKP Board, I
was delighted to visit the Company’s business operations in Erbil and the
Shaikan Field. During the trip, we met senior officials from the Kurdistan
Regional Government, the Ministry of Natural Resources and various local
authorities, spent time with the GKP team and visited the field
facilities, well sites and local community development projects. It is
clear that GKP has made a significant contribution to Kurdistan during its
long history of investment and operations in the region and, despite the
current security challenges, we believe it will continue to do so. The
Shaikan Field remains a world-class asset and the Board would like to
thank the Company’s management team and staff for their continued efforts
to realise its full potential.
David Thomas
Non-Executive Chair
18 March 2026
CEO review
2025 was a significant year of transition for the Company, defined by the
restart of Kurdistan pipeline exports in September 2025 after over two and
a half years of suspension. Our operational and financial delivery
remained consistent, with production towards the top end of tightened
guidance and investments in production-enhancing projects, primarily the
sanction of water handling at PF-2, balanced with $50 million of dividends
paid to shareholders. While the near-term outlook is uncertain considering
the recent deterioration in the regional security environment, the Company
is in a strong position to navigate this period of turbulence with our
robust cash position, flexibility to moderate our costs should the need
arise and ability to swiftly return to production and exports once the
current situation stabilises.
2025 performance
Safe operations are our number one priority at Gulf Keystone and we were
pleased to record another year without a Lost Time Incident (“LTI”) in
2025. Our continued strong safety performance was delivered in the context
of disruptions to production and field operations over the summer due to
trucking shortages and security issues, the transition from local sales to
exports in September 2025 and a number of active work fronts across our
facilities and well sites. In January 2026 we celebrated three years
without an LTI. We have extended our track record of LTI-free days to over
1,150 as at the date of this report and have gone more than a year without
a recordable incident.
Gross average production in 2025 was 41,560 bopd, towards the top end of
the Company's tightened guidance range of 40,000 – 42,000 bopd and 2%
higher than the prior year (2024: 40,689 bopd). Cumulative volumes from
the Shaikan Field since commercial production began passed 150 million
barrels in November 2025, which is testament to the enduring quality of
the asset.
Local market demand for Shaikan Field crude was consistently strong
between January and May 2025, enabling monthly gross average production
above 45,000 bopd. Production reduced from June to August because of
trucking shortages and security disruptions caused by drone attacks on
other oil fields in the region, the latter leading to the temporary
shut-in of the Shaikan Field between 15 and 31 July 2025. The total loss
of gross production due to these factors amounted to approximately 1.3
MMstb, or approximately 3,500 bopd on an annualised basis.
On 27 September 2025, pipeline exports from the Shaikan Field restarted
based on interim agreements signed by the Company and other IOCs with the
KRG and FGI. All trucking sales ceased on 26 September 2025. The
transition was smooth with volumes quickly ramping up towards full well
capacity following the reopening of the Iraq-Türkiye Pipeline (“ITP”).
The interim exports agreements are in full compliance with the 2023-2025
Federal Iraqi Budget Law (the ‘Budget Law’) while maintaining the sanctity
of Kurdistan’s Production Sharing Contracts (“PSCs”). The Budget Law
provides for an interim period during which IOCs are compensated $16/bbl
for exported production to cover the costs of production and
transportation. As the KRG is no longer paid for its entitlement, but
rather is compensated through FGI budget transfers, the $16/bbl equated to
$30/bbl for 2025 exports sales on a cash received basis, based on the
level of net entitlement for the Shaikan Contractor in the second half of
the year.
Following the interim period, a reconciliation to full PSC entitlement at
international prices and the signing of longer-term agreements is expected
following a review of IOC invoices and contractual costs conducted by an
international independent consultant. The Company expects the interim
exports agreements to be extended beyond their current expiry of 31 March
2026 to facilitate the completion of the consultant’s review. The
Company’s invoiced revenue for exports sales in 2025 indicate the
potential level of international netbacks we could expect to receive, both
in top-up payments for interim period sales and for future exports sales,
with discounts to Dated Brent significantly reduced relative to both 2025
local sales and exports sales prior to the ITP closure in March 2023 (see
the ‘Financial review’ for further detail).
Regular monthly liftings of crude allocated to the Company and other IOCs
by a nominated trader commenced at the Ceyhan oil terminal in Türkiye in
November 2025 and associated payments began in December 2025. Monthly
liftings and payments have continued into 2026 as expected.
The Company’s work programme in 2025 comprised disciplined and targeted
investment in maintaining the safety and reliability of the Shaikan
Field’s production facilities, with safety upgrades progressed at PF-2,
and optimising production through well workovers and interventions.
In August, we were pleased to sanction the installation of water handling
facilities at PF-2. Once operational, the water handling facilities are
expected to unlock an estimated 4,000 – 8,000 bopd of incremental gross
production above the anticipated field baseline from existing constrained
wells and reduce downside risk to reservoir recovery. The facilities will
also add additional wet oil processing capacity of around 17,000 bopd to
the Shaikan Field’s existing dry oil processing capacity of around 60,000
bopd. While good progress has been made on the project since sanction, the
schedule is currently under review due to the regional security
environment.
2026 outlook
Gross production averaged c.41,300 bopd in 2026 year to 28 February, with
production exceeding 44,000 bopd on several days towards the end of
February 2026 reflecting the successful completion of well workovers and
interventions.
Gross production has averaged c.32,100 bopd in 2026 year to 17 March, with
the reduction reflecting the precautionary shut-in of the Shaikan Field
following the strikes by the US and Israel on Iran on 28 February 2026 and
subsequent retaliatory strikes in the Middle East, including in Kurdistan.
Annualised losses to date from the shut-in are estimated at approximately
840 bopd a week. The Company is ready to restart production and exports
quickly with an improvement in the security environment.
Due to the security situation the Company has placed its previous gross
average production guidance for 2026 of 37,000 – 41,000 bopd under review.
The Company has also suspended its 2026 net capex, net operating costs and
other G&A expenses guidance and is assessing initiatives to reduce
expenditures, if required. We will look to reinstate guidance once
production has resumed and the overall impact of the shut-in is known.
Shaikan Field estimated reserves
The Company estimates gross 2P reserves of 416 MMstb as at 31 December
2025 contained in the Jurassic reservoir. The reduction relative to the
2024 year-end internal estimate of 443 MMstb reflects gross production of
15 MMstb in 2025 and minor revisions of 12 MMstb.
Gross 2P reserves have been internally estimated based on a draft FDP,
which models a return to development drilling towards the end of 2026.
Revisions to estimated reserves reflect updated assumptions regarding
reservoir and well performance, partially offset by additional infill
drilling.
Gross 2C resources continue to be estimated at 311 MMstb based on the
Company’s latest independent Competent Person’s Report (“CPR”) prepared by
ERC Equipoise (“ERCE”) as at 31 December 2022. Total gross 2C resources
include an estimated 101 MMstb in the Jurassic reservoir, 157 MMstb in the
Triassic reservoir and 53 MMstb in the Cretaceous reservoir.
The 2022 CPR was the Company’s last published independent third-party
evaluation of the Company's reserves and resources. The Company expects to
commission an updated CPR, including a comprehensive independent
assessment of 1P and 2P reserves and 2C resources, once a path to future
field development has been established.
