DJ 2025 Half Year Results Announcement
Gulf Keystone Petroleum Ltd (GKP)
2025 Half Year Results Announcement
28-Aug-2025 / 07:00 GMT/BST
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28 August 2025
Gulf Keystone Petroleum Ltd. (LSE: GKP)
("Gulf Keystone", "GKP", "the Group" or "the Company")
2025 Half Year Results Announcement
Gulf Keystone, a leading independent operator and producer in the Kurdistan Region of Iraq, today announces its results
for the half year ended 30 June 2025.
Jon Harris, Gulf Keystone's Chief Executive Officer, said:
"We delivered strong operational and financial performance in the first half of 2025, with material free cash flow
generated from increased production and realised prices, capital discipline and cost control. Following the temporary
shut-in of the Shaikan Field in July related to security concerns, production restarted earlier this month after
consultation with the Kurdistan Regional Government and has gradually ramped back up towards full well capacity. Given
the return to stable sales and our robust cash balance, we are pleased to announce today the declaration of a USD25
million interim dividend, increasing total dividends declared in 2025 to USD50 million.
Looking ahead, we have tightened 2025 gross average production guidance to 40,000 - 42,000 bopd primarily reflecting
the production losses from recent temporary disruptions. We are excited to have sanctioned the installation of water
handling facilities at PF-2 which we expect, once operational, to unlock incremental production above the anticipated
field baseline and reduce downside risk to reservoir recovery. We continue to engage with government stakeholders
regarding the restart of Kurdistan crude exports, with increasing momentum towards a solution in recent weeks."
Highlights to 30 June 2025 and post reporting period
Operational
-- Zero Lost Time Incidents for over 950 days with rigorous focus on safety maintained
-- Gross average production increased 12% to 44,100 bopd in H1 2025 (H1 2024: 39,252 bopd), reflecting consistently
robust local market demand and good reservoir performance
-- Gross average production of c.40,600 bopd in 2025 year to date (as at 26 August 2025):
- Primarily reflects precautionary field shut-in in July following drone attacks on certain other oil fields in
Kurdistan
- Production has gradually returned towards full well capacity after operations were restarted in August
following a security assessment and consultation with the Kurdistan Regional Government ("KRG")
- Realised prices have averaged around USD27-USD28/bbl in the post reporting period
-- Continued execution of disciplined work programme focused on safely maintaining existing production capacity and
reliability
-- Investment decision taken on installation of water handling facilities at PF-2:
- Commissioning expected at the beginning of 2027
- Once operational, the facilities are expected to unlock an estimated 4,000 - 8,000 bopd of incremental gross
production above the anticipated field baseline while reducing reservoir risk
- To minimise upfront capital expenditure and provide flexibility, the facilities will be leased over multiple
years following commissioning, with limited incremental net capex expected in 2025
Financial
-- Free cash flow generation of USD24.6 million in H1 2025 (H1 2024: USD26.6 million), enabled by increased production and
realised prices, capital discipline and cost control
-- Adjusted EBITDA increased 13% to USD41.1 million (H1 2024: USD36.4 million) as higher production, stronger prices and
lower other G&A expenses offset the increase in operating costs and share option expense:
- Revenue increased 17% to USD83.1 million (H1 2024: USD71.2m) as strong production was bolstered by a 6% increase in
the average realised price during the period to USD27.8/bbl (H1 2024: USD26.3/bbl)
- Gross operating costs per barrel of USD4.2/bbl were flat (H1 2024: USD4.2/bbl), with the decrease from the 2024
average of USD4.4/bbl primarily reflecting higher production
-- Net capital expenditure of USD18.1 million (H1 2024: USD7.8 million) reflecting the Company's focused work programme of
safety critical upgrades at PF-2 and production optimisation expenditures:
- Includes a non-cash charge of USD5.4 million associated with the capitalisation of drilling inventory previously
classified as held for sale
-- Interim dividend of USD25 million paid in H1 2025 (H1 2024 shareholder distributions: USD21 million)
-- Cash balance of USD99.0 million as at 30 June 2025 (31 December 2024: USD102.3 million), with no outstanding debt;
latest balance as at 27 August 2025 of USD105.7 million
Outlook
-- 2025 gross average production expected to be between 40,000 - 42,000 bopd (previous guidance: 40,000 - 45,000
bopd), reflecting production losses from the recent temporary disruptions:
- Guidance remains subject to local sales demand and a stable security environment
-- 2025 net capital expenditure expected to be USD30-USD35 million (previous guidance: USD25-USD30 million):
- Unchanged expectation of c.USD20 million net capex on PF-2 safety upgrades and maintenance and USD5-USD10 million on
production optimisation initiatives
- Increase in guidance primarily reflects the incremental net capex associated with the water handling project
-- Unchanged guidance for operating costs of USD50-USD55 million and other G&A expenses below USD10 million
-- The Company is pleased to declare a USD25 million interim dividend, equivalent to 11.52 US cents per Common Share
based on the Company's total issued share capital as at 27 August 2025:
- The dividend will be paid on 30 September 2025, based on a record date of 12 September 2025 and ex-dividend
date of 11 September 2025
- Shareholders will have the option of being paid the dividend in either GBP or USD, with the default currency
GBP
-- The Company continues to engage with government stakeholders regarding a solution to enable the restart of
Kurdistan crude exports through the Iraq-Türkiye Pipeline:
- The Company remains ready to resume oil exports provided satisfactory agreements are reached on payment surety
for future oil exports, repayment of outstanding receivables and preservation of current contract economics
Investor & analyst presentation
GKP's management team will be hosting a presentation for investors and analysts at 10:00am (BST) today via live audio
webcast:
https://brrmedia.news/GKP_GY_25
Sell-side analysts are requested to join the meeting via the dial-in details provided to them separately and ask
questions verbally. Investors are encouraged to pre-submit written questions via the webcast registration page, with
the opportunity to submit questions live during the presentation.
A recording of the presentation will be made available on GKP's website.
This announcement contains inside information for the purposes of the UK Market Abuse Regime.
Enquiries:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations
& Corporate Communications 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: 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.
CEO review
The Company performed well in the first half of 2025, with consistently robust local market demand and good reservoir performance enabling increased production relative to the prior year period. Capital and cost discipline continued to underpin free cash flow generation and shareholder distributions. While temporary market disruption and security concerns impacted sales in June and July respectively, production has gradually returned towards full well capacity in August. We have also seen increased momentum towards an exports restart solution in our engagement with government stakeholders in recent weeks.
We have maintained a rigorous focus on safety in 2025 year to date, extending our track record of days without a Lost Time Incident to over 950.
Gross average production in the first half of 2025 was 44,100 bopd, a 12% increase relative to H1 2024. Local market demand for Shaikan Field crude was consistently strong between January to May 2025, enabling monthly gross average production above 45,000 bopd. Sales reduced in June because of trucking shortages around the Eid Al-Adha holiday and some disruptions during the conflict between Israel and Iran. Average realised prices in H1 2025 were relatively healthy at USD27.8/bbl, 6% higher compared to the prior year period. The Company's ability to meet buyer demand was enabled by good reservoir performance, with successful production optimisation initiatives offsetting natural field declines and well maintenance.
Gross production has averaged c.40,600 bopd in the year to date as at 26 August 2025, with the reduction relative to the first half average primarily reflecting the temporary shut-in of the Shaikan Field on 15 July 2025 following drone attacks on a number of oil fields close to our operations and elsewhere in Kurdistan. The safety of Gulf Keystone's staff is always our top priority and we acted quickly to move employees and contractors to safe locations. Earlier this month, the Company restarted production operations following a security assessment and consultation with the KRG. Following a gradual ramp up, production levels have returned towards full well capacity.
The Company has continued to execute its disciplined work programme, progressing safety upgrades at PF-2 and executing production optimisation initiatives. As previously announced, the planned shut-in of PF-2 that had been scheduled to take place in Q4 2025 to tie-in the safety upgrades was deferred to 2026 to support production and provide greater work programme flexibility.
