2024 Full Year Results Announcement
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Gulf Keystone Petroleum Ltd (GKP)
20 March 2025
Gulf Keystone Petroleum Ltd. (LSE: GKP) (“Gulf Keystone”, “GKP”, “the Group” or “the Company”)
2024 Full Year Results Announcement
$25 million interim dividend declared & 2025 guidance reiterated
Gulf Keystone, a leading independent operator and producer in the Kurdistan Region of Iraq, today announces its results for the full year ended 31 December 2024.
Jon Harris, Gulf Keystone’s Chief Executive Officer, said: “2024 was a year of strong operational and financial delivery for Gulf Keystone. We have sustained our positive momentum into 2025, with year to date gross average production of c.46,400 bopd, strong local sales demand and a disciplined expenditure programme supporting continued free cash flow generation. As a result, we are pleased to announce today the declaration of a $25 million interim dividend as we reiterate our 2025 operational and financial guidance. We remain focused on facilitating a solution to restart oil exports as we continue to seek fair and transparent agreements regarding payment surety, the repayment of receivables and the preservation of current contract economics.” Highlights to 31 December 2024 and post reporting period
Operational
Shaikan Field estimated reserves
Financial
Outlook
Investor & analyst presentations
GKP’s management team will be hosting a presentation for analysts and investors at 10:00am (GMT) today via live audio webcast:
https://brrmedia.news/GKP_FY_2024
Management will also be hosting an additional webcast presentation focused on retail investors via the Investor Meet Company ("IMC") platform at 12:00pm (GMT) today. The presentation is open to all existing and potential shareholders and participants will be able to submit questions at any time during the event.
https://www.investormeetcompany.com/gulf-keystone-petroleum-ltd/register-investor
Recordings of both presentations will be made available on GKP’s website.
This announcement contains inside information for the purposes of the UK Market Abuse Regime.
Enquiries:
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.
Chair’s statement This is my first annual results statement as Chair of Gulf Keystone following my appointment under sad circumstances in September 2024 after the passing of Martin Angle. Martin was an excellent Chair, an outstanding professional and above all a good friend with whom I worked for many years as a Non-Executive Director. He is sorely missed by all of us at the Company. Thankfully, he has left behind an experienced and diligent Board of Directors and a talented executive team focused on driving shareholder value from the Company’s world-class asset, the Shaikan oil field.
The last two years have been a challenging period for Gulf Keystone, catalysed by the suspension of international crude oil exports from Kurdistan via the Iraq-Türkiye Pipeline (“ITP”) in late March 2023 and the resultant requirement to preserve the Company’s liquidity by accessing new local oil markets whilst cutting costs and safely maintaining production. I am pleased to say that these challenges have been met and, during 2024, the Company generated a significant amount of free cash flow with a much leaner organisation and strong production levels. Production during the year averaged 40,689 bopd gross which, given the relatively low level of development activity, was a good outcome and again demonstrates the quality of the Shaikan reservoir.
The improved cash flow position allowed for the settlement of all the Company’s overdue invoices to our suppliers and service providers in Q1 2024 and for shareholder distributions to recommence consistent with our stated policy. A $10 million share buyback programme was announced in May 2024 and, with continuing strong local sales demand and improving liquidity, the Board approved the payment of a total of $35 million of dividends in July and October 2024. The total shareholder distributions completed during the year were $45 million.
Gulf Keystone’s strong operational and financial performance in 2024 reflected the Company’s commitment to maximise shareholder value and positions it well to capitalise on the potential restart of international oil exports when the ITP reopens. GKP’s leadership team and Board continue to dedicate a significant amount of time and effort to engaging with government and other stakeholders to move towards a solution, both as a Company and alongside other IOCs operating in the region. Engagement remains ongoing as we continue to seek agreements on payment surety, the repayment of past receivables and the preservation of existing commercial terms. We are hopeful of a swift resolution and remain ready to quickly restart oil exports.
One of our primary areas of focus as a Board in 2024 was to ensure that we retain the Company’s considerable talent to navigate through the current operational and commercial environment in Kurdistan. At the same time, we oversaw a number of new Director appointments which have deepened the experience and expertise of the Board and also enabled us to meet the UK Corporate Governance Code and Listing Rules requirements in respect of Board independence, gender and ethnic diversity.
