DJ 2025 Full Year Results Announcement
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 USD50 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
USD12.5 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 USD193.1 million (2024 revenue: USD151.2
million), reflecting the production increase and average realised price of USD33.9/bbl (2024: USD26.8/bbl)
- Average realised price of USD50.5/bbl for 2025 exports sales, a significant improvement on the price achieved
from 2025 local sales of USD27.6/bbl and representing a USD13.4/bbl discount to Dated Brent
- Cash receipts for 2025 exports sales equated to USD30/bbl as per the interim exports agreements
-- Adjusted EBITDA up 46% to USD111.4 million in 2025 (2024: USD76.1 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 USD4.3/bbl relative to prior year (2024: USD4.4/bbl), with 18% reduction in other G
&A expenses to USD9.3 million (2024: USD11.4 million)
-- Net capital expenditure of USD38.8 million (2024: USD18.3 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 USD29.1 million (2024: USD65.4 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 USD30/bbl
- The amounts receivable at the year-end related to the timing difference of exports sales have since been
collected as expected in 2026
-- USD50 million returned to shareholders in 2025 through semi-annual dividend payments in April and September
-- 2025 year-end cash balance of USD78.2 million (31 December 2024: USD102.3 million) and no debt
- Cash balance as at 18 March 2026 of USD89.1 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 USD40-USD50 million, USD55-USD60 million and less than USD10 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 USD12.5
million, equivalent to USD0.0575 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:
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.
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March 19, 2026 03:01 ET (07:01 GMT)
DJ 2025 Full Year Results Announcement -2-
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 aclark@gulfkeystone.com
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton
GKP@fticonsulting.com
Nick Hennis
or visit: 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: 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 USD50 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 USD12.5 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 USD50 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
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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 USD16/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 USD16/bbl equated to USD30/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
Year Local sales Year
Export sales
ended 1 January to ended
27 September to 31
December
31 December 26 September 31 December
2025
2025 2025 2024
Gross average production(1) bopd 41,560 43,434 40,891 40,689
Dated Brent(2) USD/bbl 69.1 63.9 71.0 80.8
Realised price(1)(3) USD/bbl 33.9 50.5 27.6 26.8
Discount to Dated Brent USD/bbl 35.2 13.4 43.4 53.9
Revenue (invoiced for the period)(1) USDm 193.1 79.2 113.9 151.2
(4)
Revenue (IFRS)(5) USDm 164.8 50.9 113.9 151.2
Operating costs USDm 52.6 14.0 38.6 52.4
Gross operating costs per barrel(1) USD/bbl 4.3 4.2 4.4 4.4
Other general and administrative USDm 9.3 2.0 7.3 11.4
expenses
Share option expense USDm 7.0 1.0 6.0 4.4
Adjusted EBITDA(1)(6) USDm 111.4 56.8 54.6 76.1
Profit/(loss) after tax USDm 15.1 24.0 (8.9) 7.2
Basic earnings/(loss) per share cents 7.0 11.1 (4.1) 3.3
Revenue receipts(1) USDm 122.4 14.1 108.3 144.1
Net capital expenditure(1)(7) USDm 38.8 14.6 24.2 18.3
Free cash flow(1) USDm 29.1 (8.3) 37.4 65.4
Shareholder distributions(8) USDm 50 0 50 45
Cash and cash equivalents USDm 78.2 78.2 87.2 102.3
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March 19, 2026 03:01 ET (07:01 GMT)
DJ 2025 Full Year Results Announcement -4-
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 USD30/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 USD5.4 million non-cash charge associated with the capitalisation of drilling
inventory previously classified as held for sale. 8. 2025: USD50 million of dividends; 2024: USD35 million of dividends and USD10 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 USD50 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 USD111.4 million in 2025 (2024: USD76.1 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 USD193.1 million (2024: USD151.2 million), reflecting the 2% improvement in annual production and an average realised price of USD33.9/bbl (2024: USD26.8/ bbl). Revenue on an IFRS basis was USD164.8 million (2024: USD151.2 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 USD50.5/bbl and therefore represented a significant improvement on the price achieved from local sales of USD27.6/bbl in January to September 2025 and USD26.8/bbl in 2024. The average discount to Dated Brent of USD13.4/bbl arising from 2025 export sales is encouraging and represents a sizeable reduction compared to the average discount to Dated Brent of USD27.2/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 USD4.3/bbl (2024: USD4.4/ bbl) and USD52.6 million (2024: USD52.4 million) respectively. Other G&A expenses reduced 18% to USD9.3 million in 2025 (2024: USD11.4 million), primarily reflecting the absence of one-off retention awards in 2024.