Increased production, stronger prices and continued capital and cost discipline enabled the Company to generate USD24.6 million of free cash flow in the first half of 2025. In line with our commitment to return excess cash to shareholders, we paid a USD25 million interim dividend in April.
The Company has recently sanctioned the installation of water handling facilities at PF-2. Engineering design work has commenced and commissioning is currently expected at the beginning of 2027.
Once operational, the 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 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 there are no indications of a near term increase in water ingress following an extraordinary track record of dry oil production to date of over 145 MMstb, we have long viewed water handling as a critical component of the Shaikan Field's development and natural life cycle.
To reduce costs, we have sourced second hand facilities and are combining them with an existing oil train at PF-2. To minimise upfront capital expenditure and provide flexibility, the facilities will be leased over multiple years following commissioning. Limited incremental net capital expenditure is expected in 2025, with total costs during the construction phase ahead of commissioning estimated at approximately USD12 million net to GKP. The facilities are expected to generate positive cash flow, even in a local sales environment, with future operating costs associated with the lease and water disposal expected to be more than covered by the anticipated incremental production.
Looking ahead to the remainder of the year, we are expecting 2025 gross average production to be between 40,000 - 42,000 bopd (previous guidance: 40,000 - 45,000 bopd), reflecting the impact of the temporary disruptions experienced from June to August. We continue to progress our production optimisation programme, with additional well workovers planned in the second half of the year, while managing natural field declines and certain wells constrained by water and gas. The guidance remains subject to local sales demand and a stable security environment.
2025 net capital expenditure is expected to be USD30-USD35 million (previous guidance: USD25-USD30 million), primarily reflecting the incremental capex associated with water handling.
The Company, along with other international oil companies ("IOCs") operating in Kurdistan, has been continuing to engage with government stakeholders and other relevant parties regarding the restart of Kurdistan exports. The past few weeks have been characterised by increased levels of activity as we focus on securing written agreements. We are hopeful of reaching a solution soon and remain ready to restart exports quickly.
Jon Harris
Chief Executive Officer
27 August 2025
Financial review
Key financial highlights
Six months Six months
Year ended
ended ended
31 December 2024
30 June 2025 30 June 2024
Gross average production(1) bopd 44,100 39,252 40,689
Dated Brent(2) USD/bbl 71.9 84.1 80.8
Realised price(1) USD/bbl 27.8 26.3 26.8
Discount to Dated Brent USD/bbl 44.1 57.8 53.9
Revenue USDm 83.1 71.2 151.2
Operating costs USDm 26.9 23.9 52.4
Gross operating costs per barrel(1) USD/bbl 4.2 4.2 4.4
Other general and administrative expenses USDm 4.6 5.4 11.4
Share option expense USDm 4.4 2.1 4.4
Adjusted EBITDA(1) USDm 41.1 36.4 76.1
(Loss)/profit after tax USDm (7.2) 0.4 7.2
Basic (loss)/earnings per share cents (3.3) 0.2 3.3
Revenue receipts(1) USDm 78.2 65.5 144.1
Net capital expenditure(1) USDm 18.1 7.8 18.3
Free cash flow(1) USDm 24.6 26.6 65.4
Shareholder distributions(3) USDm 25 21 45
Cash and cash equivalents USDm 99.0 102.3 102.3
1. Represents either a non-financial or non-IFRS measure which are explained in the summary of non-IFRS measures where
applicable. 2. Provided as a comparator for realised price. Realised prices for local sales remain driven by supply and demand
dynamics in the local market, with no direct link to Dated Brent. 3. H1 2025: USD25 million dividend; H1 2024: USD15 million dividend and USD6 million of the Company's USD10 million share
buyback programme launched on 13 May 2024 and completed on 23 July 2024; FY 2024: USD35 million of dividends and USD10
million of completed share buybacks.
Gulf Keystone continued to generate material free cash flow in the first half of 2025, supported by increased production and realised prices, capital discipline and cost control. The strong financial performance funded the payment of a USD25 million interim dividend to shareholders while maintaining the Company's robust, debt-free balance sheet. With production having returned towards full well capacity following the temporary July shut-in and a robust cash balance, the Board has approved the declaration of an additional USD25 million interim dividend. Looking ahead, we remain focused on maintaining capital and cost discipline to drive free cash flow from local sales as we work towards the restart of exports.
Adjusted EBITDA
Adjusted EBITDA increased 13% to USD41.1 million in H1 2025 (H1 2024: USD36.4 million) as higher production, stronger realised prices and lower other G&A expenses more than offset the increase in operating costs and share option expense.
Gross average production increased 12% to 44,100 bopd in H1 2025 (H1 2024: 39,252 bopd) reflecting consistently robust demand from a more established local sales market and good reservoir performance.
H1 2025 revenue increased 17% to USD83.1 million (H1 2024: USD71.2 million) as strong production volumes were complemented by a 6% increase in the average realised price during the period to USD27.8/bbl (H1 2024: USD26.3/bbl). Realised prices have averaged around USD27-USD28/bbl since June.
The Company continued to carefully manage its cost base in the first half of 2025 while safely maintaining the production capacity of the Shaikan Field. Gross operating costs per barrel of USD4.2/bbl were flat relative to the prior period (H1 2024: USD4.2/bbl), with the decrease from the 2024 average of USD4.4/bbl primarily reflecting higher production. Operating costs in the first half of 2025 increased by 13% to USD26.9 million (H1 2024: USD23.9 million), principally reflecting higher production and well service costs to bring two wells back online.
Other G&A expenses decreased 15% to USD4.6 million in H1 2025 (H1 2024: USD5.4 million), primarily reflecting the absence of one-off retention awards accrued for in 2024 and paid in Q1 2025.
Share option expense was USD4.4 million in H1 2025 (H1 2024: USD2.1 million), reflecting the higher vesting in April 2025 of a greater number of awards associated with the 2022 LTIP relative to the vesting of the 2021 LTIP award in 2024.
(Loss)/profit after tax
The Company reported a loss after tax of USD7.2 million in the first half of 2025 (H1 2024 profit after tax: USD0.4 million), principally reflecting an USD8.9 million charge to the expected credit loss ("ECL") provision associated with the outstanding export sales receivables. The non-cash charge reflects a revision of the previously modelled ITP reopening date and updated commercial assumptions (see note 12 to the financial statements for further detail).
Cash flows
Revenue receipts, which reflect cash received in the period for the Company's net entitlement of production sales, were USD78.2 million, 19% higher year-on-year (H1 2024: USD65.5 million) primarily driven by higher production and stronger realised prices.
Net capital expenditure in H1 2025 was USD18.1 million (H1 2024: USD7.8 million), as the Company progressed its disciplined work programme comprised of safety-critical upgrades at PF-2 and production optimisation expenditures. 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 (see note 10 to the financial statements for further detail).
Free cash flow decreased 8% to USD24.6 million in H1 2025 (H1 2024: USD26.6 million), with the increase in production and realised prices offset by higher cash capex and outflows related to working capital and other items.
The Company continued to engage with the KRG regarding outstanding commercial matters including the payment mechanism of the overdue October 2022 to March 2023 invoices. The total owed to GKP amounts to USD151.1 million (comprising of USD120.4 million cost oil and USD30.7 million profit oil net to GKP after capacity building payment ("CBP") deduction). The combined total owed to GKP and Kalegran B.V. (a subsidiary of MOL Group, "MOL") (who form together the "Shaikan Contractor" or the "Contractor") amounts to USD192.8 million (comprising USD150.5 million cost oil and USD42.3 million profit oil). The Company continues to expect to recover the invoices in full.
Gulf Keystone was pleased to pay an interim dividend of USD25 million in H1 2025 (H1 2024 shareholder distributions: USD21 million), according to the Company's announced approach of semi-annual dividend reviews.
To satisfy the vesting of the 2022 LTIP award, purchases of the Company's shares were made by the Employee Benefit Trust ("EBT") in the period, amounting to USD4.0 million. The vesting of LTIP awards in previous years has been satisfied by the issuance of shares.