Jon Harris
Chief Executive Officer
18 March 2026
Financial review
Key financial highlights
Local
Year Export sales sales Year
ended 27 September 1 January ended
to 31 to
31 December 31
December 26 December
2025 September
2025 2024
2025
Gross average production(1) bopd 41,560 43,434 40,891 40,689
Dated Brent(2) $/bbl 69.1 63.9 71.0 80.8
Realised price(1)(3) $/bbl 33.9 50.5 27.6 26.8
Discount to Dated Brent $/bbl 35.2 13.4 43.4 53.9
Revenue (invoiced for the $m 193.1 79.2 113.9 151.2
period)(1)(4)
Revenue (IFRS)(5) $m 164.8 50.9 113.9 151.2
Operating costs $m 52.6 14.0 38.6 52.4
Gross operating costs per $/bbl 4.3 4.2 4.4 4.4
barrel(1)
Other general and $m 9.3 2.0 7.3 11.4
administrative expenses
Share option expense $m 7.0 1.0 6.0 4.4
Adjusted EBITDA(1)(6) $m 111.4 56.8 54.6 76.1
Profit/(loss) after tax $m 15.1 24.0 (8.9) 7.2
Basic earnings/(loss) per cents 7.0 11.1 (4.1) 3.3
share
Revenue receipts(1) $m 122.4 14.1 108.3 144.1
Net capital $m 38.8 14.6 24.2 18.3
expenditure(1)(7)
Free cash flow(1) $m 29.1 (8.3) 37.4 65.4
Shareholder $m 50 0 50 45
distributions(8)
Cash and cash equivalents $m 78.2 78.2 87.2 102.3
1. Represents either a non-financial or non-IFRS measure which are
explained in the summary of non-IFRS measures where applicable.
2. Simple average Dated Brent price; provided as a comparator for
realised price.
3. 2024 realised prices reflect a full year of local sales, 2025 realised
prices reflect local sales from 1 January to 26 September 2025 and
export sales from 27 September to 31 December 2025. Realised prices
for 2025 export sales reflect the full value of entitlement invoices
at international prices with adjustments for quality and
transportation costs. Cash received for 2025 export sales equated to
$30/bbl.
4. Revenue (invoiced for the period) is a non-IFRS measure reflecting the
full value of local and export sales entitlement invoices. See note 2
in the financial statements for further details.
5. Revenue (IFRS) reflects ‘Revenue (invoiced for the period)’ adjusted
for the effective recovery of past receivables.
6. Adjusted EBITDA is based on ‘Revenue (invoiced for the period)’.
7. 2025 net capital expenditure includes a $5.4 million non-cash charge
associated with the capitalisation of drilling inventory previously
classified as held for sale.
8. 2025: $50 million of dividends; 2024: $35 million of dividends and $10
million of completed share buybacks.
2025 was another year of strong delivery in line with annual guidance,
with targeted investment in production-enhancing projects, strict cost
control and continued free cash flow generation underpinning $50 million
of dividend payments to GKP shareholders. The restart of Kurdistan exports
was a pivotal milestone for the Company, with significantly higher
realised prices visible in our invoiced revenue in Q4 2025 and consistent
payments to date for sales under the interim exports agreements.
Looking ahead, the Company is currently navigating the recent
deterioration of the regional security environment and shut-in of
production. We are in a strong position, with a robust balance sheet and
significant flexibility to reduce expenditures should the shut-in persist.
Notwithstanding these immediate challenges, we see several opportunities
for shareholder value creation ahead by securing a return to exports sales
at international prices, concluding our commercial negotiations with the
KRG and capitalising on a new phase of balancing investment in profitable
production growth with shareholder returns as we approach the full
recovery of past recoverable costs.
Adjusted EBITDA
Adjusted EBITDA increased 46% to $111.4 million in 2025 (2024: $76.1
million), driven by a resilient production performance, tight cost control
in line with annual guidance and the sharp increase in realised prices
visible in exports sales invoices following the restart of Shaikan Field
pipeline exports on 27 September 2025.
Revenue based on sales invoices issued in 2025, a non-IFRS measure,
increased 28% to $193.1 million (2024: $151.2 million), reflecting the 2%
improvement in annual production and an average realised price of
$33.9/bbl (2024: $26.8/bbl). Revenue on an IFRS basis was $164.8 million
(2024: $151.2 million) which reflects an adjustment for the effective
recovery of past receivables. The Group is restricted from reporting a
total receivable balance in excess of the unrecovered cost oil balance (or
‘Cost Pool’) and therefore cannot recognise revenue under IFRS beyond this
point. See note 2 in the financial statements for further details.
Under the exports agreements signed in September 2025, crude pricing is
now linked to Dated Brent around cargo lifting windows as opposed to
average monthly Brent pricing in the month of production. The realised
price achieved from export sales in 2025 was $50.5/bbl and therefore
represented a significant improvement on the price achieved from local
sales of $27.6/bbl in January to September 2025 and $26.8/bbl in 2024. The
average discount to Dated Brent of $13.4/bbl arising from 2025 export
sales is encouraging and represents a sizeable reduction compared to the
average discount to Dated Brent of $27.2/bbl in 2022, the last full year
of exports sales prior to the ITP closure in March 2023. However, it is
relatively early in the new export process to project the precise discount
for exports sales going forward given the limited time period, the limited
number of cargo liftings in the period and the ongoing review of the
independent consultant.
The Company continued to exercise rigorous cost control in 2025, with
operating costs and other G&A expenses in line with annual guidance. Gross
operating costs per barrel and operating costs were broadly flat at
$4.3/bbl (2024: $4.4/bbl) and $52.6 million (2024: $52.4 million)
respectively. Other G&A expenses reduced 18% to $9.3 million in 2025
(2024: $11.4 million), primarily reflecting the absence of one-off
retention awards in 2024.
Share option expense was $7.0 million in 2025 (2024: $4.4 million),
principally reflecting the increase in vested awards associated with the
2022 LTIP relative to the vesting of the 2021 LTIP award in 2024.
Cash flows
Revenue receipts, which reflect cash received in the year for the
Company’s net entitlement of local and interim period exports sales (with
the latter reflecting cash receipts of $30/bbl as per the interim exports
agreements), were $122.4 million. Revenue receipts were 15% lower relative
to the prior year (2024: $144.1 million) reflecting the transition from
pre-paid local sales to payments for exports sales typically in the second
month after production. As such, two exports sales payments were received
in December 2025 for two crude liftings in November 2025 covering
September and most of October exports sales. This timing difference of
around two months is reflected as a receivable as at 31 December 2025 of
$32.0 million net to GKP. Payments for exports liftings have continued
consistently to the date of this report, in line with the interim exports
agreements, enabling us to collect the amounts receivable at the year end.
The Company has also accrued a receivable for exports sales under the
interim agreements to account for the differential between realised prices
for cash received from 2025 export sales and the expected reconciliation
to international prices, reflected in the realised prices for invoiced
revenue. This additional receivable totalled $32.8 million net to GKP at
year end 2025. The Company's current expectation is that this receivable,
as well as increases accrued for export sales ahead of the conclusion of
the consultant’s review and interim exports agreements, will be paid in
the form of additional allocated liftings of crude and associated
payments. The estimated payment timing and value of this receivable are
subject to the independent consultant’s report. The current interim
exports agreements, which expire on 31 March 2026, are expected to be
extended to facilitate its completion of the report.
Net capital expenditure in 2025 was $38.8 million (2024: $18.3 million)
reflecting investment in PF-2 safety upgrades, well workovers and initial
expenditure on the installation of water handling facilities at PF-2. Net
capex in the period included a non-cash charge of $5.4 million associated
with the capitalisation of drilling inventory purchased and paid for in
2022 and 2023 that had previously been classified as held for sale
following the wind down of the Company’s expansion programme in 2023.
Excluding this charge, cash net capital expenditure of $33.4 million was
in line with annual guidance.
Free cash flow generation in 2025 was $29.1 million (2024: $65.4 million),
with the increase in Adjusted EBITDA offset by the increase in net capital
expenditure in the year and a working capital outflow related to the 2025
exports sales receivables.
The Company was pleased to pay dividends in the year of $50 million (2024:
$35 million of dividends and $10 million of completed share buybacks),
according to the Company’s announced approach of semi-annual dividend
reviews around the full-year and half-year results.
To satisfy the vesting of the 2022 LTIP award in 2025, purchases of the
Company’s shares were made by the Employee Benefit Trust (“EBT”) in the
first half of the year, amounting to $4.0 million. The Company expects the
EBT to purchase shares to satisfy the potential vesting of future LTIP
awards. The vesting of LTIP awards in previous years has been satisfied by
the issuance of shares.
GKP’s cash balance was $78.2 million as at 31 December 2025 (31 December
2024: $102.3 million) with no outstanding debt. The cash balance as at 18
March 2026 was $89.1 million, with the increase since year end 2025 driven
by continued consistent cash payments for exports sales.