Share option expense was USD7.0 million in 2025 (2024: USD4.4 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 USD30/bbl as per the interim exports agreements), were USD122.4 million. Revenue receipts were 15% lower relative to the prior year (2024: USD144.1 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 USD32.0 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 USD32.8 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 USD38.8 million (2024: USD18.3 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 USD5.4 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 USD33.4 million was in line with annual guidance.
Free cash flow generation in 2025 was USD29.1 million (2024: USD65.4 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 USD50 million (2024: USD35 million of dividends and USD10 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 USD4.0 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 USD78.2 million as at 31 December 2025 (31 December 2024: USD102.3 million) with no outstanding debt. The cash balance as at 18 March 2026 was USD89.1 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
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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 USD152.7 million of unrecovered cost oil for the Shaikan Contractor (USD122.2 million net to GKP) in the Cost Pool. The R-factor, calculated as cumulative Contractor revenue receipts of USD2,582 million divided by cumulative Contractor costs of USD2,079 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 USD28.3 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 USD122.8 million net to GKP (comprising USD92.1 million cost oil and USD30.7 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 USD184.6 million as at 31 December 2025 (comprising USD141.8 million cost oil and USD42.8 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 USD40-USD50 million, net operating costs of USD55-USD60 million and other G&A expenses below USD10 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 USD12.5 million, equivalent to USD0.0575 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 (USD million)(1) 65.8 65.5 Gross operating costs per barrel (USD 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
USD million USD 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 intangibles 2.0 3.0
Decrease in expected credit loss provision on trade receivables (7.6) (8.2)
Adjusted EBITDA (including IFRS revenue) 83.1 76.1
Effective recovery of past receivables 28.3 -
Adjusted EBITDA (including non-IFRS revenue invoiced for the year) 111.4 76.1
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
USD million USD 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
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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
USD million USD million
Net capital expenditure (see note 10 to the consolidated financial statements) 38.8 18.3
As detailed in note 10 to the financial statements, the net capital expenditure in the period ended 31 December 2025, includes USD5.4 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 USD33.4 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
USD million USD 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
USD'000 USD'000
Non-IFRS measure
Revenue invoiced for the year 2 193,093 151,208
Effective recovery of past receivables 2 (28,280) -
Revenue 164,813 151,208
IFRS consolidated income statement
Revenue 2 164,813 151,208
Cost of sales 3 (141,089) (138,866)
Decrease of expected credit loss provision on trade receivables 13 7,558 8,191
Gross profit 31,282 20,533
Other general and administrative expenses 4 (9,313) (11,412)
Share option related expenses 5 (6,959) (4,419)
Profit from operations 15,010 4,702
Finance income 7 2,740 4,116
Finance costs 7 (1,976) (1,676)
Foreign exchange (loss)/gain (1,108) 724
Profit before tax 14,666 7,866
Tax credit/(charge) 8 468 (708)
Profit after tax 15,134 7,158
Earnings per share (cents)
Basic 9 6.97 3.26
Diluted 9 6.68 3.13
Consolidated statement of comprehensive income
For the year ended 31 December 2025
2025 2024
USD'000 USD'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
USD'000 USD'000
Non-current assets
Trade receivables 13 84,007 138,175
Intangible assets 260 1,255
Property, plant and equipment 10 349,404 388,450
Deferred tax asset 16 1,365 825
435,036 528,705
Current assets
Inventories 12 7,774 9,852
Trade and other receivables 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 14 (128,314) (117,277)
Deferred income - (716)
(128,314) (117,993)
Non-current liabilities
Trade and other payables 14 (928) (1,112)
Decommissioning provision 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
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For the year ended 31 December 2025
Attributable to equity holders of the Company
Share Total
Share Exchange translation Accumulated
reserve losses
premium equity
capital
Notes USD'000 USD'000 USD'000 USD'000 USD'000
Balance at 1 January 2024 222,443 503,312 (3,766) (174,752) 547,237
Profit after tax for the year - - - 7,158 7,158
Exchange difference on translation of - - (517) - (517)
foreign operations
Total comprehensive income for the year - - (517) 7,158 6,641
Dividends paid 22 - (34,933) - - (34,933)
Employee share schemes 21 - - - 3,472 3,472
Share issues 18 255 - - (255) -
Repurchase of ordinary shares 18 (5,693) (4,394) - - (10,087)
Balance at 31 December 2024 217,005 463,985 (4,283) (164,377) 512,330
Profit after tax for the year - - - 15,134 15,134
Exchange difference on translation of - - 1,781 - 1,781
foreign operations
Total comprehensive income for the year - - 1,781 15,134 16,915
Dividends paid 22 - (49,846) - - (49,846)
Employee share schemes 21 - - - 3,660 3,660
Reissue of repurchased shares 18 - - - (3,702) (3,702)
Own shares repurchased and held in 18 - - - (330) (330)
Employee Benefit Trust
Balance at 31 December 2025 217,005 414,139 (2,502) (149,615) 479,027
Consolidated cash flow statement
For the year ended 31 December 2025
2025 2024
Notes
USD'000 USD'000
Operating activities
Cash generated from operations 19 60,381 89,427
Interest received 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 payments (4,032) -
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 cash on hand 78,233 102,346
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 instruments; Contracts Referencing
IFRS 7 Nature-dependent Electricity
Annual Improvements to IFRS 1: Hedge accounting by a first-time adopter; IFRS 7: Gain or loss on derecognition; IFRS
IFRS Accounting Standards 7: Disclosure of deferred difference between fair value and transaction price; IFRS 7:
- Volume 11 Introduction 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
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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 USD89.1 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
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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 ?nancial 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.