GKP's cash balance was USD99.0 million as at 30 June 2025 (31 December 2024: USD102.3 million) with no outstanding debt. The cash balance as at 27 August 2025 was USD105.7 million.
The Group performed a cash flow and liquidity analysis, including consideration of the current uncertainty over the timing of the pipeline reopening and settlement of outstanding amounts due from the KRG, and the fact that the outlook for local sales volumes and prices have fluctuated in the past and may be difficult to predict. Based on this analysis, the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for twelve months. Therefore, the going concern basis of accounting is used to prepare the financial statements.
Net entitlement
The Company shares Shaikan Field revenues with its partner, MOL, and the KRG, based on the terms of the Shaikan Production Sharing Contract ("Shaikan PSC"). GKP and MOL's revenue entitlement is described as "Contractor entitlement" and GKP's entitlement alone is described as "net". GKP's net entitlement includes its share of the recovery of the Company's investment in the Shaikan Field, comprising capital expenditure and operating costs, through cost oil and a share of the profits through profit oil, less a CBP owed to the KRG.
The unrecovered cost oil balance (or "Cost Pool") and R-factor are used to calculate monthly cost oil and profit oil entitlements, respectively, owed to the Shaikan Contractor from crude oil sales. Unrecovered cost oil owed to the Shaikan Contractor increases with the addition of incurred expenditures deemed recoverable under the Shaikan PSC and is depleted on a cash basis as crude sales are paid.
As at 30 June 2025, there was USD140.0 million of unrecovered cost oil for the Shaikan Contractor (USD116.4 million net to GKP, including certain expenditures funded 100% by the Company), subject to a potential cost audit by the MNR. The R-factor, calculated as cumulative Contractor revenue receipts of USD2,523 million divided by cumulative Contractor costs of USD2,021 million, was 1.25, resulting in a share in the profit oil for the Contractor of 26.3%.
GKP's net entitlement of total Shaikan Field sales was 36% in the first half of 2025. Looking ahead, the Company expects its net entitlement to remain at this level in the second half of 2025. Should exports restart, increases in realised price, cash receipt of payments for international sales and the potential implementation by the KRG of a repayment mechanism for past overdue invoices would accelerate the depletion of the Cost Pool upon receipt of payment. This would shorten the period that the Company's net entitlement is expected to remain around 36% provided that investment in the Shaikan Field does not increase.
The outlook for the Company's net entitlement assumes effective receipt of the cost oil portion of the outstanding October 2022 to March 2023 receivable balance due from the KRG to the Shaikan Contractor, which totalled USD150.5 million as at 30 June 2025 (or on a net basis to GKP USD120.4 million). Effective recovery of the receivable cost oil is expected to occur with regular payment from either local or export sales. Recovery is expected to effectively lead to a corresponding reduction in the net receivable balance due from the KRG. USD30.7 million of profit oil (net to GKP after CBP deduction) is also expected to be fully repaid by the KRG as part of a repayment mechanism.
The Company now expects the receivable cost oil to begin to be effectively recovered through regular crude sales in the second half of 2025. This reflects the differing accounting recognition criteria of the Cost Pool and receivable balance, which under IFRS recognises revenue on an accrual basis in contrast to the reporting of the PSC which is prepared on a cash basis. It also reflects the Company's ongoing negotiations with the MNR on outstanding commercial matters, which include the timing and mechanism for settling the outstanding receivables. See Note 12 to the financial statements for further detail.
Outlook
2025 net capital expenditure is expected to be USD30-USD35 million (previous guidance: USD25-USD30 million), primarily reflecting the incremental investment associated with water handling. We continue to expect c.USD20 million of net capital expenditure on the PF-2 safety upgrades and USD5-USD10 million related to the production optimisation programme. Guidance excludes the H1 2025 non-cash charge of USD5.4 million associated with the reclassification of drilling inventory, as described above.
The Company continues to expect operating costs of USD50-USD55 million and other G&A expenses below USD10 million in 2025 as per previously communicated guidance.
The Company is pleased to declare, alongside the 2025 half year results, a USD25 million interim dividend, increasing total dividends declared in 2025 to USD50 million. The dividend is equivalent to 11.52 US cents per Common Share based on the Company's total issued share capital as at 27 August 2025 and will be paid on 30 September 2025, based on a record date of 12 September 2025 and ex-dividend date of 11 September 2025. Shareholders will have the option of being paid the dividend in either GBP or USD, with the default currency GBP.
Gabriel Papineau-Legris
Chief Financial Officer
27 August 2025
Non-IFRS measures
The Group uses certain measures to assess the financial performance of its business. Some of these measures are termed "non-IFRS measures" because they exclude amounts that are included in, or include amounts that are excluded from, the most directly comparable measure calculated and presented in accordance with International Financial Reporting Standards ("IFRS"), or are calculated using financial measures that are not calculated in accordance with IFRS. These non-IFRS measures include financial measures such as operating costs and non-financial measures such as gross average production.
The Group uses such measures to measure and monitor operating performance and liquidity, 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. 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 also set out below, where applicable. The Group does not regard these non-IFRS measures as a substitute for, or superior to, the equivalent measures calculated and presented in accordance with IFRS or those calculated using financial measures that are calculated in accordance with IFRS.
Gross operating costs per barrel
Gross operating costs are divided by gross production to arrive at operating costs per barrel.
Six months ended Six months ended
Year ended 31 December 2024
30 June 2025 30 June 2024
Gross production (MMstb) 8.0 7.2 14.9
Gross operating costs (USD million)(1) 33.6 29.9 65.5
Gross operating costs per barrel (USD per bbl) 4.2 4.2 4.4
1. Gross operating costs equate to operating costs (see note 5 to the financial statements) adjusted for the Group's
80% working interest in the Shaikan Field.
Adjusted EBITDA
Adjusted EBITDA is a useful indicator of the Group's profitability, which excludes the impact of costs attributable to tax expense)/(credit), finance costs, finance revenue, depreciation, amortisation, impairment of receivables and provision against inventory held for resale.
Six months ended Six months ended
Year ended 31 December
2024
30 June 2025 30 June 2024
USD million
USD million USD million
(Loss)/profit after tax (7.2) 0.4 7.2
Finance costs 1.0 0.8 1.7
Finance income (1.1) (2.0) (4.1)
Tax (credit)/charge (0.2) 0.6 0.7
Depreciation of oil and gas assets 41.2 36.5 75.8
Depreciation of other PPE assets and amortisation of 1.2 1.7 3.0
intangibles
Increase/(decrease) of expected credit loss provision on 8.9 (1.7) (8.2)
trade receivables
Reversal of provision against inventory held for resale (2.6) - -
Adjusted EBITDA 41.1 36.4 76.1
Net cash
Net cash is a useful indicator of the Group's indebtedness and financial flexibility because it indicates the level of cash and cash equivalents less cash borrowings within the Group's business. Net cash is defined as cash and cash equivalents, less current and non-current borrowings and non-cash adjustments. Non-cash adjustments include unamortised arrangement fees and other adjustments.
30 June 2025 30 June 2024 31 December 2024
USD million USD million USD million
Cash and cash equivalents 99.0 102.3 102.3
Borrowings - - -
Net cash 99.0 102.3 102.3
Net Capital expenditure
Net capital expenditure is the value of the Group's additions to oil and gas assets excluding the change in value of the decommissioning asset or any asset impairment.
Six months ended Six months ended
Year ended 31 December 2024
30 June 2025 30 June 2024
USD million
USD million USD million
Net capital expenditure 18.1 7.8 18.3
As detailed in Note 10 to the financial statements, the net capital expenditure in the period ended 30 June 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 period. 2025 full year capex guidance of USD30-USD35 million excludes this non-cash item.
Free cash flow
Free cash flow represents the Group's cash flows, before any dividends and share buybacks including related fees.