The Group performed a cash flow and liquidity analysis, including the
impact of the ongoing conflict in the Middle East region and the
precautionary shut-in of the Shaikan Field since 28 February 2026.
Consequently, the Group has considered a range of sensitivities, including
delays to a production restart, and remains satisfied that sufficient
levers and mitigating actions are available to preserve liquidity, which
are set out in more detail in the ‘Going concern’ note within the
financial statements. 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, Kalegran B.V.
(a subsidiary of MOL Group (“MOL”), with GKP and MOL together forming the
‘Shaikan Contractor’ or the ‘Contractor’), 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 Capacity
Building Payment (“CBP”) owed to the KRG.
The Cost Pool and R-factor, as defined below, 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 receipt
basis as crude sales are paid.
As the Cost Pool is reported on a cash receipt basis, a large receivable
balance related to 2022-2023 exports sales remains outstanding which has
therefore not yet been deducted from the Cost Pool, as detailed below and
within note 13 of the financial statements. As at 31 December 2025, there
was $152.7 million of unrecovered cost oil for the Shaikan Contractor
($122.2 million net to GKP) in the Cost Pool. The R-factor, calculated as
cumulative Contractor revenue receipts of $2,582 million divided by
cumulative Contractor costs of $2,079 million, was 1.24 as at 31 December
2025. Both the Cost Pool and the R-factor are subject to potential cost
audit by the KRG.
GKP’s net entitlement of total Shaikan Field sales was approximately 36%
in 2025 for amounts invoiced in the year. The Company’s 2025 net
entitlement reflects the effective recovery in the second half of the year
of $28.3 million of cost oil owed to GKP from the outstanding October 2022
to March 2023 receivable balance. Consequently, the total receivable
balance for 2022-2023 exports sales as at 31 December 2025 reduced to
$122.8 million net to GKP (comprising $92.1 million cost oil and $30.7
million profit oil net to GKP). Including receivables in relation to
September to December 2025 export sales, the combined total owed to GKP
amounted to $184.6 million as at 31 December 2025 (comprising $141.8
million cost oil and $42.8 million profit oil).
As previously disclosed, the repayment of the 2022-2023 receivable balance
is a component of the Company’s ongoing commercial negotiations with the
KRG, along with the settlement of other KRG-related assets and
liabilities. The negotiations continue to progress but no agreement has
been reached as at the date of this report.
Looking ahead, the outlook for GKP’s net entitlement in 2026 will depend
on the outcome of these negotiations, among other variables, given the
cost oil component of the outstanding 2022-2023 receivable balance as at
31 December 2025 essentially accounted for the Cost Pool at the same date.
The net effect of settling the receivable balance and the other
KRG-related assets and liabilities under discussion with the KRG is
expected to lead to a lower Cost Pool relative to the 31 December 2025
level, reducing the amount of cost oil that can be recovered and reducing
the Company’s net entitlement.
In due course, the outstanding Cost Pool is expected to be fully
recovered. Increases in realised prices and production as well as the
potential settlement of past overdue invoices, as outlined above, are
expected to accelerate depletion. Once the Cost Pool is fully depleted,
the Company's net entitlement will be below 36% and will be determined by
the revenue realised from oil sales and the amount of recoverable net
capital expenditures and operating costs spent in a given period. A fully
depleted Cost Pool will put the Company in an excellent position to invest
in profitable production growth while continuing to generate free cash
flow, assuming healthy oil prices and consistent exports payments.
Outlook
In light of the current production shut-in, the Company has suspended its
2026 net capital expenditures, net operating costs and other G&A expenses
guidance. The Company retains a robust balance sheet and significant
flexibility to reduce its work programme and cost base should the
production shut-in persist. The Company had previously been expecting net
capex of $40-$50 million, net operating costs of $55-$60 million and other
G&A expenses below $10 million in 2026. The Company will look to update
guidance once production has restarted and the overall impact is known.
Gulf Keystone remains committed to returning potential excess cash to
shareholders via semi-annual dividend payments and opportunistic share
buybacks. As described in the ‘Chair’s statement’, the Board has decided
to declare an interim dividend of $12.5 million, equivalent to $0.0575 per
Common Share, following careful consideration of the Company’s liquidity
needs, current outlook and ability to significantly reduce capital
expenditures and costs. The dividend will be paid on 27 April 2026, based
on a record date of 10 April 2026 and ex-dividend date of 9 April 2026.
The Board intends to review the feasibility of a supplementary dividend
payment following a restart of production, exports and payment receipts.
Gabriel Papineau-Legris
Chief Financial Officer
18 March 2026
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 gross operating costs and non-financial measures such as
gross 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.
2025 2024
Gross production (MMbbls) 15.2 14.9
Gross operating costs ($ million)(1) 65.8 65.5
Gross operating costs per barrel ($ per bbl) 4.3 4.4
(1) Gross operating costs equate to operating costs included in cost of
sales (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.
2025 2024
$ million $ million
Profit after tax 15.1 7.2
Finance costs 2.0 1.7
Finance income (2.7) (4.1)
Tax (credit)/charge (0.5) 0.7
Depreciation of oil and gas assets 77.3 75.8
Depreciation of other PPE assets and amortisation of 2.0 3.0
intangibles
Decrease in expected credit loss provision on trade (7.6) (8.2)
receivables
Adjusted EBITDA (including IFRS revenue) 83.1 76.1
Effective recovery of past receivables 28.3 -
Adjusted EBITDA (including non-IFRS revenue invoiced 111.4 76.1
for the year)
Non-IFRS revenue invoiced for the year includes both local and pipeline
exports as invoiced in 2025 and explained further in note 2.
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.
2025 2024
$ million $ million
Cash 78.2 102.3
Borrowings - -
Net cash 78.2 102.3
The Group was debt free at 31 December 2025 and 31 December 2024.
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.
2025 2024
$ million $ million
Net capital expenditure (see note 10 to the 38.8 18.3
consolidated financial statements)
As detailed in note 10 to the financial statements, the net capital
expenditure in the period ended 31 December 2025, includes $5.4 million of
items originally purchased and paid in 2022 and 2023, but were
subsequently classed as impaired inventory held for sale. Upon delisting
as held for sale these assets have been capitalised, as an oil and gas
asset, but are a non-cash item in the current year. Excluding this charge,
net capital expenditure of $33.4 million was in line with annual guidance.
Free cash flow
Free cash flow represents the Group’s cash flows before any dividends and
share buybacks including related fees.
2025 2024
$ million $ million
Net cash generated from operating activities 63.1 93.5
Net cash used in investing activities (33.6) (27.6)
Payment of leases (0.4) (0.5)
Free cash flow 29.1 65.4
Consolidated income statement
For the year ended 31 December 2025
Notes 2025 2024
$’000 $’000
Non-IFRS measure
Revenue invoiced for the year 6 2 193,093 151,208
Effective recovery of past receivables 7 2 (28,280) -
Revenue 164,813 151,208
IFRS consolidated income statement
Revenue 8 2 164,813 151,208
Cost of sales 9 3 (141,089) (138,866)
Decrease of expected credit loss provision on 10 13 7,558 8,191
trade receivables
Gross profit 31,282 20,533
Other general and administrative expenses 11 4 (9,313) (11,412)
Share option related expenses 12 5 (6,959) (4,419)
Profit from operations 15,010 4,702
Finance income 13 7 2,740 4,116
Finance costs 14 7 (1,976) (1,676)
Foreign exchange (loss)/gain (1,108) 724
Profit before tax 14,666 7,866
Tax credit/(charge) 15 8 468 (708)
Profit after tax 15,134 7,158
Earnings per share (cents)
Basic 16 9 6.97 3.26
Diluted 17 9 6.68 3.13
Consolidated statement of comprehensive income
For the year ended 31 December 2025
2025 2024
$’000 $’000
Profit after tax for the year 15,134 7,158
Items that may be reclassified to the income statement in
subsequent periods:
Exchange gain/(loss) on translation of foreign operations 1,781 (517)
Total comprehensive income for the year 16,915 6,641
Consolidated balance sheet
As at 31 December 2025
Notes 31 December 2025 31 December 2024
$’000 $’000
Non-current assets
Trade receivables 13 84,007 138,175
Intangible assets 260 1,255
Property, plant and equipment 18 10 349,404 388,450
Deferred tax asset 19 16 1,365 825
435,036 528,705
Current assets
Inventories 20 12 7,774 9,852
Trade and other receivables 21 13 125,065 26,779
Cash 78,233 102,346
211,072 138,977
Total assets 646,108 667,682
Current liabilities
Trade and other payables 22 14 (128,314) (117,277)
Deferred income - (716)
(128,314) (117,993)
Non-current liabilities
Trade and other payables 23 14 (928) (1,112)
Decommissioning provision 24 15 (37,839) (36,247)
(38,767) (37,359)
Total liabilities (167,081) (155,352)
Net assets 479,027 512,330
Equity
Share capital 18 217,005 217,005
Share premium 18 414,139 463,985
Exchange translation reserve (2,502) (4,283)
Accumulated losses (149,615) (164,377)
Total equity 479,027 512,330
The notes form part of the financial statements.