In June 2024, we were pleased to welcome Gabriel Papineau-Legris as a Director following his appointment as Chief Financial Officer at the 2024 AGM, replacing Ian Weatherdon who retired. In October 2024, we also appointed Catherine Krajicek and Marianne Daryabegui to the Board and together they bring many years of experience working in the oil and gas industry, emerging markets, finance and M&A and also as Non-Executive Directors. In addition to her other Board responsibilities, Marianne has assumed the role of the Senior Independent Director for the Company. I am sure that our new Board members will make a significant contribution to the Company and look forward to working with them in the future.
I would like to take this opportunity to thank our shareholders for their continued support through what has been a period of volatility and uncertainty for the Company. We continue to actively engage with our shareholders and welcome all feedback. Gulf Keystone has emerged as a fitter and stronger organisation and, with the success of the local sales arrangements and safe maintenance and enhancement of the Shaikan Field’s production capacity, has been able to restart shareholder distributions with top quartile total shareholder return performance of 24% in 2024 relative to our peers (assuming dividends paid in the year were reinvested). The Board and the Company are now focused on unlocking further upside value by securing a commercial solution to restart oil exports while delivering on our operational and financial guidance for the year.
David Thomas Non-Executive Chair
19 March 2025
CEO review 2024 was a positive year for Gulf Keystone, characterised by strong operational and financial delivery despite the challenging operating environment. As the local sales market in Kurdistan developed, we returned to consistently strong production levels which, combined with a lean work programme and strict cost control, enabled us to generate significant free cash flow, facilitating the restart of shareholder distributions and the preservation of our robust balance sheet.
2024 performance Our performance was underpinned by the extension of our excellent safety track record, with zero Lost Time or Recordable incidents in the year, well below the relevant Kurdistan and international peer benchmarks. This was achieved despite 24/7 truck loading operations at both production facilities and the temporary shut-in of PF-1, which involved close to 100,000 working hours of activity. We were pleased to further extend our record of Lost Time Incident free days to over two years in January 2025 and have been currently operating without an LTI for over 790 days as at 18 March 2025.
2024 gross average production of 40,689 bopd was almost double 2023’s performance of 21,891 bopd as we returned to a full year of sales after the extended shut-in of the Shaikan Field in Q2 2023 due to the suspension of Kurdistan crude exports. After a slow start in Q1 2024, during which the local market was developing to absorb increasing supply from producers in the region, we saw strong underlying demand from the second quarter onwards. This enabled a number of months of high production at levels we had last seen prior to the shut-in of the ITP, with September 2024 production of 48,458 bopd our best month on record.
Local market demand was tempered by temporary disruptions to truck availability during regional holidays, in particular the two Eid celebrations in April and June 2024, and temporary road closures related to the Kurdistan regional elections in October 2024. Production was also reduced as expected during the planned shutdown of PF-1 in November 2024 as we installed safety upgrades and carried out maintenance.
Local sales realised prices averaged $26.8/bbl in 2024. As with production volumes, we saw lower prices in Q1 2024 which then improved and stabilised in the second half of the year. Prices have averaged between $27-$29/bbl in 2025 year to date, as at 18 March 2025.
Our ability to meet local market demand was supported by the execution of a disciplined work programme focused on maintaining and enhancing the production capacity of the Shaikan Field whilst preserving the future value of the field. The successful completion of safety upgrades and maintenance at PF-1 have improved the safety and reliability of the plant, while production optimisation expenditures on existing wells enabled us to offset field declines in the year. The Shaikan Field continues to perform extremely well after over ten years of operations and over 135 million barrels of production.
Higher production and the achievement of an average monthly capex and cost run rate below $7 million, in line with guidance, enabled us to generate $65.4 million of free cash flow. In line with our commitment to return excess cash to shareholders, we distributed $45 million of dividends and share buybacks in the year, an excellent outcome after we had been forced to suspend our ordinary dividend policy in 2023 due to the suspension of exports.
Shaikan Field estimated reserves The Company estimates gross 2P reserves of 443 MMstb as at 31 December 2024, reflecting our year-end 2023 internal estimate of 458 MMstb reduced by gross production of 15 MMstb in 2024.
We have estimated 2P reserves based on a number of modelling assumptions, including a return to development drilling and the expansion of our production facilities from 2026. A return to field development continues to be predicated on the restart of exports and establishment of a stable commercial and payments environment. This would also likely be the point at which we would review the commissioning of an updated Competent Person’s Report (“CPR”), including a comprehensive independent assessment of 1P and 2P reserves and 2C resources. Our last independent CPR was prepared by ERC Equipoise (“ERCE”) as at 31 December 2022.