Six months ended Six months ended
Year ended 31 December 2024
30 June 2025 30 June 2024
USD million
USD million USD million
Net cash generated from operating activities 38.3 42.8 93.5
Net cash used in investing activities (13.5) (16.0) (27.6)
Payment of leases (0.2) (0.2) (0.5)
Free cash flow 24.6 26.6 65.4
Principal risks & uncertainties
The Board determines and reviews the key risks for the Group on a regular basis. The principal risks, and how the Group seeks to mitigate them, for the second half of the year are largely consistent with those detailed in the management of principal risks and uncertainties section of the 2024 Annual Report and Accounts. The principal risks are listed below:
Strategic Operational Financial
Health, safety and
Export route availability Commodity prices
environment ("HSE") risks
Political, social and economic
Gas flaring Oil revenue payment mechanism
instability
Liquidity and funding
Stakeholder misalignment Security
capability
Disputes regarding title or
Reserves
exploration and production rights
Business conduct and
Field delivery risk
anti-corruption
Risk of economic sanctions
impacting the Group
Climate change
Organisation and talent
Cyber security
Responsibility statement
The Directors confirm that to the best of their knowledge:
a. the condensed set of financial statements has been prepared in accordance with UK-adopted IAS 34 (Interim Financial
Reporting); b. the interim management report includes a fair review of the information required by DTR 4.2.7R (indication of
important events and their impact during the first six months and description of principal risks and uncertainties
for the remaining six months of the year); and c. the interim management report includes a fair review of the information required by DTR 4.2.8R (disclosure of
related parties' transactions and changes therein).
By order of the Board
Jon Harris
Chief Executive Officer
27 August 2025
INDEPENDENT REVIEW REPORT TO GULF KEYSTONE PETROLEUM LIMITED
Conclusion
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2025 is not prepared, in all material respects, in accordance with UK adopted International Accounting Standard 34 and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
We have been engaged by Gulf Keystone Petroleum Limited (the "company") and its subsidiaries (the "Group") to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2025 which comprises the condensed consolidated income statement, the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash ?ow statement and the related explanatory notes that have been reviewed.
Basis for conclusion
We conducted our review in accordance with the International Standard on Review Engagements (UK) 2410, "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" ("ISRE (UK) 2410"). A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
As disclosed in Note 2, the annual financial statements of the Group are prepared in accordance with UK adopted international accounting standards. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with UK adopted International Accounting Standard 34, "Interim Financial Reporting".
Conclusions relating to going concern
Based on our review procedures, which are less extensive than those performed in an audit as described in the Basis for conclusion section of this report, nothing has come to our attention to suggest that the directors have inappropriately adopted the going concern basis of accounting or that the directors have identified material uncertainties relating to going concern that are not appropriately disclosed.
This conclusion is based on the review procedures performed in accordance with ISRE (UK) 2410, however future events or conditions may cause the Group to cease to continue as a going concern.
Responsibilities of directors
The directors are responsible for preparing the half-yearly financial report in accordance with the UK adopted International Accounting Standard 34 "Interim Financial Reporting", the Bermuda Companies Act 1981 and Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
In preparing the half-yearly financial report, the directors are responsible for assessing the Group's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or have no realistic alternative but to do so.
Auditor's responsibilities for the review of the financial information
In reviewing the half-yearly report, we are responsible for expressing to the Company a conclusion on the condensed set of financial statement in the half-yearly financial report. Our conclusion, including our Conclusions Relating to Going Concern, are based on procedures that are less extensive than audit procedures, as described in the Basis for Conclusion paragraph of this report.
Use of our report
Our report has been prepared in accordance with the terms of our engagement to assist the Company in meeting the requirements of the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority and for no other purpose. No person is entitled to rely on this report unless such a person is a person entitled to rely upon this report by virtue of and for the purpose of our terms of engagement or has been expressly authorised to do so by our prior written consent. Save as above, we do not accept responsibility for this report to any other person or for any other purpose and we hereby expressly disclaim any and all such liability.
BDO LLP
Chartered Accountants
London, UK
27 August 2025
BDO LLP is a limited liability partnership registered in England and Wales (with registered number OC305127).
Condensed consolidated income statement
For the six months ended 30 June 2025
Year
Six months ended Six months ended
ended 31 December
2024
Notes 30 June 2025 30 June 2024
Unaudited Unaudited
Audited
USD'000 USD'000
USD'000
Revenue 4 83,144 71,186 151,208
Cost of sales 5 (71,172) (65,675) (138,866)
(Increase)/decrease of expected credit loss 12 (8,911) 1,676 8,191
provision on trade receivables
Gross profit 3,061 7,187 20,533
Other general and administrative expenses 6 (4,593) (5,392) (11,412)
Share option related expense 7 (4,435) (2,055) (4,419)
(Loss)/profit from operations (5,967) (260) 4,702
Finance income 1,124 2,008 4,116
Finance costs (970) (814) (1,676)
Foreign exchange (losses)/gains (1,651) 124 724
(Loss)/profit before tax (7,464) 1,058 7,866
Tax credit/(charge) 250 (616) (708)
(Loss)/profit after tax (7,214) 442 7,158
(Loss)/profit per share (cents)
Basic 8 (3.32) 0.20 3.26
Diluted 8 (3.32) 0.19 3.13
Condensed consolidated statement of comprehensive income
For the six months ended 30 June 2025
Six months Six months
Year ended
ended ended
31 December 2024
30 June 2025 30 June 2024
Audited
Unaudited Unaudited
USD'000 USD'000 USD'000
(Loss)/profit after tax for the period (7,214) 442 7,158
Items that may be reclassified subsequently to profit or
loss:
Exchange differences on translation of foreign operations 2,289 (139) (517)
Total comprehensive (loss)/income for the period (4,925) 303 6,641
Condensed consolidated balance sheet
As at 30 June 2025
30 June
31 December 2024
2025
Notes Audited
Unaudited
USD'000
USD'000
Non-current assets
Property, plant and equipment 10 365,592 388,450
Intangible assets 607 1,255
Trade receivables 12 120,902 138,175
Deferred tax asset 1,159 825
488,260 528,705
Current assets
Inventories 11 7,777 9,852
Trade and other receivables 12 35,096 26,779
Cash and cash equivalents 99,041 102,346
141,914 138,977
Total assets 630,174 667,682
Current liabilities
Trade and other payables 13 (110,223) (117,277)
Deferred income 13 (800) (716)
(111,023) (117,993)
Non-current liabilities
Trade and other payables 13 (1,080) (1,112)
Provisions (37,594) (36,247)
(38,674) (37,359)
Total liabilities (149,697) (155,352)
Net assets 480,477 512,330
Equity
Share capital 14 217,005 217,005
Share premium account 14 439,105 463,985
Exchange translation reserve (1,994) (4,283)
Accumulated losses (173,639) (164,377)
Total equity 480,477 512,330
Condensed consolidated statement of changes in equity
For the six months ended 30 June 2025
Exchange
Share Share premium Accumulated Total
translation
capital account losses equity
reserve
USD'000 USD'000 USD'000 USD'000 USD'000
Balance at 1 January 2024 (audited) 222,443 503,312 (3,766) (174,752) 547,237
Profit after tax for the period - - - 442 442
Exchange difference of translation of foreign - - (139) - (139)
operations
Total comprehensive (loss)/income for the period - - (139) 442 303
Dividends - (15,000) - - (15,000)
Share issues 255 - - (255) -
Repurchase of ordinary shares (3,359) (2,525) - - (5,884)
Employee share schemes - - - 1,337 1,337
Balance at 30 June 2024 (unaudited) 219,339 485,787 (3,905) (173,228) 527,993
Profit after tax for the period - - - 6,716 6,716
Exchange difference of translation of foreign - - (378) - (378)
operations
Total comprehensive (loss)/income for the period - - (378) 6,716 6,338
Dividends - (19,933) - - (19,933)
Share issues - - - - -
Repurchase of ordinary shares (2,334) (1,869) - - (4,203)
Employee share schemes - - - 2,135 2,135
Balance at 31 December 2024 (audited) 217,005 463,985 (4,283) (164,377) 512,330
Loss after tax for the period - - - (7,214) (7,214)
Exchange difference of translation of foreign - - 2,289 - 2,289
operations
Total comprehensive income/(loss) for the period - - 2,289 (7,214) (4,925)
Dividends - (24,880) - - (24,880)
Reissue of repurchased shares - - - (3,506) (3,506)
Own shares repurchased and held in Employee - - - (526) (526)
Benefit Trust
Employee share schemes - - - 1,984 1,984
Balance at 30 June 2025 (unaudited) 217,005 439,105 (1,994) (173,639) 480,477
Condensed consolidated cash flow statement
for the six months ended 30 June 2025
Six months Six months
Year ended
ended ended
Notes 31 December 2024
30 June 2025 30 June 2024
Audited
Unaudited Unaudited
USD'000 USD'000 USD'000
Operating activities
Cash generated in operations 9 37,171 40,788 89,427
Interest received 1,124 2,008 4,116
Net cash generated in operating activities 38,295 42,796 93,543
Investing activities
Purchase of intangible assets (133) (32) (420)
Purchase of property, plant and equipment 10 (13,385) (15,973) (27,178)
Net cash used in investing activities (13,518) (16,005) (27,598)
Financing activities
Payment of dividends 14 (24,880) - (34,933)
Purchase of own shares - share buyback - (5,884) (10,087)
Purchase of own shares - employee share-based payments 14 (4,032) - -
Payment of leases (216) (238) (452)
Net cash used in financing activities (29,128) (6,122) (45,472)
Net (decrease)/increase in cash and cash equivalents (4,351) 20,669 20,473
Cash and cash equivalents at beginning of period 102,346 81,709 81,709
Effect of foreign exchange rate changes 1,046 (46) 164
Cash and cash equivalents at end of the period being bank 99,041 102,332 102,346
balances and cash on hand
Notes to the consolidated financial statements
1. 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.