The financial statements were approved by the Board of Directors and
authorised for issue on 18 March 2026 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 2025
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 1 222,443 503,312 (3,766) (174,752) 547,237
January 2024
Profit after tax - - - 7,158 7,158
for the year
Exchange
difference on
translation of - - (517) - (517)
foreign
operations
Total
comprehensive - - (517) 7,158 6,641
income for the
year
Dividends paid 25 22 - (34,933) - - (34,933)
Employee share 21 - - - 3,472 3,472
schemes
Share issues 18 255 - - (255) -
Repurchase of 18 (5,693) (4,394) - - (10,087)
ordinary shares
Balance at 31 217,005 463,985 (4,283) (164,377) 512,330
December 2024
Profit after tax - - - 15,134 15,134
for the year
Exchange
difference on
translation of - - 1,781 - 1,781
foreign
operations
Total
comprehensive - - 1,781 15,134 16,915
income for the
year
Dividends paid 26 22 - (49,846) - - (49,846)
Employee share 21 - - - 3,660 3,660
schemes
Reissue of
repurchased 18 - - - (3,702) (3,702)
shares
Own shares
repurchased and 18 - - - (330) (330)
held in Employee
Benefit Trust
Balance at 31 217,005 414,139 (2,502) (149,615) 479,027
December 2025
Consolidated cash flow statement
For the year ended 31 December 2025
2025 2024
Notes
$’000 $’000
Operating activities
Cash generated from operations 19 60,381 89,427
Interest received 27 7 2,740 4,116
Interest paid 7 (25) -
Net cash generated from operating activities 63,096 93,543
Investing activities
Purchase of intangible assets (248) (420)
Purchase of property, plant and equipment 19 (33,314) (27,178)
Net cash used in investing activities (33,562) (27,598)
Financing activities
Payment of dividends 22 (49,846) (34,933)
Purchase of own shares - share buyback - (10,087)
Purchase of own shares - employee share-based (4,032) -
payments
Payment of leases (425) (452)
Net cash used in financing activities (54,303) (45,472)
Net (decrease)/increase in cash (24,769) 20,473
Cash at beginning of year 102,346 81,709
Effect of foreign exchange rate changes 656 164
Cash at end of the year being bank balances and 78,233 102,346
cash on hand
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 29 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 2024 or 2025 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 2025.
The following new accounting standards, amendments to existing standards
and interpretations are effective on 1 January 2025: Lack of
Exchangeability (Amendments to IAS 21) and Amendments to the SASB
standards to enhance their international applicability. 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 (“IAS”):
IFRS S1 General Requirements for Disclosure of
Sustainability-related Financial Information
IFRS S2 Climate-related Disclosures; Amendments to
Greenhouse Gas Emissions Disclosures
IFRS 19 Subsidiaries without Public Accountability:
Disclosures
Amendments IFRS 9 and Classification and measurement of financial
IFRS 7 instruments; Contracts Referencing Nature-dependent
Electricity
IFRS 1: Hedge accounting by a first-time adopter;
IFRS 7: Gain or loss on derecognition; IFRS 7:
Annual Improvements to Disclosure of deferred difference between fair
IFRS Accounting value and transaction price; IFRS 7: Introduction
Standards - Volume 11 and credit risk disclosures; IFRS 9: Lessee
derecognition of lease liabilities; IFRS 9:
Transaction price; IFRS 10: Determination of a ‘de
facto agent’; IAS 7: Cost method
Amendments to IAS 21 Translation to a Hyperinflationary Presentation
Currency
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
material 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, together with its cash flows and liquidity
position, is presented in the Financial review.
As at 18 March 2026, the Group had $89.1 million of cash and no debt. The
Group continues to monitor and manage its liquidity closely. Cash
forecasts are updated regularly, and sensitivities are run for different
scenarios reflecting the latest operational and commercial outlook,
including revenue receipts under interim export arrangements, the timing
of the return to full Production Sharing Contract (“PSC”) entitlement and
expenditure phasing. The Group remains focused on taking appropriate
actions to preserve its liquidity position.
On 28 February 2026, the Shaikan Field was shut-in as a safety precaution
following the strikes by the US and Israel on Iran and the subsequent
retaliatory strikes in the Middle East, including in the Kurdistan.
Production remains shut-in at the date of this report and the Company is
taking all reasonable steps to maintain security and safeguarding the
value of the asset during this time. There has been no damage to the
Group’s assets, and appropriate steps were taken to protect staff. The
Company is monitoring for an opportunity to safely and quickly restart
production with an improvement in the security environment.
The Group’s liquidity position has remained stable up to the date of this
report, supported by the resumption of export sales in late 2025. Prior
to the precautionary shut‑in on 28 February 2026, regular liftings and
associated payments continued under the interim agreements. While
production is currently shut-in, the interim export arrangements remain in
place until 31 March 2026. The Group expects that these arrangements will
be extended. A review by an independent consultant of International Oil
Companies’ invoices and contractual cost structures is underway to support
reconciliation to full PSC entitlement (see note 13).
Export sales are currently impacted by the precautionary shut‑in of the
Shaikan field. The key uncertainties relevant to the going concern
assessment include:
• Geopolitical and security environment: the duration and impact of the
ongoing conflict in the wider Middle East region is difficult to
predict;
• Continuation of interim export arrangements: the renewal of agreements
beyond 31 March 2026, and the regularity and timing of export
receipts;
• PSC entitlement reconciliation: completion of the consultant‑led
review and timing of transition to full entitlement pricing; and
• Outstanding commercial matters – progression of discussions with the
Ministry of Natural Resources (“MNR”) regarding arrears, cost audit,
PSC amendments and associated commercial issues.
The Directors have considered a range of sensitivities, including an
extension of interim export arrangements, delays to returning to full PSC
entitlement and prolonged delays to production restart due to the conflict
in the wider Middle East region. Across these sensitivities, the Group
retains the ability to implement mitigating actions, including the
deferral of discretionary expenditure and the phasing of activity, to
preserve liquidity while maintaining safe operations and the ability to
promptly restart production.
As explained in note 14, although the Group has recognised current
liabilities payable to the Kurdistan Regional Government (“KRG”), these
are not expected to be cash settled.
Overall, the Group’s forecasts, taking into account the applicable risks,
scenario testing and available mitigating actions, indicate that the Group
has sufficient financial resources for the 12‑month period from the date
of approval of the 2025 annual report and accounts. Based on this
analysis, the Directors have a reasonable expectation that the Group has
adequate resources to continue to operate for the foreseeable future.
Accordingly, the going concern basis of accounting continues to be adopted
for the preparation of these 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) as at and for the year ending 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 Group recovers
its costs incurred, and profit oil, which is the mechanism through which
profits are shared between the Group, its partner and the KRG. The Group
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 for all of 2024 and up until 26 September
2025, the delivery point was the point at which crude oil was loaded into
the buyers’ nominated trucks. The consideration was determined by
reference to the selling price as per crude sales agreements with local
customers, with other fees and royalties due as determined by commercial
agreements; revenue was reported net of these deductions.