2025 outlook Gross production has averaged c.46,400 bopd in the year to date (1 January to 18 March 2025), supported by continued strong local sales demand, enabling us to reiterate our gross average production guidance of 40,000 to 45,000 bopd. Our full-year guidance is contingent on stable demand at current levels and a number of other assumptions, including estimated field declines of around 6-10%, the expected impact on production from the planned PF-2 shutdown later in the year and the estimated reduction in truck availability during regional holidays. Should we see any unforeseen disruptions in the local market or the restart of exports, we expect to review the guidance.
We remain focused on balancing capital and cost discipline while maintaining safe and reliable production capacity. We are executing a similar work programme to 2024, with estimated net capital expenditures of $25-$30 million in 2025. The increase relative to 2024 is driven by incremental expenditures on production optimisation, accounting for $5-$10 million of the guidance, as we target quick payback, low-cost and efficient interventions on existing wells to offset declines. Around $20 million is expected to be spent on replicating the 2024 PF-1 safety upgrades and maintenance at PF-2, currently scheduled for Q4 2025 and requiring the shut-in of the facility for approximately three weeks.
In addition to our existing budget, we are actively exploring additional plant initiatives to enhance production, including water handling. We have scheduled reviews and expect to take appropriate actions later in 2025 considering the Company’s liquidity position and operating environment at the time.
As we execute against delivering our annual guidance, we continue to actively pursue a solution to restart the export of our crude to international markets via the ITP, with a number of recent meetings between the IOCs, KRG and FGI, in which Gulf Keystone has played an active role. As we approach the two-year anniversary of the ITP’s closure on 25 March 2025, we remain hopeful that we are now nearing a solution.
We continue to believe a return to international exports with the right agreements in place regarding payment surety, receivables repayment and the preservation of our contractual rights would be transformative for the Company, Kurdistan and Iraq, both in unlocking additional revenue from a vital source of global oil supply which is currently selling for significantly discounted prices but also by signalling that Kurdistan and Iraq are open for business and are attractive destinations for foreign investment.
Jon Harris Chief Executive Officer
19 March 2025
Financial review
Key financial highlights
GKP delivered a strong financial performance in 2024, with a full year of robust local sales combined with capital and cost discipline underpinning a return to free cash flow generation and the restart of shareholder distributions. We are pleased to declare, alongside the 2024 full-year results, a $25 million interim dividend, the first semi-annual dividend to be paid under the shareholder distributions framework announced in October 2024. Looking ahead, stable local sales demand and the delivery of our guidance should enable material free cash flow generation in 2025, with significant improvements in cash flow generation to be potentially unlocked through the restart of exports at the current level of net entitlement.
Adjusted EBITDA
Adjusted EBITDA increased 52% to $76.1 million in 2024 (2023: $50.1 million). Higher production more than offset the decline in realised prices related to the transition from exports to discounted local sales and higher operating costs related to a full year of production after the temporary shut-in of the Shaikan Field during Q2 2023.
Gross average production increased 86% to 40,689 bopd (2023: 21,891 bopd) reflecting a full year of local sales in 2024 following the impact of the suspension of pipeline exports in 2023.
Revenue increased 22% to $151.2 million (2023: $123.5m) as the increase in 2024 volumes more than offset the 34% decline in average realised price to $26.8/bbl (2023: $40.9/bbl). Realised prices for local sales remain driven by supply and demand dynamics in the local market, with no direct link to Dated Brent. Prices have averaged between $27-$29/bbl in 2025 year to date, as at 18 March 2025.
The Company continued to exercise strict cost control in 2024 while maintaining and enhancing the production capacity of the Shaikan Field. Gross operating costs per barrel decreased 21% to $4.4/bbl (2023: $5.6/bbl) and operating costs increased to $52.4 million (2023: $36.1 million), primarily reflecting higher production but also the higher allocation of staff-related costs to operating expenditure due to the lower level of capital expenditure in the year.
Other G&A expenses were $11.4 million in 2024 (2023: $10.5 million). The increase versus the prior year primarily reflects the reinstatement of performance-based staff bonuses for 2024, compared to a small recognition payment in 2023, and the payment of one-off retention awards. These payments were partly offset by the absence of non-recurring corporate costs incurred in H1 2023. In line with industry practice, all direct Shaikan Field related expenditure, such as Shaikan Field G&A which was immaterial in 2024, is now categorised as either operating or capital expenditure as appropriate.