2. Summary of material accounting policies
These interim financial statements should be read in conjunction with the audited financial statements contained in the Annual Report and Accounts for the year ended 31 December 2024. The Annual Report and Accounts of the Group were prepared in accordance with United Kingdom adopted International Accounting Standards ("IAS"). The condensed set of financial statements included in this half yearly financial report have been prepared in accordance with IAS 34 'Interim Financial Reporting' and the Disclosure and Transparency Rules ("DTR") of the Financial Conduct Authority ("FCA") in the United Kingdom as applicable to interim financial reporting.
The condensed set of financial statements included in this half yearly financial report have been prepared on a going concern basis as the Directors consider that the Group has adequate resources to continue operating for the foreseeable future.
The accounting policies adopted in the 2025 half-yearly financial report are the same as those adopted in the 2024 Annual Report and Accounts, other than the implementation of new International Financial Reporting Standards ("IFRS") reporting standards.
The financial information included herein for the year ended 31 December 2024 does not constitute the Group's financial statements for that year but is derived from those Accounts. The auditor's report on those Accounts was unqualified and did not include a reference to any matters to which the auditor drew attention by way of emphasis of matter.
Adoption of new and revised accounting standards
As of 1 January 2025, a number of accounting standard amendments and interpretations became effective. The adoption of these amendments and interpretations has not had a material impact on the financial statements of the Group for the six months ended 30 June 2025.
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 Chief Executive Officer's review and the Principal risks and uncertainties. The financial position of the Group at the period end and its cash flows and liquidity position are included in the Financial review.
As at 27 August 2025 the Group had USD105.7 million of cash and no debt. The Group continues to closely monitor and manage its liquidity. Cash forecasts are regularly produced and sensitivities are run for different scenarios including, but not limited to, changes in sales volumes, commodity price fluctuations, timing of export pipeline restart, delays to revenue receipts and cost optimisations. The Group remains focused on taking appropriate actions to preserve its liquidity position.
The Group's liquidity position has remained stable up to the date of this report. Although local sales were impacted by the precautionary shut-in of the Shaikan field from mid-July due to drone attacks at a number of oil fields in the vicinity of Shaikan operations, demand this year has been consistently strong. This enabled production to remain within the 2025 guidance range. Following the re-start of operations earlier this month, production has since returned to similar levels as before the shut-in. The Group continues to execute a disciplined work programme, with careful management of investment with a focus on production optimisation initiatives and well maintenance to offset natural field decline. Nonetheless, the Group is aware there could be a potential decline in local sales, and potential delays in Kurdistan Regional Government ("KRG") revenue receipts once the Iraq-Türkiye pipeline ("ITP") has been reopened. The key uncertainties in the current environment are summarised below:
-- Geopolitical events and regional instability: recent events such as the recent conflict between Israel and Iran and
drone attacks are challenging to foresee; -- Local sales: the Group continues local sales with payments from buyers required in advance following extensive due
diligence. During H1 2025 the Group received over USD78 million related to local sales. However, production volumes
(average 44,100 bopd in H1 2025) and prices have fluctuated in the past and may be difficult to predict; and -- Export sales: The Group continues to engage with the KRG and Federal Iraq on the resumption of Kurdistan's oil
exports, although a number of key details remain outstanding including payment surety for future oil exports, the
repayment of outstanding receivables and the preservation of current contract economics which are a key step
towards the resumption of Kurdistan oil exports. As such, the timing of the reopening of the ITP and payment
mechanism remain uncertain.
The Directors believe an agreement will ultimately be reached to reopen the ITP, and reasonably expect that overdue balances will be paid, and that receipts from the KRG will return to a more regular basis. However, a reduction in local sales or reopening of the pipeline with a deferral of revenue receipts could result in liquidity pressures within the 12-month going concern period.
The Directors have considered sensitivities, including local sales volumes and potential delays in KRG revenue receipts once the ITP reopens, to assess the impact on the Group's liquidity position and believe sufficient mitigating actions are available to withstand such impacts within the 12-month going concern period. Specifically, the Directors considered stress tests that included no further local sales that could arise from constrained local demand or a prolonged disruption to operations, delayed KRG revenue receipts once the ITP reopens and confirmed that cost reduction opportunities exist to ensure that the Group can continue to discharge its liabilities for a period of at least 12 months.
As explained in note 13, although the Group has recognised current liabilities of around USD84 million payable to the KRG, it does not expect these will be cash settled.
Overall, the Group's forecasts which include the USD25 million dividend declared on 27 August 2025, and taking into account the applicable risks, stress test scenarios and potential mitigating actions, show that it has sufficient financial resources for the 12 months from the date of approval of these interim financial statements.
Based on the analysis performed, the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for the foreseeable future. Thus, the going concern basis of accounting is used to prepare these interim financial statements.
Critical accounting judgements and key sources of estimation uncertainty
In the application of the accounting policies described above, the Group is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of revision and future periods if the revision affects both current and future periods.
Critical judgements in applying the Group's accounting policies
The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the Directors have made in the process of applying the Group's accounting policies and that have the most significant effect on the amounts recognised in financial statements
Production sharing contract entitlement: Revenue, trade receivables and capacity building payments
The recognition of revenue, particularly the recognition of revenue from pipeline exports, is considered to be a key accounting judgement. The Group began commercial production from the Shaikan Field in July 2013 and historically made sales to both the domestic and export markets. The Group considers that revenue can be reliably measured as it passes the delivery point into the export pipeline or truck, in the period all revenue was to the local market via trucking. The critical accounting judgement applied in preparing the financial statements is that it is appropriate to continue to recognise trade receivables due from the KRG for deliveries from 1 October 2022 to 25 March 2023 based on an alternative proposed pricing mechanism, notwithstanding that there is no signed lifting agreement for that period and the pricing mechanism has not yet been agreed. 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 pricing terms; no further receipts for the period of pipeline exports from 1 October 2022 to 25 March 2023 have been received.
No adjustments were made in the period in respect of the above as revenue was earned via local sales, with no agreement yet reached in respect of the export period mentioned above.
Any future agreements between the Group and the KRG might change the amounts of revenue recognised.
During past production sharing contract ("PSC") negotiations with the Ministry of Natural Resources ("MNR"), it was tentatively agreed that the Shaikan Contractor would provide the KRG a 20% carried working interest in the PSC. This would result in a reduction of GKP's working interest from 80% to 61.5%. To compensate for such decrease, capacity building payments expense would be reduced to 20% of profit petroleum. While the PSC has not been formally amended, it was agreed that GKP would invoice the KRG for oil sales based on the proposed revised terms from October 2017. The financial statements reflect the proposed revised working interest of 61.5%. Relative to the PSC terms, the proposed revised invoicing terms result in a decrease in both revenue and cost of sales and on a net basis are slightly positive for the Group.