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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 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 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 USD28.3m 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
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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 USD308.6 million (2024: USD348.9 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 (USD/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
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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
USD'000 USD'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 sales (see note 13) in accordance (3,556) -
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 USD193.1 million (2024: USD151.2 million) with USD64.8 million remaining outstanding as at 31 December 2025 as disclosed in note 13 (prior to ECL). The effective rebilling of past due receivables totalled USD28.3 million (2024: not applicable), therefore revenue, in accordance with IFRS 15, was capped at USD164.8 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 USD27.6/bbl (2024: USD26.8/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 USD50.5/bbl (2024: not applicable) with approximately USD30/bbl achieved to date and settled within approximately two months of production in line with export contracts. The remaining balance outstanding of approximately USD32.8 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
USD'000 USD'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 (see note 10) 77,308 75,781
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 USD2.6m 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
2024
2025
USD'000
USD'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
USD'000 USD'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
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588 562 Other assurance services (including a half year review) 116 117 Total fees 704 679
5. Share option related expense
2025 2024
USD'000 USD'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 employees Average number of full-time 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
USD'000 USD'000
Wages and salaries 39,315 37,833
Social security costs 2,446 2,723
Pension costs 456 472
Share-based payment (see note 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
USD'000 USD'000
Lease interest (161) (48)
Unwinding of discount on provisions (see note 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
USD'000 USD'000
Deferred UK corporation tax credit/(charge) (see note 16) 468 (708)
Tax credit/(charge) attributable to the Company and its subsidiaries 468 (708)
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 GBP50k tapered to 25% on profits above GBP250k.
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 calculations (USD'000) 15,134 7,158
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 outstanding 217,005 219,562
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
USD'000
USD'000 USD'000
USD'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 decommissioning asset (693) - - (693)
Depreciation charge (75,781) (576) (394) (76,751)
Disposals' depreciation - - 2,004 2,004
Foreign currency translation differences - (1) (6) (7)
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)
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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 decommissioning asset (198) - - (198) Depreciation charge (77,308) (475) (325) (78,108) Disposals' depreciation - 2,021 - 2,021 Foreign currency translation differences - 5 102 107 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 USD346.5 million (2024: USD385.2 million).
The additions to the Shaikan asset amounting to USD38.8 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 USD5.4 million (2024: not applicable).
The USD0.2 million decrease (2024: USD0.7 million decrease) in decommissioning asset value comprises a USD1.9 million decrease relating to changes of inflation and discount rates (2024: USD1.1 million), partially offset by an increase of USD1.7 million relating to increases in well estimates and additional facilities works (2024: USD0.4 million).
The DD&A charge of USD77.3 million (2024: USD75.8 million) on oil and gas assets has been included within cost of sales (see note 3). The depreciation charge of USD0.5 million (2024: USD0.6 million) on fixtures and equipment and USD0.3 million (2024: USD0.4 million) on right of use assets has been included in general and administrative expenses (see note 4).
Right of use assets at 31 December 2025 of USD1.3 million (2024: USD1.5 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:
Principal
Place of
Name of subsidiary incorporation
Proportion of
ownership interest activity
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%
5th Floor Exploration, evaluation, development and
production activities in Kurdistan
Rosebank Centre
11 Bermudiana Road
Pembroke, HM08 Bermuda
Principal
Name of joint operation Location
Proportion of ownership interest activity
Shaikan Kurdistan 80%
Production and development activities
12. Inventories
2025 2024
USD'000 USD'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
USD'000 USD'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
USD'000 USD'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 non-current 209,072 164,954
Reconciliation of trade receivables
2025 2024
USD'000 USD'000
Amounts related to past due trade receivables
Gross past due trade receivables before impairment allowance 142,745 171,026
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 impairment allowance 64,805 -
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 USD142.7 million (2024: USD171.0 million) are comprised of invoiced amounts due from the KRG, based upon KBT pricing, for crude oil export sales totalling USD130.5 million (2024: USD158.8 million) related to October 2022 - March 2023 and a share of Shaikan amounts due from the KRG that GKP purchased from MOL amounting to USD12.2 million (2024: USD12.2 million). Although no legal right of offset exists, the net balance past due from the KRG comprises USD130.5 million (2024: USD158.8 million) included in trade receivables and USD7.7 million (2024: USD7.7 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 USD122.8 million (2024: USD151.1 million).