Share option expense of $4.4 million was 59% lower year-on-year (2023: $10.8 million), principally reflecting the reduced vesting of the 2021 LTIP award in 2024 relative to the vesting of the 2020 LTIP award in 2023.
Cash flows
Revenue receipts, which reflect cash received in the year for the Company’s net entitlement of production sales, were $144.1 million, 32% higher than the previous year (2023: $109.2 million) primarily driven by higher production but also supported by pre-payments for local sales.
Net capital expenditure in 2024 was $18.3 million (2023: $58.2 million), in line with annual guidance and reflecting the Company’s disciplined work programme comprised of safety-critical upgrades at PF-1 and production optimisation expenditures. 2024 expenditures were the lowest since 2017, with the 69% decrease relative to 2023 reflecting the termination of expansion activity following the suspension of Kurdistan exports in March 2023.
Free cash flow generation in 2024 was $65.4 million, compared to a $13.1 million outflow in 2023. Revenues generated by local sales more than covered the Company’s aggregate net capex and costs, which on an average monthly basis were $6.8 million, below the Company’s guidance of c.$7 million. Low-cost production and capital discipline provide significant downside protection even at discounted local sales prices.
The Company continued to engage with the KRG regarding the payment mechanism of the overdue October 2022 to March 2023 invoices. The total owed to GKP amounts to $151.1 million (comprising of $120.4 million cost oil and $30.7 million profit oil net to GKP after capacity building payment (‘CBP’) deduction). The total owed to GKP and MOL (who form together the ‘Shaikan Contractor’ or the ‘Contractor’) amounts to $192.8 million (comprising $150.5 million cost oil and $42.3 million profit oil). The Company continues to expect to recover the invoices in full (see ‘Net entitlement’ section below for further detail).
With improving liquidity and strong local sales demand, on 13 May 2024 the Company announced the launch of a $10 million share buyback programme, which was completed on 23 July 2024. The buyback was supplemented with the payment of two dividends in July and October 2024 respectively, totalling $35 million, increasing completed shareholder distributions in the year to $45 million. A second share buyback programme of up to $10 million was also launched in October 2024, although limited purchases were made due to the subsequent increase in the Company’s share price. In light of this and the announced declaration of a $25 million interim dividend today, the Company has decided not to renew the buyback programme which expired on 20 March 2025.
GKP’s cash balance was $102.3 million as at 31 December 2024 (31 December 2023: $81.7 million) with no outstanding debt. Continued free cash flow generation from local sales in Q1 2025 to date have led to a further increase in the Company’s cash balance to $115 million as at 19 March 2025.
The Group performed a cash flow and liquidity analysis, including the current uncertainty over the timing of the pipeline reopening and settlement of outstanding amounts due from the KRG, and the fact that the outlook for local sales volumes has fluctuated in the past and may be difficult to predict, based on which the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for at least 12 months. Therefore, the going concern basis of accounting is used to prepare the financial statements.
Net entitlement
The Company shares Shaikan Field revenues with its partner, MOL, and the KRG, based on the terms of the Shaikan Production Sharing Contract (‘Shaikan PSC’). GKP and MOL’s revenue entitlement is described as ‘Contractor entitlement’ and GKP’s entitlement alone is described as ‘net’. GKP’s net entitlement includes its share of the recovery of the Company’s investment in the Shaikan Field, comprising capital expenditure and operating costs, through cost oil and a share of the profits through profit oil, less a CBP owed to the KRG.
The unrecovered cost oil balance (or ‘Cost Pool’) and R-factor are used to calculate monthly cost oil and profit oil entitlements, respectively, owed to the Shaikan Contractor from crude oil sales. Unrecovered cost oil owed to the Shaikan Contractor increases with the addition of incurred expenditures deemed recoverable under the Shaikan PSC and is depleted on a cash basis as crude sales are paid. As at 31 December 2024, there was $162.9 million of unrecovered cost oil for the Shaikan Contractor ($130.3 million net to GKP), subject to potential cost audit by the KRG. The R-factor, calculated as cumulative Contractor revenue receipts of $2,417 million divided by cumulative Contractor costs of $1,963 million, was 1.23, resulting in a share in the profit oil for the Contractor of 26.5%.