As part of earlier PSC negotiations, on 16 March 2016, GKP signed a bilateral agreement with the MNR (the "Bilateral Agreement"). The Bilateral Agreement included a reduction in the Group's capacity building payment from 40% to 30% of profit petroleum. Subsequent to signing the Bilateral Agreement, further negotiations resulted in the capacity building payment rate being reduced from 30% to 20%, which has formed the basis for all oil sales invoices to date as noted above. Since PSC negotiations have not been finalised, GKP has included a non-cash payable for the difference between the capacity building rate of 20% and 30%, which is recognised in cost of sales and other payables. See note 13 for further details.
The Group expects to confirm with the MNR whether to proceed with a formal amendment to the PSC to reflect current invoice terms.
Material sources of estimation uncertainty
The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.
Expected credit loss ("ECL")
The recoverability of receivables is a key accounting judgement. The difference between the nominal value of receivables and the expected value of receivables after allowing for counterparty default risk is the basis for the ECL. This ECL is offset against current and non-current receivable amounts as appropriate within the balance sheet with the change in the receivable balance during the period recognised in the income statement.
In making this judgement, a weighted average has been applied to modelled receipt profiles, upon which a counterparty default allowance has been applied to derive the ECL. When modelling receipt profiles management have made a number of key estimates that are dependent upon uncertain future events including: the KRG's deemed credit rating, the export pipeline reopening date, that the unrecovered cost pool is depleted on a cash basis as invoices for crude sales are paid and can be recovered through local or 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, a potential commercial settlement with the KRG which may include an agreement on the settlement mechanism of receivable balances on terms not yet agreed, 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 12.
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 basis for the updated estimate of the current value of obligations and costs at 30 June 2025 was prepared internally. An independent third-party review of the obligations and costs to decommission the asset was undertaken by ERC Equipoise as at 31 December 2023, which closely aligned with the internal estimate at the time; this estimate formed the basis of the updated estimate of the current value of obligations and costs as at 30 June 2025.
Management have increased the decommissioning costs as at 30 June 2025, 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.
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 30 June 2025 was the Shaikan Field with a carrying value, being Oil and Gas assets less capitalised decommissioning provision, of USD324.9 million (31 December 2024: USD348.9 million). The Group performed an impairment indicator evaluation as at 30 June 2025 and concluded that no impairment indicators arose. The key areas of estimation in assessing the potential impairment indicators are as follows:
-- While the date of the re-opening of the ITP remains uncertain, management have assessed a re-opening date of August
2026 as being reasonable. Although the estimated re-opening date is ten months later than the base case assessment
at 31 December 2024, management previously performed sensitivities of up to two years with no impairment, therefore
this delay to the projected re-opening was not assessed to be an impairment trigger; -- The Group's netback oil price applied only to export pipeline sales was based on the Brent forward curve and market
participants' consensus, including banks, analysts and independent reserves evaluators, as at 30 June 2025 for the
years 2025 to 2030 with inflation of 2.5% per annum thereafter, less transportation costs and quality adjustments.
Brent consensus prices are as follows:
Scenario (USD/bbl - nominal) 2025 2026 2027 2028 2029 2030 30 June 2025 - base case 66.0 65.0 70.0 71.0 70.0 80.0 30 June 2025 - stress case 59.4 58.5 63.0 63.9 63.0 72.0 31 December 2024 - base case 74.0 72.0 74.0 75.0 73.0 80.0 31 December 2024 - stress case 66.6 64.8 66.6 67.5 65.7 72.0
-- Management have previously applied sensitivities including a 10% reduction from base case pricing to derive a
stress case price with no impairment impact. The stress case pricing is noted above; -- Discount rates are adjusted to reflect risks specific to the Shaikan Field and the Kurdistan Region of Iraq.
Management assessed changes to the key variables that could impact discount rate and concluded no change was
necessary. The post-tax nominal discount rate was estimated to be 16%, unchanged from 31 December 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 increase in comparison to 31 December
2024 impairment assessment; -- No adverse changes were noted for commercial reserves and production profiles; -- No changes were noted in the operating environment such as local market conditions in the period (although please
see Going concern on events that occurred after period end), tax or other legal or regulatory changes. Following
the judgment issued by the Iraqi Al Kharkh (Commercial) Court on 18 December 2024 which declared that the Shaikan
PSC was valid and enforceable, the Company was subsequently informed on 27 February 2025 that Iraqi Ministry of Oil
had applied to the Cassation (Appeal) Court for a procedure known as a 'Correction'. However, this application was
denied by the Court and the decision is considered final. Although this ruling by the Al Kharkh Court has decreased
the risk of challenge to the validity of the Shaikan PSC, the Company has maintained its overall risk estimates in
respect of its operating environment, albeit the PSC validity risk has lowered. There has been no change to the
status of the Iraqi Federal Supreme Court ruling from February 2022 which stated that the Kurdistan Oil and Gas Law
was unconstitutional; 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 1 per barrel CO2 emissions intensity by at
least 50% versus the original 2020 baseline of 38 kgCO2e per barrel is dependent on the timing of sanction and
implementation of the Gas Management Plan. The International Energy Agency's ("IEA") most recent Announced Pledges
Scenario ("APS") and Net Zero Emissions ("NZE") climate scenario oil prices and carbon taxes were used to evaluate
the potential impact of the principal climate change transition risks. The APS scenario assumes that governments
will meet, in full and on time, all of the climate-related commitments that they have announced, including longer
term net zero emissions targets and pledges in Nationally Determined Contributions to reduce national emissions and
adapt to the impacts of climate change leading to a global temperature rise of 1.7°C in 2100. NZE scenario portrays
a pathway for the global energy sector to reach net zero CO2 emissions by 2050 which is consistent with limiting
long-term global warming to 1.5 °C with limited overshoot. The assumed re-opening date is August 2026, which is ten
months later than the base case assessment at 31 December 2024, which had a pipeline reopening date of October 2025
whereby management previously performed sensitivities of up to two years. There was no impairment under the APS
scenario, but a potential impairment under the NZE scenario. While the IEA oil price assumptions incorporate carbon
prices, the IEA has not disclosed the assumed average carbon intensity per barrel of production. Therefore, at 31
December 2024 the Group performed a sensitivity to conservatively include IEA carbon pricing on all production
which results in no impairment under the APS scenario, but a potential impairment under the NZE scenario.
3. 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% (31 December 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 condensed consolidated primary statements and the related notes.
4. Revenue
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Oil sales via export pipeline - - -
Local oil sales 83,144 71,186 151,208
83,144 71,186 151,208
The Group accounting policy for revenue recognition is set out in its 2024 Annual Report, with revenue recognised upon crude oil passing the delivery points, either being entry into pipeline or delivered into trucks.
Throughout the period, GKP sold oil to local buyers at negotiated prices. The weighted average realised price achieved in the six-month period to 30 June 2025 was USD27.8/bbl (H1 2024: USD26.3/bbl; FY 2024: USD26.8/bbl). Local buyers are contracted to pay GKP in advance of receipt of oil; such amounts are recognised as deferred income (see note 13) until a customer's receipt of oil at the delivery point.
Information about major customers
Customers making up greater than 10% of revenue are as follows:
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Customer A 65% 86% 88%
Customer B 23% 14%<10%
Customer C 12% 0%<10%
5. Cost of Sales
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
Operating costs 26,893 23,917 52,435
Capacity building payments 5,885 5,131 10,818
Changes in oil inventory value (198) 98 (168)
Depreciation of oil and gas assets and operational assets 41,219 36,529 75,781
Reversal of provision against inventory held for sale (2,627) - -
71,172 65,675 138,866
Capacity building payments have been recorded in line with the MNR's proposed pricing mechanism (see 2024 Annual Report); any difference between the proposed and final pricing mechanism will be reflected in future periods.