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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 USD122.8 million above (2024: USD151.1 million), comprises USD92.1 million (2024: USD120.4 million) cost oil and USD30.7 million profit oil (net of Capacity Building Payment). Although no legal right of offset exists, it is expected that USD29.6 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 USD8.7 million (2024: USD16.3 million) was provided against the trade receivables balance in accordance with IFRS 9 'Financial Instruments'. During the year, a USD7.6 million credit to the income statement was recognised due to the decrease in the ECL provision (2024: credit of USD8.2 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 USD64.8 million (2024: nil) are amounts due under contracts signed with the KRG and the Federal Government of Iraq ("FGI"). Outstanding amounts comprise two components:
-- USD32.0 million equivalent to approximately USD30/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 -- USD32.8 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, USD3.0 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 USD61.8 million (2024: nil). This 2025 export sales trade receivable balance of USD61.8 million above, comprises USD49.7 million cost oil and USD12.1 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 USD4.4 million, conversely a decrease of the CDS of 2% would decrease the ECL provision by USD4.7 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 USD0.1 million (2024: USD0.5 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
USD'000 USD'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 receivables 7,687 7,687
Capacity building payment due to KRG on 2025 export sales trade receivables 3,014 -
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 USD87.2 million (2024: USD80.9 million) include:
-- USD41.9 million (2024: USD40.1 million) expected to be offset against amounts due from the KRG:
- USD12.3 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;
- USD29.6 million relating to a partial offset of past due trade receivables (see note 13). -- USD45.3 million (2024: USD40.8 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 USD45.3 million.
Non-current liabilities
2025 2024
USD'000 USD'000
Non-current lease liability 928 1,112
15. Decommissioning provision
2025 2024
USD'000 USD'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 USD0.2 million decrease in new provisions and changes in estimates (2024: USD0.7 million decrease) comprises USD1.9 million decrease relating to changes of inflation and discount rates (2024: USD1.1 million decrease), partially offset by an increase of USD1.7 million relating to increases in well estimates and additional facilities works (2024: USD0.4 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
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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.
Total
Share-based payments
Accelerated tax Tax losses carried
depreciation forward
USD'000 USD'000
USD'000
USD'000
At 1 January 2024 293 482 770 1,545
Tax (charge)/credit to income (271) 238 (675) (708)
statement
Exchange differences - (11) (1) (12)
At 31 December 2024 22 709 94 825
Tax credit/(charge) to income 176 323 (31) 468
statement
Exchange differences 6 60 6 72
At 31 December 2025 204 1,092 69 1,365
17. Financial instruments
2025 2024
USD'000 USD'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 USD8.7 million provision against trade receivables (2024: USD16.3 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 USD207.6 million (2024: USD171.0 million). Although the Group expects to recover the full trade receivables balance, a provision of USD8.7 million (2024: USD16.3 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
USD'000 USD'000
Authorised:
Common shares of USD1 each 292,105 292,105
Common shares
No. of shares Share capital Share premium Total amount
'000 USD'000 USD'000 USD'000
Balance 1 January 2024 222,443 222,443 503,312 725,755
Dividends paid - - (34,933) (34,933)
Shares issued 255 255 - 255
Repurchase of ordinary shares (5,693) (5,693) (4,394) (10,087)
Balance 31 December 2024 217,005 217,005 463,985 680,990
Dividends paid - - (49,846) (49,846)
Balance 31 December 2025 217,005 217,005 414,139 631,144
At 31 December 2025, a total of 0.1 million common shares at USD1 each were held by the EBT (2024: 0.2 million at USD1 each). These common shares were included within reserves.
Rights attached to share capital
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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 the surplus assets of the Company only after
(iv) 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
USD'000 USD'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 78,108 76,752
the right of use assets)
Amortisation of intangible assets 1,248 1,980
Decrease of expected credit loss provision on trade receivables 13 (7,558) (8,191)
Share-based payment expense 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 capital 88,086 78,749
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
USD'000 USD'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 USD13.3 million (2024: USD9.2 million). Of this amount, USD7.0 million (2024: nil) relates to a single contractual agreement.
21. Share-based payments
2025 2024
USD'000 USD'000
Total share options charge 3,660 3,472
The total share options charge of USD3.7 million (2024: USD3.5 million) is comprised of USD3.5 million (2024: USD3.2 million) related to the LTIP plan and USD0.2 million (2024: USD0.3 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 GBP2.16 (2024: GBP1.48).
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 GBP1.57 GBP1.11 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 equivalents received) Nil Nil
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 USD6.2 million (2024 USD4.6 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).
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