GKP’s net entitlement of total Shaikan Field sales was 36% in 2024. Looking ahead, the Company expects its net entitlement to remain around 36% in 2025 in a continuing local sales environment. Should exports restart, increases in realised price, cash receipt of payments for international sales and the potential implementation by the KRG of a repayment mechanism for past overdue invoices would accelerate the depletion of the Cost Pool upon receipt of payment. This would shorten the period that the Company’s net entitlement is expected to remain around 36% provided that investment in the Shaikan Field does not increase.
The outlook for the Company’s net entitlement assumes receipt of the cost oil portion of the outstanding October 2022 to March 2023 receivable balance due from the KRG to the Shaikan Contractor, which comprises $150.5 million of the total unrecovered cost oil of $162.9 million as at 31 December 2024 (or on a net basis to GKP, $120.4 million of the unrecovered cost oil of $130.3 million). Recovery of the receivable cost oil is expected to begin in the first half of 2025 with regular payment from either local or export sales. Recovery will in turn lead to a corresponding reduction in the receivable balance due from the KRG, with $30.7 million of profit oil (net to GKP after CBP deduction) expected to be fully repaid by the KRG as part of a repayment mechanism.
Outlook
The Company plans to invest net capital expenditure of $25-$30 million in 2025, which includes $20 million on the implementation of safety upgrades and maintenance at PF-2, currently scheduled to take place in Q4 2025, and $5-$10 million on the Company’s ongoing production optimisation programme. While maintaining a strong focus on capital discipline, the Company continues to explore a range of additional plant initiatives to preserve and enhance production, including water handling.
The Company expects its cost base to remain stable in 2025, with expected operating costs of $50-$55 million and other G&A expenses forecast below $10 million in 2025. Strict cost control combined with capital discipline should enable material free cash flow generation in 2025 provided local sales demand and pricing remain stable.
Gulf Keystone remains committed to returning excess cash to shareholders via dividends and/or share buybacks, subject to the liquidity needs of the business and the operating environment. In October 2024, the Company set out a framework for shareholder distributions to enable investors to better evaluate the prospect of future returns in a local sales environment.
The Board will review the Company’s capacity to declare an interim dividend on a semi-annual basis around the time of the full-year results and half-year results and will consider share buybacks on an opportunistic basis throughout the year. Distribution capacity will be determined with reference to the Company’s operating environment and liquidity needs, typically the next year of capital expenditures and costs but also the potential liquidity required to transition from pre-paid local sales to the restart of exports and the normalisation of KRG payments.
In line with this framework, the Company is pleased to announce the declaration of a $25 million interim dividend. The dividend will be paid on 23 April 2025, based on a record date of 4 April 2025 and ex-dividend date of 3 April 2025. Shareholders will have the option of being paid the dividend in either GBP or USD, with the default currency GBP. The USD and GBP rate per share will be announced ahead of the payment date based on the Company’s latest total issued share capital.
Gabriel Papineau-Legris Chief Financial Officer
19 March 2025
Non-IFRS measures
The Group uses certain measures to assess the financial performance of its business. Some of these measures exclude amounts that are included in, or include amounts that are excluded from, the most directly comparable measure calculated and presented in accordance with International Financial Reporting Standards (“IFRS”), or are calculated using financial measures that are not calculated in accordance with IFRS. As a result, these measures are termed “non‑IFRS measures” and include financial measures such as operating costs and non-financial measures such as gross average production.
The Group uses such measures to measure and monitor operating performance and liquidity, in presentations to the Board and as a basis for strategic planning and forecasting. The Directors believe that these and similar measures are used widely by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity.
The non-IFRS measures may not be comparable to other similarly titled measures used by other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of the Group’s operating results as reported under IFRS. An explanation of the relevance of each of the non-IFRS measures and a description of how they are calculated is set out below. Additionally, a reconciliation of the non-IFRS measures to the most directly comparable measures calculated and presented in accordance with IFRS and a discussion of their limitations is set out below, where applicable. The Group does not regard these non-IFRS measures as a substitute for, or superior to, measures that are equivalent to financial measures that are calculated or presented in accordance with IFRS.
Gross operating costs per barrel Gross operating costs are divided by gross production to arrive at operating costs per barrel.
(1) Gross operating costs equate to operating costs (see note 3 to the consolidated financial statements) adjusted for the Group’s 80% working interest in the Shaikan Field.