The Group accounting policy for depreciation of oil and gas assets is set out in its 2024 Annual Report. The increase in charge compared to the corresponding period in 2024 is principally derived from higher production in the six-month period ended 30 June 2025.
During the six-month period ended 30 June 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 six-month period ended 30 June 2025 (H1 2024: nil; FY 2024: nil). Following this reversal in the six-month period ended 30 June 2025, these items were capitalised as an addition to oil and gas assets (see note 10).
6. Other general and administrative expenses
Six months Year ended
ended 31 December
Six months
ended
30 June 2025 30 June 2024 2024
Unaudited
USD'000
Unaudited Audited
USD'000 USD'000
Depreciation and amortisation 1,233 1,690 3,033
Other general and administrative costs 3,360 3,702 8,379
4,593 5,392 11,412
7. Share option related expense
Six months Year ended
ended 31 December
Six months
ended
30 June 2025 30 June 2024 2024
Unaudited
USD'000
Unaudited Audited
USD'000 USD'000
Share-based payment expense 1,984 1,337 3,472
Payments related to share options exercised 2,058 741 704
Share-based payment/(credit) related provision for taxes 393 (23) 243
4,435 2,055 4,419
During the six-month period ending 30 June 2025, share options exercised relate to options vesting in the period under both the Deferred Bonus Plan and the Long Term Incentive Plan. Further details relating to these plans are set out in the 2024 Annual Report. The Company's Employee Benefit Trust settled employee share option exercises from shares purchased during the period (see note 14).
8. Earnings per share
The calculation of the basic and diluted profit per share is based on the following data:
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
(Loss)/profit after tax (USD'000) (7,214) 442 7,158
Number of shares ('000s):
Basic weighted average number of ordinary shares 217,500 222,188 219,562
Basic (loss)/earnings per share (cents) (3.32) 0.20 3.26
The Group followed the steps specified by IAS 33 'Earnings per share' in determining whether outstanding share options are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
Number of shares ('000s):
Basic weighted average number of ordinary shares 217,500 222,188 219,562
Effect of dilutive potential ordinary shares - 5,906 9,134
Diluted number of ordinary shares outstanding 217,500 228,094 228,696
Diluted (loss)/earnings per share (cents) (1) (3.32) 0.19 3.13
1. As at 30 June 2025, the Group had 9,989k antidilutive (H1 2024: 5,906k dilutive; FY 2024: 9,134 dilutive) ordinary
shares relating to outstanding share options. Earnings per share is calculated on the assumption of conversion of
all potentially dilutive ordinary shares; however, during a period where a company makes a loss, anti-dilutive
shares are not included in the loss per share calculation as they would reduce the reported loss per share.
The weighted average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee ("EBT") of 0.2 million, (H1 2024: 0.2 million; FY 2024: 0.1 million) see note 14.
9. Reconciliation of loss from operations to net cash generated in operating activities
Six months Six months Year ended
ended ended 31 December
30 June 2025 30 June 2024 2024
Unaudited Unaudited Audited
USD'000 USD'000 USD'000
(Loss)/profit from operations (5,967) (260) 4,702
Adjustments for:
Depreciation, depletion and amortisation of property, plant and equipment 41,651 37,008 76,752
(including the right of use assets)
Amortisation of intangible assets 801 1,211 1,980
Share-based payment expense 1,984 1,337 3,472
Increase/(decrease) of provision for impairment of trade receivables 8,911 (1,676) (8,191)
(Reversal of provision)/provision against inventory held for sale (2,627) - 34
Operating cash flows before movements in working capital 44,753 37,620 78,749
Increase in inventories (714) (18) 49
(Increase)/decrease in trade and other receivables (27) 1,042 (1,290)
(Decrease)/increase in trade and other payables (6,841) 2,144 11,919
Cash generated from operations 37,171 40,788 89,427
10. Property, plant and equipment
Oil and Gas Fixtures and Right of use
Assets Equipment Assets Total
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' costs - - (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
Cost 1,010,429 9,687 1,701 1,021,817
Accumulated depreciation (625,258) (7,914) (195) (633,367)
Net book value at 31 December 2024 385,171 1,773 1,506 388,450
Period ended 30 June 2025
Opening net book value 385,171 1,773 1,506 388,450
Additions 18,055 143 - 18,198
Revision to decommissioning asset 459 - - 459
Depreciation charge (41,219) (273) (159) (41,651)
Foreign currency translation differences - 6 130 136
Closing net book value 362,466 1,649 1,477 365,592
At 30 June 2025
Cost 1,028,943 9,836 1,831 1,040,610
Accumulated depreciation (666,477) (8,187) (354) (675,018)
Net book value 362,466 1,649 1,477 365,592
The additions to the Shaikan asset, amounting to USD18.1 million during the six-month period ended 30 June 2025 (FY 2024: 18.3 million) included safety critical upgrades, the purchase of jet pumps as well as items purchased and paid for in 2022 and 2023 and subsequently classified as impaired inventory held for sale (see note 5). 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 USD0.5 million increase (2024: USD0.7 million decrease) in decommissioning asset value relates to a USD0.1 million increase in changes to inflation and discount rates (2024: USD1.1 million decrease), in addition to an increase of USD0.4 million relating to facilities work (2024: USD0.4 million).
11. Inventories
31 December
30 June 2025
2024
Unaudited
Audited
USD'000
USD'000
Warehouse stocks and materials 7,345 6,829
Inventory held for sale - 2,789
Crude oil 432 234
7,777 9,852
In the six-month period ended 30 June 2025, management determined that inventory previously impaired and held for sale, was no longer being held for sale. Impairments of USD2.6 million recognised within Cost of sales in prior periods were reversed in the six-month period ended 30 June 2025 (see note 5) and the unimpaired USD5.4 million was included as an addition within Oil and gas assets as at 30 June 2025 (see note 10).
12. Trade and other receivables
Non-current receivables
31 December
30 June 2025
2024
Unaudited
Audited
USD'000
USD'000
Trade receivables - non-current 120,902 138,175
Current receivables
31 December
30 June 2025
2024
Unaudited
Audited
USD'000
USD'000
Trade receivables - current 24,946 16,583
Underlift 436 -
Other receivables 7,172 7,291
Prepayments and accrued income 2,542 2,905
Total current receivables 35,096 26,779
Total receivables 155,998 164,954
Reconciliation of trade receivables
31 December
30 June 2025
2024
Unaudited
Audited
USD'000
USD'000
Gross carrying amount relating to export sales 171,026 171,026
Less: impairment allowance relating to export sales (25,178) (16,267)
Carrying value relating to export sales at end of period 145,848 154,759
Trade receivables relating to local oil sales 1,310 -
Total carrying value of trade receivables 147,158 154,759
Gross trade receivables relating to export sales of USD171.0 million (2024: USD171.0 million) are comprised of invoiced amounts due, based upon Kurdistan blend ("KBT") pricing, from the KRG for crude oil sales totalling USD158.8 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 Kalegran B.V. (a subsidiary of MOL Group) ("MOL") amounting to USD12.2 million (2024: USD12.2 million). Although no legal right of offset exists, the net balance due from the KRG comprises USD158.8 million (2024: USD158.8 million) included in trade receivables and USD7.7 million (2024: USD7.7 million) included within current liabilities (see note 13), resulting in a net receivable balance due from the KRG relating to crude oil sales of USD151.1 million (2024: USD151.1 million).
As detailed in the Summary of material accounting policies section within the 2024 Annual Report, entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred, and profit oil, which is the mechanism through which profits are shared between the Company, its partner MOL and the KRG. The outstanding receivable balance of USD151.1 million above, comprises USD120.4 million cost oil and USD30.7 million profit oil (2024: USD151.1 million, USD120.4 million and USD30.7 million respectively) (net of Capacity Building Payment).