Since the reopening of the ITP on 27 September 2025, all oil is sold by
the Shaikan Contractor (the Group and Kalegran BV, a subsidiary of MOL
Hungarian Oil & Gas Plc, (“MOL”)) to the KRG, who in turn resell the oil.
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 delivery point the Shaikan Contractor is
due economic benefits which can be reliably measured and are probable to
be received.
For sales since the reopening of the ITP, the delivery point is the export
pipeline flange at the production facilities. The sale price determined by
the closing oil market price on the last day of the production month, 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. Consideration is due based upon the oil market
price upon lifting at the port of Ceyhan, after other fees and royalties
due as determined by commercial agreements. The variation between the
sales price and consideration received is recorded as an embedded
derivative in line with IFRS 9, not as variable consideration according to
IFRS 1 (see note 2 to the consolidated financial statements)
Income tax arising from the Group’s activities under its PSC is settled by
the KRG on behalf of the Group. Since the Group 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 2025 was based on internal estimates of reserves which are
periodically independently reviewed via a Competent Person’s Report
(“CPR”). The last CPR was prepared by ERC Equipoise as at 31 December
2022. For calculating DD&A, future production and cash flows are modelled
alongside estimated future expenditure to determine GKP’s future net
economic entitlement.
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 containing embedded derivatives are measured at fair
value through profit or loss in line with IFRS 9, with all other trade
receivables measured at amortised cost.
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. 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 capital
and share premium as appropriate.
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 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.
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 trade and other
payables as current or non-current liabilities depending on underlying
lease terms.
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 over the lease term.
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.
Past due trade receivable valuation
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 to the past due trade receivable considered
whether it was appropriate to recognise export revenue for deliveries from
October 2022 to March 2023 based on a proposed new pricing mechanism,
notwithstanding that there was no signed lifting agreement for that period
confirming the pricing mechanism. 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 discrete receipts for the period of pipeline exports
from 1 October 2022 to 25 March 2023 have been received.
Cost oil entitlement
For so long as GKP’s cost pool exceeds the cost oil component of the trade
receivables balance, GKP’s cost oil entitlement is aligned between revenue
and invoiced amounts at 28.8% of gross field revenues (40% Contractor cost
oil, less 10% royalty, GKP paying interest of 80%). It has been adjudged
that in the event that the cost oil component of trade receivables exceeds
the cost pool balance, revenue is capped to the level of recoverable costs
incurred in the period with the outstanding cost oil trade receivable
making up the full 28.8% invoiced. Cost oil trade receivables, when
rebilled, are therefore not recognised as revenue transactions. In 2025
GKP’s cost pool balance reduced to the level of outstanding cost oil trade
receivables which largely results from the level of past due receivables
as detailed in note 13. As a result amounts invoiced in 2025 included
$28.3m of cost oil trade receivables rebilling that is not included within
revenue. Future cash flows are expected to align to the full cost oil
entitlement invoiced.
A summary of the currently estimated financial impact of cost oil revenue
being limited by the available cost pool is detailed in note 2.
Profit oil entitlement
Profit oil entitlement is dependent upon the R-factor and cost oil
component described above, as determined by the PSC. GKP judges that the
R-factor is to be calculated on a cash receipts basis; giving a current
profit oil entitlement of approximately 9% when cost oil is capped at
28.8%. A reduction of approximately 2% is expected on cash receipts
relating to capacity building payments payable as described below. GKP’s
invoiced entitlement is approximately 38%, being a combination of cost and
profit oil; cash receipts are expected to be at 36% entitlement after a 2%
capacity building payment reduction.
Working interest and capacity building payments
During past PSC negotiations with the 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.
Any future agreements between the Group and the MNR could change the
amounts of revenue or expense recognised and will be reflected in future
periods.
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 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 2025.
Management have increased the decommissioning 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 2025 was the Shaikan Field with a
carrying value, being Oil and Gas assets less capitalised decommissioning
provision, of $308.6 million (2024: $348.9 million). The Group performed
an impairment indicator evaluation as at 31 December 2025 and concluded
that no impairment indicators arose. The key areas of estimation in
assessing the potential impairment indicators are as follows:
• The ITP re-opened in late September 2025. This timing is within the
two-year sensitivity period based on the assessment performed at 31
December 2023, with no impairment, therefore the actual re-opening
date was not assessed to be an impairment trigger;
• The Group’s netback oil price applied only to export pipeline sales
was based on the Brent forward curve and market participants’
consensus, including banks, analysts and independent reserves
evaluators, as at 31 December 2025 for the period 2026 to 2032 with
inflation of 2.50% per annum thereafter, less transportation costs and
quality adjustments. Brent consensus prices are as follows
2025 2026
Scenario ($/bbl – nominal) 2027 2028 2029 2030 2031 2032
31 December 2025 – base case n/a 62.0 65.0 70.0 70.0 72.0 79.0 80.0
31 December 2025 – stress case n/a 55.8 58.5 63.0 63.0 64.8 71.1 72.0
31 December 2024 – base case 74.0 72.0 74.0 75.0 73.0 80.0 82.0 84.1
31 December 2024 – stress case 66.6 64.8 66.6 67.5 65.7 72.0 73.8 75.7
• 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 a
reduction in the rate was necessary. The post-tax nominal discount
rate was estimated to be 15%, a 1% reduction from 31 December 2024;
• 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 materially increase in comparison
to 31 December 2023 impairment assessment;
• No adverse changes were noted for commercial reserves and production
profiles;
• The field was shut-in July 2025 as a precaution after drone attacks at
other oil fields in Kurdistan. Operations resumed in August 2025 after
a security review with the KRG and production returned to full
capacity. On 28 February 2026, the Group again suspended production
operations as a precautionary measure in response to the wider Middle
East conflict. There has been no damage to the Group’s assets, and
appropriate measures were taken to safeguard staff. The situation
continues to be monitored, and operations will resume once conditions
allow. The potential impact of this event has not been included in the
assessment because it is a post‑balance‑sheet non‑adjusting event; 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 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.
The 2025 World Energy Outlook NZE scenario now assumes that global
temperatures exceed 1.5°C for several decades, peaking at
approximately 1.65°C around 2050, before gradually declining to below
1.5°C by 2100 through rapid emissions reductions and the deployment of
CO₂ removal technologies. The actual re-opening date is consistent
with the assessment as at 31 December 2023, where management performed
sensitivities of up to two years. There was no impairment under the
APS scenario, but a potential impairment under the NZE scenario.
Management has performed an updated assessment using the latest data
from the World Energy Outlook 2025 and this indicates that there is no
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% (2024: 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
2025 2024
$’000 $’000
Non-IFRS measure
Revenue invoiced for the year 193,093 151,208
Effective recovery of past receivables (28,280) -
Revenue 164,813 151,208
Oil sales via export pipeline 54,477 -
Local oil sales 113,892 151,208
Revenue in accordance with IFRS 15 168,369 151,208
Embedded derivative on trade receivables from 2025 export (3,556) -
sales (see note 13) in accordance with IFRS 9
Revenue 164,813 151,208
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.
Non-IFRS measure
GKP’s entitlement as per 2025 export contracts, has been invoiced and
either cash settled in 2025 or expected to be cash settled in 2026,
subject to subsequent price variation in line with export contracts and
completion of the international independent consultant’s review confirming
entitlement and related invoices. Entitlement on an invoicing basis
remains at approximately 38% net to GKP with an approximate 2% reduction,
relating to 20% capacity building payments, reducing cash receipts to an
effective 36% entitlement.
For financial reporting purposes and as required under IFRS, the
unrecovered cost pool is effectively decreased by the cost oil component
of past due trade receivables (see note 13). Upon the cost oil component
of trade receivables equalling the unrecovered cost pool, invoices issued
at 38% entitlement effectively recovering the cost oil component of
outstanding trade receivables.
Invoiced amounts that the Group expect to result in cash inflows total
$193.1 million (2024: $151.2 million) with $64.8 million remaining
outstanding as at 31 December 2025 as disclosed in note 13 (prior to ECL).
The effective rebilling of past due receivables totalled $28.3 million
(2024: not applicable), therefore revenue, in accordance with IFRS 15, was
capped at $164.8 million.