Adjusted EBITDA Adjusted EBITDA is a useful indicator of the Group’s profitability, and excludes the impact of the costs noted below.
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.
The Company was debt free at 31 December 2024 and 31 December 2023.
Net capital expenditure Net capital expenditure is the value of the Group’s additions to oil and gas assets excluding the change in value of the decommissioning asset or any asset impairment.
Free cash flow Free cash flow represents the Group’s cash flows before any dividends and share buybacks including related fees.
Consolidated income statement For the year ended 31 December 2024
Consolidated statement of comprehensive income For the year ended 31 December 2024
Consolidated balance sheet As at 31 December 2024
The financial statements were approved by the Board of Directors and authorised for issue on 19 March 2025 and signed on its behalf by:
Jon Harris Chief Executive Officer
Gabriel Papineau-Legris Chief Financial Officer
For the year ended 31 December 2024
Consolidated cash flow statement For the year ended 31 December 2024
Summary of material accounting policies
General information Gulf Keystone Petroleum Limited (the “Company”) is domiciled and incorporated in Bermuda (registered address: c/o Carey Olsen Services Bermuda Limited, 5th Floor, Rosebank Centre, 11 Bermudiana Road, Pembroke, HM08 Bermuda); together with its subsidiaries it forms the “Group”. On 25 March 2014, the Company’s common shares were admitted, with a standard listing, to the Official List of the United Kingdom Listing Authority (“UKLA”) and to trading on the London Stock Exchange’s Main Market for listed securities. On 29th July 2024, new Listing Rules came into effect for the London Stock Exchange. The former categories for Main Market listed companies of Premium and Standard Listed were ceased (GKP being a Standard Listed company up until this point). From that date, GKP moved to the Equity Shares – Transition category. The Company serves as the parent company for the Group, which is engaged in oil and gas exploration, development and production, operating in the Kurdistan Region of Iraq.
The financial information set out in this results announcement does not constitute the Company’s annual report and accounts for the years ended 31 December 2023 or 2024 but is derived from those accounts. The auditors have reported on those accounts; their reports were unqualified and did not draw attention to any matters by way of emphasis without qualifying their report.
Amendments to International Financial Reporting Standards (“IFRS”) that are mandatorily effective for the current year In the current year, the Group has applied a number of amendments to IFRS issued by the International Accounting Standards Board (IASB) that are mandatorily effective for an accounting period that begins on or after 1 January 2024.
The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2024: Classification of Liabilities as Current or Non-Current & Non-current Liabilities with Covenants (Amendments to IAS 1), Lease Liability in a Sale and Leaseback (Amendments to IFRS 16), and Supplier Finance Arrangements (Amendments to IAS 7 and IFRS 7). These standards do not and are not expected to have a material impact on the Company’s results or financials statement disclosures in the current or future reporting periods.
New and revised IFRSs issued but not yet effective At the date of approval of these financial statements, the Group has not applied the following new and revised IFRSs that have been issued but are not yet effective by United Kingdom adopted International Accounting Standards:
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:
An entity is required to apply IFRS 18 for annual reporting periods beginning on or after 1 January 2027, with earlier application permitted. The amendments to IAS 7 and IAS 33, as well as the revised IAS 8 and IFRS 7, become effective when an entity applies IFRS 18. IFRS 18 requires retrospective application with specific transition provisions.
The Directors of the company anticipate that the application of these amendments may have an impact on the Group's consolidated financial statements in future periods.
Statement of compliance The financial statements have been prepared in accordance with United Kingdom adopted International Accounting Standards.
Basis of accounting The financial statements have been prepared using the going concern basis of accounting and under the historical cost basis except for the valuation of hydrocarbon inventory which has been measured at net realisable value and the valuation of certain financial instruments which have been measured at fair value. Equity-settled share-based payments are recognised at fair value at the date of grant and are not subsequently revalued. The principal accounting policies adopted are set out below.
Going concern The Group’s business activities, together with the factors likely to affect its future development, performance and position, are set out in the Chair’s statement, the Chief Executive Officer’s review and the Management of principal risks and uncertainties. The financial position of the Group at the year end and its cash flows and liquidity position are included in the Financial review.