Impairment allowance relating to export sales (ECL)
While GKP expects to recover the full value of the outstanding invoices and purchased revenue arrears, an ECL of USD25.2 million (2024: USD16.3 million) was provided against the trade receivables balance in accordance with IFRS 9 'Financial Instruments'. During the six-month period to 30 June 2025, an USD8.9 million charge was recognised due to the increase in the ECL provision (H1 2024: USD1.7 million credit; FY 2024: USD8.2 million credit) arising from the delayed estimated pipeline reopening date and updated commercial assumptions applied compared to the prior year.
Negotiations are ongoing with the MNR on the wider commercial settlement, including the timing and mechanism for settling outstanding receivables. As a result of the ongoing discussions there is uncertainty on the balance of the unrecovered cost pool and therefore when the Contractor expects to start to recover the receivable balance which underpins the ECL estimate. As reported in the 2024 Annual Report, the Company had expected to start recovering cost oil balances within receivables in the first half of 2025, however the Company now expects the Contractor to effectively begin recovering the cost oil component of the trade receivables balance due from the KRG in the second half of 2025 via the settlement of invoices due from the point that the outstanding cost pool balance declines to a level at or below the trade receivable balance. It is expected that upon conclusion of commercial negotiations, cash received in line with current entitlements would be offset against the overdue trade receivables balance. This is incorporated into the ECL scenario modelling (see Material sources of estimation uncertainty section included above). Following the export pipeline reopening the remaining overdue trade receivables are expected to be recovered from the KRG including both the outstanding cost oil balance at that time and the full profit oil balance referenced above.
The outstanding sales invoices from October 2022 - March 2023 receivable have been recognised based on the MNR's proposed pricing mechanism, which GKP has not accepted (see Critical accounting judgements and key sources of estimation uncertainty section included above)).
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 date of the re-opening of the ITP 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 4.43%. An increase of the CDS of 2% would increase the ECL provision by USD7.4 million; conversely a decrease of the CDS by 2% would decrease the ECL provision by USD7.6 million. Doubling or halving the probability of the modelled commercial settlement, in which the receivables are recovered via future production would cause the ECL provision to increase by USD6.7 million or decrease by USD3.2m respectively. GKP estimates that re-opening of ITP will occur in August 2026, should this be delayed by 12 months there would be a USD6.3 million increase in the ECL provision.
All other variables listed within the Summary of material accounting policies, when individually reasonably varied do not have a material impact upon ECL valuation.
13. Trade and other payables
Current liabilities
30 June 31 December
2025 2024
Unaudited Audited
USD'000 USD'000
Trade payables 2,304 1,746
Accrued expenditures 12,988 22,228
Amounts due to KRG not expected to be cash settled 83,722 80,905
Capacity building payment due to KRG on trade receivables 7,687 7,687
Other payables 3,090 4,080
Finance lease obligations 432 395
Overlift - 236
Total current liabilities 110,223 117,277
Trade payables and accrued expenditures principally comprise amounts outstanding for trade purchases and ongoing costs; the Directors consider that carrying amounts approximate fair value. Accrued expenditures have decreased due to payment of operational invoices and other expenditure which became due in the six-month period ended 30 June 2025, having been accrued at 2024 year end.
Amounts due to the KRG not expected to be cash settled of USD83.7 million (2024: USD80.9 million) include:
-- USD40.9 million (2024: USD40.1 million) expected to be offset against oil sales to the KRG up to 2018, together with
other amounts considered due from the KRG, that have not been recognised in the financial statements as management
consider that the criteria for revenue recognition have not been satisfied, and -- USD42.8 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
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 and key sources of estimation
uncertainty section included above), the value of which is expected to exceed the accrued USD42.8 million.
Deferred income
At 30 June 2025, deferred income of USD0.8 million (2024: USD0.7 million) relates to cash advances paid by local oil buyers in advance of lifting oil (see note 4).
Non-current liabilities
30 June 31 December
2025 2024
Unaudited Audited
USD'000 USD'000
Non-current finance lease liability 1,080 1,112
14. Share capital
Common shares
No. of shares Share capital Share premium Amount
000 USD'000 USD'000 USD'000
Issued and fully paid
Balance 1 January 2025 (audited) 217,005 217,005 463,985 680,990
Dividends - - (24,880) (24,880)
Balance 30 June 2025 (unaudited) 217,005 217,005 439,105 656,110
During the six-month period ended 30 June 2025, the Company's EBT purchased 1.6 million shares of the Company for future satisfaction of employee share options for a total consideration of USD4.0 million that originated from the Company. Subsequently 1.4 million of these shares, with a value of USD3.5 million, were used to satisfy exercised employee share options. At period end 0.2 million shares, with a value of USD0.5 million, were retained within the EBT.
15. Contingent liabilities
During the six-month period ended 30 June 2025, the Company has continued negotiations with the MNR around a number of outstanding commercial matters (including the sale of test production oil mentioned below), with the aim of agreeing a formal amendment to the PSC to reflect current invoicing terms.
The Group has a contingent liability of USD27.3 million (31 December 2024: USD27.3 million) in relation to the proceeds from the sale of test production oil prior to the approval of the Shaikan Field Development Plan ("FDP") in June 2013. If a cash outflow to the MNR were required in the future, this would result in a corresponding increase to the unrecovered cost pool as the test production revenue is recorded as a reduction of the cost pool by USD34 million gross to the Contractor (USD27.3 million net to GKP) in the Group's cost Recovery submissions to the MNR.
The above negotiations may lead to a revision to the unrecovered cost pool impacting future revenues, the settlement of previously unrecognised assets and liabilities, netting of existing receivable and payable balances, or require material adjustments to such balances as they are currently recorded. Due to the uncertain and wide range of potential financial outcomes that cannot presently be reliably estimated, no provision for such asset or liability has been recognised within the financial statements.
16. Subsequent Events
On 26 August 2025, the Group entered into a contractual agreement to install water handling facilities at PF-2 which are expected to increase future gross production over the anticipated field baseline. The costs during construction phase are estimated at approximately USD12 million net to GKP in the period up to the anticipated commissioning at the beginning of 2027. Once the water handling facilities have been commissioned, they will be operated under a lease agreement and expected to generate positive cash flows thereafter. The financial effect of this commitment will be reflected in future periods. No adjustment has been made to the 30 June 2025 financial statements.
On 27 August 2025, the Company declared an interim dividend of USD25 million.
GLOSSARY (See also the glossary in the 2024 Annual Report and Accounts)
H1 2024 First half of Financial Year 2024 H1 2025 First half of Financial Year 2025 APS Announced pledges scenario bbl Barrel bopd Barrels of oil per day Capex Capital expenditure CBP Capacity building payment CDS Credit default swap CGU Cash-generating unit Company Gulf Keystone Petroleum Limited Cost Pool Unrecovered cost oil balance DTR Disclosure and Transparency Rules EBITDA Earnings before interest, tax, depreciation and amortisation EBT Employee Benefit Trust ECL Expected credit loss FCA Financial Conduct Authority FDP Field Development Plan G&A General and administrative FY Financial year GKP Gulf Keystone Petroleum Limited Group Gulf Keystone Petroleum Limited and its subsidiaries HSE Health, safety and environment IAS International Accounting Standards IEA International Energy Agency IFRS International Financial Reporting Standards IOC International oil company ITP Iraq-Türkiye pipeline KBT Kurdistan blend KRG Kurdistan Regional Government KRI Kurdistan Region of Iraq LTI Lost Time Incident LTIP Long term incentive plan MMstb Million stock tank barrels MNR Ministry of Natural Resources of the Kurdistan Regional Government MOL Kalegran B.V. (a subsidiary of MOL Group) NZE Net Zero Emissions Opex Operating costs PF-1 Production Facility 1 PF-2 Production Facility 2 PSC Production Sharing Contract Shaikan Contractor GKP and MOL Shaikan PSC Shaikan Production Sharing Contract UKLA United Kingdom Listing Authority USD US dollars
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ISIN: BMG4209G2077 Category Code: MSCM TIDM: GKP LEI Code: 213800QTAQOSSTNTPO15 Sequence No.: 400081 EQS News ID: 2189714 End of Announcement EQS News Service =------------------------------------------------------------------------------------
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August 28, 2025 02:00 ET (06:00 GMT)