Local oil sales (from 1 January 2024 – 26 September 2025)
For the duration of local oil sales, GKP sold oil to local buyers at
negotiated prices. The weighted average realised price achieved was
$27.6/bbl (2024: $26.8/bbl).
Oil sales via export pipeline (from 27 September 2025 – 31 December 2025)
Following the reopening of the Iraq-Türkiye Pipeline (“ITP”), on 27
September 2025 GKP resumed exports of oil that are lifted at the port of
Ceyhan, Türkiye.
GKP’s performance obligation is satisfied upon oil entering the ITP at the
Group’s production facilities. Revenue is valued using the estimated
realisable price when the Group’s entitlement barrels enter the ITP.
The estimated weighted average realisable price for export revenue via the
pipeline in 2025 was $50.5/bbl (2024: not applicable) with approximately
$30/bbl achieved to date and settled within approximately two months of
production in line with export contracts. The remaining balance
outstanding of approximately $32.8 million (subject to price variation) is
payable subject to completion of the independent consultant’s review
referenced above.
The transaction price that results in cash flows to GKP is determined by
the realised price when oil is lifted at the port of Ceyhan. The
difference between the estimated realisable price when oil enters the
pipeline at the Group’s production facilities and the actual realised
price when lifted at Ceyhan, or the estimated realisable price for barrels
input into the pipeline but unlifted at year end, is accounted for as an
embedded derivative in accordance with IFRS 9.
Information about major customers
Customers making up greater than 10% of revenue are as follows:
2025 2024
Kurdistan Regional Government 31% 0%
Customer A 45% 88%
Customer B 12% <10%
Customer C 12% <10%
3. Cost of sales
2025 2024
$’000 $’000
Operating costs 52,639 52,435
Capacity building payments 13,583 10,818
Change in oil inventory value (59) (168)
Depreciation of oil and gas assets and operational assets 77,308 75,781
(see note 10)
Reversal of provision against inventory held for sale (2,627) -
Loss on disposal of drilling stock 245 -
141,089 138,866
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 is based upon internal reserves and development
cost estimates. The increase in charge compared to 2024 is principally
derived from higher production in 2025.
During the year ended 31 December 2025, inventory formerly held for sale
was reassessed to no longer be held for sale. Whilst held for sale this
inventory was provided against, upon reassessment this provision has been
reversed resulting in a gain of $2.6m in the year ended 31 December 2025
(2024: nil). Following this reversal these items were capitalised as an
addition to oil and gas assets (see note 10).
4. Other general and administrative expenses
2025 2024
$’000
$’000
Depreciation and amortisation 2,049 3,033
Auditor’s remuneration (see below) 704 679
Other general and administrative costs 6,560 7,700
9,313 11,412
2025 2024
$’000 $’000
Fees payable to the Company’s auditor:
for the audit of the Company’s annual accounts 562 530
for the audit of the Company’s subsidiaries 26 32
Total audit fees 588 562
Other assurance services (including a half year review) 116 117
Total fees 704 679
5. Share option related expense
2025 2024
$’000 $’000
Share-based payment expense 3,660 3,472
Payments related to share options exercised 2,543 704
Share-based payment related provision for taxes 756 243
6,959 4,419
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 (assuming the dividend has been paid or gone
ex-dividend) 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.
The increase in payments related to share options exercised reflects a
higher number of options exercised during the year. This was primarily
driven by a higher LTIP vesting percentage which is calculated based upon
performance conditions of both absolute and relative Total Shareholder
Return (“TSR”) (2025: 75% of the 2022 LTIP; 2024: 30% of the 2021 LTIP).
In addition, the Year 1 tranche of the 2024 LTIP vested in 2025. The
increase was further impacted by a higher share price at the date of
exercise (see note 21).
6. Staff costs
The average number of employees, including Executive Directors, and
contractors employed by the Group was 433 (2024: 411); the number of
full-time equivalents of these workers was 287 (2024: 274).
Average number of Average number of full-time
employees equivalents
2025 2024 2025 2024
Kurdistan 409 387 263 250
United Kingdom 24 24 24 24
Total 433 411 287 274
Staff costs as follows are shown net of amounts recharged to joint
operations:
2025 2024
$’000 $’000
Wages and salaries 39,315 37,833
Social security costs 2,446 2,723
Pension costs 456 472
Share-based payment (see note 30 21) 6,959 4,419
49,176 45,447
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
2025 2024
$’000 $’000
Lease interest (161) (48)
Unwinding of discount on provisions (see note 31 15) (1,790) (1,628)
Interest expense (25) -
Total finance costs (1,976) (1,676)
Finance income 2,740 4,116
Net finance income 764 2,440
8. Income tax
2025 2024
$’000 $’000
Deferred UK corporation tax credit/(charge) (see note 32 16) 468 (708)
Tax credit/(charge) attributable to the Company and its 468 (708)
subsidiaries
The Group is not required to pay taxes in Bermuda on either income or
capital gains. The Group has received an undertaking from the Minister of
Finance in Bermuda exempting it from any such taxes at least until the
year 2035.
In the KRI, the Group is subject to corporate income tax on its income
from petroleum operations under the Kurdistan PSC. Under the Shaikan PSC,
any corporate income tax arising from petroleum operations will be paid
from the KRG’s share of petroleum profits. Due to the uncertainty over the
payment mechanism for oil sales in Kurdistan, it has not been possible to
measure reliably the taxation due that has been paid on behalf of the
Group by the KRG and therefore the notional tax amounts have not been
included in revenue or in the tax charge. This is an accounting
presentational point and there is no taxation to be paid.
Deferred tax is provided for temporary differences which give rise to such
a balance in jurisdictions subject to income tax. All deferred tax arises
in the UK. The annual UK corporation tax rate for the years ended 31
December 2025 and 31 December 2024 was 19% on profits up to £50k tapered
to 25% on profits above £250k.
9. Earnings per share
The calculation of the basic and diluted profit per share is based on the
following data:
2025 2024
Profit after tax for basic and diluted per share 15,134 7,158
calculations ($’000)
Number of shares (‘000s):
Basic weighted average number of ordinary shares 217,005 219,562
Basic EPS (cents) 6.97 3.26
The Group applies IAS 33 in determining whether potential common shares
are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
2025 2024
Number of shares (‘000s)
Basic weighted average number of ordinary shares 217,005 219,562
outstanding
Effect of potential dilutive share options 9,557 9,134
Diluted number of ordinary shares outstanding 226,562 228,696
Diluted EPS (cents) 6.68 3.13
The weighted average number of ordinary shares in issue excludes shares
held by Employee Benefit Trustee (“EBT”) of 0.1 million, (2024: 0.1
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
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 (693) - - (693)
decommissioning asset
Depreciation charge (75,781) (576) (394) (76,751)
Disposals’ depreciation - - 2,004 2,004
Foreign currency - (1) (6) (7)
translation 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
Year ended 31 December
2025
Opening net book value 385,171 1,773 1,506 388,450
Additions 38,788 365 - 39,153
Disposals’ cost - (2,021) - (2,021)
Revision to (198) - - (198)
decommissioning asset
Depreciation charge (77,308) (475) (325) (78,108)
Disposals’ depreciation - 2,021 - 2,021
Foreign currency - 5 102 107
translation differences
Closing net book value 346,453 1,668 1,283 349,404
At 31 December 2025
Cost 1,049,019 8,035 1,803 1,058,857
Accumulated depreciation (702,566) (6,367) (520) (709,453)
Net book value 346,453 1,668 1,283 349,404
The net book value of oil and gas assets at 31 December 2025 is comprised
of property, plant and equipment relating to the Shaikan block with a
carrying value of $346.5 million (2024: $385.2 million).
The additions to the Shaikan asset amounting to $38.8 million during the
year included investment in PF-2 safety upgrades, well workovers and
initial expenditure on the installation of water handling facilities at
PF-2 as well as items purchased and paid for in 2022 and 2023 and
subsequently classified as impaired inventory held for sale (see note 3).
Upon delisting as held for sale, the items were capitalised as oil and gas
assets at their unimpaired
value of $5.4 million (2024: not applicable).
The $0.2 million decrease (2024: $0.7 million decrease) in decommissioning
asset value comprises a $1.9 million decrease relating to changes of
inflation and discount rates (2024: $1.1 million), partially offset by an
increase of $1.7 million relating to increases in well estimates and
additional facilities works (2024: $0.4 million).
The DD&A charge of $77.3 million (2024: $75.8 million) on oil and gas
assets has been included within cost of sales (see note 33 3). The
depreciation charge of $0.5 million (2024: $0.6 million) on fixtures and
equipment and $0.3 million (2024: $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 2025 of $1.3 million (2024: $1.5
million) consisted principally of buildings.
For details of the key assumptions and judgements underlying the
impairment assessment, refer to the “Critical accounting estimates and
judgements” section of the Summary of material accounting policies.
11. Group companies
Details of the Company’s subsidiaries and joint operations at 31 December
2025 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
Brownlow Yard and engineering 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
2025 2024
$’000 $’000
Warehouse stocks and materials 7,481 6,829
Crude oil 293 234
Inventory held for sale - 2,789
7,774 9,852
13. Trade and other receivables
Non-current receivables
2025 2024
$’000 $’000
Trade receivables – non-current 84,007 138,175
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
2025 2024
$’000 $’000
Trade receivables 114,835 16,583
Other receivables 8,333 7,291
Prepayments and accrued income 1,897 2,905
Trade and other receivables - current 125,065 26,779
Total trade and other receivables - current and 209,072 164,954
non-current
Reconciliation of trade receivables
2025 2024
$’000 $’000
Amounts related to past due trade receivables
Gross past due trade receivables before impairment 142,745 171,026
allowance
Less: Impairment allowance (8,351) (16,267)
Carrying value at 31 December 134,394 154,759
Amounts related to trade receivables from 2025 export
sales
Gross trade receivables from 2025 export sales before 64,805 -
impairment allowance
Less: Impairment allowance (357) -
Carrying value at 31 December 64,448 -
Total trade receivables - current and non-current 198,842 154,759
Amounts related to past due trade receivables
Gross past due trade receivables before impairment allowance of $142.7
million (2024: $171.0 million) are comprised of invoiced amounts due from
the KRG, based upon KBT pricing, for crude oil export sales totalling
$130.5 million (2024: $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 (2024: $12.2 million). Although no legal
right of offset exists, the net balance past due from the KRG comprises
$130.5 million (2024: $158.8 million) included in trade receivables and
$7.7 million (2024: $7.7 million) included within current liabilities
relating to capacity building payment accrued at 20% (see note 14),
resulting in a net past due receivable balance due from the KRG relating
to crude oil sales in 2022 and 2023 of $122.8 million (2024: $151.1
million).
As detailed in the Sales Revenue accounting policies, entitlement has two
components: cost oil, which is the mechanism by which the Group recovers
its costs incurred, and profit oil, which is the mechanism through which
profits are shared between the Group, its partner and the KRG. The past
due trade receivable balance of $122.8 million above (2024: $151.1
million), comprises $92.1 million (2024: $120.4 million) cost oil and
$30.7 million profit oil (net of Capacity Building Payment). Although no
legal right of offset exists, it is expected that $29.6 million of the
past due balance will be offset against amounts due to the KRG (see note
14).
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. With cost oil trade receivables restricted by the cost pool
balance the impact of the proposed pricing mechanism impacts only the
value of past due profit oil receivables.
Impairment allowance / Decrease of expected credit loss provision on trade
receivables
Although GKP continues to rebill past due cost oil trade receivables (see
note 2) and negotiate settlement of past due profit oil as well as
purchased revenue arrears, an ECL of $8.7 million (2024: $16.3 million)
was provided against the trade receivables balance in accordance with IFRS
9 ‘Financial Instruments’. During the year, a $7.6 million credit to the
income statement was recognised due to the decrease in the ECL provision
(2024: credit of $8.2 million) arising principally from the lower past due
balances outstanding due to rebilled amounts and an earlier repayment
profile, as well as an earlier expected repayment profile on receivable
amounts due under the mechanism agreed within the 2025 export agreements.
The Group expects to continue to invoice and recover the cost oil
component of past due trade receivables, via monthly invoicing of exports
up to a full 36% GKP entitlement net of capacity building payment.
Amounts related to trade receivables from 2025 export sales
Gross trade receivables, relating to export sales via the reopened ITP in
September 2025, of $64.8 million (2024: nil) are amounts due under
contracts signed with the KRG and the Federal Government of Iraq (“FGI”).
Outstanding amounts comprise two components:
• $32.0 million equivalent to approximately $30/bbl on barrels input
into the ITP; cash receipts continue to be received within
approximately two months of production, and one month after those
quantities are lifted of at the port of Ceyhan, and
• $32.8 million being a reconciliation to GKP’s invoiced 38%
pre-capacity building payment entitlement; cash receipts are due
following the conclusion of an independent consultant’s review of the
Shaikan Contractor’s invoices and contractual costs.
Although no legal right of offset exists, $3.0 million (2024: nil) relates
to capacity building payment accrued at 20% within current liabilities
(see note 14), resulting in a net past due receivable balance due from the
KRG relating to 2025 export sales of $61.8 million (2024: nil). This 2025
export sales trade receivable balance of $61.8 million above, comprises
$49.7 million cost oil and $12.1 million profit oil (net of capacity
building payment).
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, the estimated timing of
cash receipts and the probability of reaching a commercial settlement.
For the purpose of GKP’s ECL calculation, the KRG's deemed CDS was
estimated to be 3.36%. When applied to appropriate receipt profiles, an
increase of the CDS of 2% would increase the ECL provision by $4.4
million, conversely a decrease of the CDS of 2% would decrease the ECL
provision by $4.7 million.
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 $0.1 million (2024: $0.5
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 2025 (2024: nil). No impairments of other receivables have been
recognised during the year (2024: nil).
14. Liabilities
Trade and other payables - current
2025 2024
$’000 $’000
Trade payables 2,520 1,746
Accrued expenditures 26,897 22,228
Amounts due to KRG not expected to be cash settled 87,184 80,905
Capacity building payment due to KRG on past due trade 7,687 7,687
receivables
Capacity building payment due to KRG on 2025 export sales 3,014 -
trade receivables
Other payables 588 4,080
Lease obligations 424 395
Overlift - 236
Total trade and other payables - current 128,314 117,277
Trade payables and accrued expenditures principally comprise amounts
outstanding for trade purchases and ongoing costs; the Directors consider
that carrying amounts approximate fair value.
Amounts due to KRG not expected to be cash settled of $87.2 million (2024:
$80.9 million) include:
• $41.9 million (2024: $40.1 million) expected to be offset against
amounts due from the KRG:
◦ $12.3 million relating to profit oil sales up to 2018 that have
not been recognised in the financial statements as management
consider that the criteria for revenue recognition have not been
satisfied, and;
◦ $29.6 million relating to a partial offset of past due trade
receivables (see note 13).
• $45.3 million (2024: $40.8 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 Group’s 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 $45.3 million.
Non-current liabilities
2025 2024
$’000 $’000
Non-current lease liability 928 1,112
15. Decommissioning provision
2025 2024
$’000 $’000
At 1 January 36,247 35,312
New provisions and changes in estimates (198) (693)
Unwinding of discount 1,790 1,628
At 31 December 37,839 36,247
The $0.2 million decrease in new provisions and changes in estimates
(2024: $0.7 million decrease) comprises $1.9 million decrease relating to
changes of inflation and discount rates (2024: $1.1 million decrease),
partially offset by an increase of $1.7 million relating to increases in
well estimates and additional facilities works (2024: $0.4 million
increase). The provision for decommissioning is based on the net present
value of the Group’s estimated share of expenditure, inflated at 2.25%
(2024: 2.5%) and discounted at 4.8 % (2024: 4.9%), 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 2024 293 482 770 1,545
Tax (charge)/credit to (271) 238 (675) (708)
income statement
Exchange differences - (11) (1) (12)
At 31 December 2024 22 709 94 825
Tax credit/(charge) to 176 323 (31) 468
income statement
Exchange differences 6 60 6 72
At 31 December 2025 204 1,092 69 1,365
17. Financial instruments
2025 2024
$’000 $’000
Financial assets
Cash 78,233 102,346
Receivables 208,541 161,426
286,774 263,772
Financial liabilities
Trade and other payables 129,242 118,152
129,242 118,152
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 an $8.7 million provision against
trade receivables (2024: $16.3 million) (see note 13). All financial
assets, except trade receivables containing embedded derivatives, 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 2025, 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 2025, the maximum exposure to credit risk from a trade receivable
outstanding from one counterparty is $207.6 million (2024: $171.0
million). Although the Group expects to recover the full trade receivables
balance, a provision of $8.7 million (2024: $16.3 million) was recognised
against the trade receivables balance in accordance with IFRS 9 (see note
13).
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
2025 2024
$’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 222,443 222,443 503,312 725,755
2024
Dividends paid - - (34,933) (34,933)
Shares issued 255 255 - 255
Repurchase of (5,693) (5,693) (4,394) (10,087)
ordinary shares
Balance 31 December 217,005 217,005 463,985 680,990
2024
Dividends paid - - (49,846) (49,846)
Balance 31 December 217,005 217,005 414,139 631,144
2025
At 31 December 2025, a total of 0.1 million common shares at $1 each were
held by the EBT (2024: 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 shares and to participate further in
(iv) 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
2025 2024
Notes
$’000 $’000
Cash flows from operating activities
Profit from operations 15,010 4,702
Adjustments for:
Depreciation, depletion and amortisation of
property, plant and equipment (including the right 78,108 76,752
of use assets)
Amortisation of intangible assets 1,248 1,980
Decrease of expected credit loss provision on 35 13 (7,558) (8,191)
trade receivables
Share-based payment expense 36 21 3,660 3,472
Provision against inventory held for sale 3 (2,627) 34
Loss on disposal of drilling stock 3 245 -
Operating cash flows before movements in working 88,086 78,749
capital
Decrease in inventories 4,460 49
Increase in trade and other receivables (36,601) (1,290)
Increase in trade and other payables 4,436 11,919
Cash generated from operations 60,381 89,427
Reconciliation of property, plant and equipment additions to cash flows
from purchase of property, plant and equipment:
2025 2024
$’000 $’000
Associated cash flows
Additions to property, plant and equipment (see note 10) 39,153 20,102
Movement in working capital (5,946) 7,083
Non-cash movements
Foreign exchange differences 107 (7)
Purchase of property, plant and equipment 33,314 27,178
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 2025, gross
capital commitments in relation to the Shaikan Field were estimated to be
$13.3 million (2024: $9.2 million). Of this amount, $7.0 million (2024:
nil) relates to a single contractual agreement.
21. Share-based payments
2025 2024
$’000 $’000
Total share options charge 3,660 3,472
The total share options charge of $3.7 million (2024: $3.5 million) is
comprised of $3.5 million (2024: $3.2 million) related to the LTIP plan
and $0.2 million (2024: $0.3 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% 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.
2025 2024
Number of Number of
share options share options
’000 ’000
Outstanding at 1 January 8,918 8,004
Granted during the year 3,206 3,590
Exercised during the year (1,845) (516)
Forfeited during the year (399) (288)
Expired during the year (529) (1,872)
Outstanding at 31 December 9,351 8,918
Exercisable at 31 December - -
The weighted average share price at the date of exercise for share options
exercised during the year was £2.16 (2024: £1.48).
The inputs into the calculation of fair values of the share options
granted during the year are as follows:
2025 2024
Weighted average share price £1.57 £1.11
Weighted average exercise price Nil Nil
Expected volatility 51.9% 56.1%
Expected life 3 years 3 years
Risk-free rate 4.0% 4.3%
Expected dividend yield (on the basis dividends Nil Nil
equivalents received)
The options outstanding at 31 December 2025 had a weighted average
remaining contractual life of two years (2024: two years).
The aggregate of the estimated fair value of options granted in 2025 is
$6.2 million (2024 $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).
2025 2024
Number of Number of
share options share options
’000 ’000
Outstanding at 1 January 216 216
Exercised during the year (136) -
Granted during the year 146 -
Outstanding at 31 December 226 216
Exercisable at 31 December - -
The options outstanding at 31 December 2025 had a weighted average
remaining contractual life of two years (2024: one year).
The aggregate of the estimated fair value of options granted in 2025 is
$0.3 million (2024: no options granted).
22. Dividends
During 2025, a total of $50 million dividends (23.040 US cents per Common
Share) were declared and paid to shareholders. In 2024, a total of $35
million dividends were declared and paid (16.048 US cents per Common
Share).
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
2025 were as follows:
D Thomas – Non-Executive Chair
M Daryabegui – Non-Executive Senior Independent Director
C Krajicek – Non-Executive Director
W Mwaura – Non-Executive Director
J Balkany – Non-Executive Director
J Harris – Chief Executive Officer and Executive Director
G Papineau-Legris – Chief Financial Officer and Executive Director
J Hulme – Chief Operating Officer
C Kinahan – Chief Human Resources 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.
2025 2024
$’000 $’000
Short-term employee benefits 6,166 7,196
Share-based payment - options 2,436 1,493
8,602 8,689
Further information about the remuneration of individual Directors is
provided in the Directors’ Emoluments section of the Remuneration
Committee report.
24. Contingent Liabilities
During 2025 and up to the date of this report, the Group continued
negotiations with the MNR around a number of historical outstanding
Shaikan commercial, financial and accounting matters. The focus of the
negotiations includes the settlement of the Group's historical oil sales
receivable balance for the outstanding October 2022 to March 2023
invoices, along with other KRG-related assets and liabilities (including
the sale of test production oil mentioned below), as well as the agreement
of a formal amendment to the PSC to reflect current invoicing terms,
outstanding since 2017.
The Group has a contingent liability of $27.3 million (31 December 2024:
$27.3 million) in relation to the proceeds from the sale of test
production oil prior to the approval of the Shaikan Field Development Plan
(“FDP”) in June 2013. If a cash outflow to the MNR were required in the
future, this would result in a corresponding increase to the unrecovered
cost pool as the test production revenue is recorded as a reduction of the
cost pool by $34 million gross to the Contractor ($27.3 million net to
GKP) in the Group’s cost recovery submissions to the MNR, and consequently
a potential increase in future cost oil revenue (see note 2).
The above negotiations may lead to a revision to the unrecovered cost pool
impacting future revenues, the settlement of previously unrecognised
assets and liabilities, netting of existing receivable and payable
balances, or may require material adjustments to currently recorded
balances. Due to the uncertain and range of potential financial outcomes
that cannot presently be reliably estimated, no provision for such asset
or liability has been recognised within the financial statements.
25. Subsequent Events
On 18 February 2026 the Company announced the commencement of trading on
the Euronext Growth Oslo. The new listing is in addition to the existing
listing on the Main Market of the London Stock Exchange. A total of
538,087 new common shares were issued as a retail offer in conjunction
with the Oslo listing.
On 28 February 2026, the Shaikan Field was shut-in as a safety precaution
following the strikes by the US and Israel on Iran and the subsequent
retaliatory strikes in the Middle East, including in the Kurdistan.
Production remains shut-in at the date of this report and the Company is
taking all reasonable steps to maintain security and safeguarding the
value of the asset during this time. The Company is monitoring for an
opportunity to safely and quickly restart production with an improvement
in the security environment.
An interim dividend of $12.5 million was declared in March 2026.
══════════════════════════════════════════════════════════════════════════
Dissemination of a Regulatory Announcement, transmitted by 37 EQS Group.
The issuer is solely responsible for the content of this announcement.
View original content: 38 EQS News
══════════════════════════════════════════════════════════════════════════
ISIN: BMG4209G2077
Category Code: MSCL
TIDM: GKP
LEI Code: 213800QTAQOSSTNTPO15
Sequence No.: 421484
EQS News ID: 2294040
End of Announcement EQS News Service
══════════════════════════════════════════════════════════════════════════
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