As at 19 March 2025 the Group had $115 million of cash and no debt. The Group continues to closely monitor and manage its liquidity. Cash forecasts are regularly produced and sensitivities are run for different scenarios including, but not limited to, changes in sales volumes, commodity price fluctuations, timing of export pipeline restart, delays to revenue receipts and cost optimisations. The Group remains focused on taking appropriate actions to preserve its liquidity position.
As a result of the closure of the Iraq-Türkiye pipeline (“ITP”) in March 2023, the Group significantly reduced expenditures to preserve liquidity and continues to closely monitor costs with minimal capital investment committed while the pipeline remains closed. Throughout 2024 and up to the date of this report in 2025, due to the stabilising of local sales volumes, the Group has significantly improved its working capital position, including settling all legacy supplier invoices from prior to the suspension of exports, and it was able to distribute $45 million to shareholders in 2024 via buybacks and dividends, with a further $25 million interim dividend declared in March 2025.
Nonetheless, the Group is aware there could be a potential decline in local sales, and potential delays in Kurdistan Regional Government (“KRG”) revenue receipts once the ITP has been reopened.
The key uncertainties of the alternative crude sale methods are summarised below:
The Directors believe an agreement will ultimately be reached to reopen the ITP, and reasonably expect that overdue balances will be paid and receipts from the KRG will return to a more regular basis. However, a reduction in local sales or reopening of the pipeline with a deferral of revenue receipts could result in liquidity pressures within the 12-month going concern period.
The Directors have considered sensitivities, including local sales volumes and potential delays in KRG revenue receipts once the ITP reopens, to assess the impact on the Group’s liquidity position and believe sufficient mitigating actions are available to withstand such impacts within the 12-month going concern period. Specifically, the Directors considered stress tests that included no further local sales or KRG revenue receipts and confirmed that cost reduction opportunities exist to ensure that the Group can continue to discharge its liabilities for a period of at least 12 months.
As explained in note 14, although the Group has recognised current liabilities of around $81 million payable to the KRG, it does not expect these will be cash settled.
Overall, the Group’s forecasts, taking into account the applicable risks, stress test scenarios and potential mitigating actions, show that it has sufficient financial resources for the 12 months from the date of approval of the 2024 annual report and accounts.
Based on the analysis performed, the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for the foreseeable future. Thus, the going concern basis of accounting is used to prepare the annual consolidated financial statements.
Basis of consolidation The consolidated financial statements incorporate the financial statements of the Company and enterprises controlled by the Company (its subsidiaries) made up to 31 December each year. Control is achieved where the Company has the power to govern the financial and operating policies of an investee entity, so as to obtain benefits from its activities.
Joint arrangements The Group is engaged in oil and gas exploration, development and production through unincorporated joint arrangements; these are classified as joint operations in accordance with IFRS 11. The Group accounts for its share of the results and net assets of these joint operations. Where the Group acts as Operator of the joint operation, the gross liabilities and receivables (including amounts due to or from non-operating partners) of the joint operation are included in the Group’s balance sheet.
Sales revenue The recognition of revenue is considered to be a key accounting judgement.
Revenue is earned based on the entitlement mechanism under the terms of the Shaikan Production Sharing Contract (“PSC”). Entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred, and profit oil, which is the mechanism through which profits are shared between the Company, its partner and the KRG. The Company is liable for capacity building payments calculated as a proportion of profit oil entitlement. Entitlement from cost oil and profit oil are reported as revenue, and capacity building payments are included in cost of sales.
For sales to the local market from 19 July 2023 onwards, including all of 2024, the delivery point is the point at which crude oil is loaded into the buyers’ nominated trucks. The consideration is determined by reference to the crude sales agreement, with other fees and royalties due as determined by commercial agreements; revenue is reported net of these deductions.
Prior to the shut-in of the ITP on 25 March 2023, all oil was sold by the Shaikan Contractor (the Company and Kalegran BV, a subsidiary of MOL Hungarian Oil & Gas Plc, (“MOL”)) to the KRG, who in turn resold the oil. The selling price was determined in accordance with the principles of the crude oil lifting agreement. On 19 July 2023, the Shaikan Contractor commenced sales to the local market by restarting trucking operations. The selling price is determined in accordance with crude sales agreements with local customers.
Under IFRS 15: Revenue from contracts with customers, GKP considers that control of crude oil is transferred from the Shaikan Contractor to the KRG or local buyer at the delivery point as defined in the lifting agreement or crude sales agreement; at this point the Shaikan Contractor is due economic benefits which can be reliably measured and are probable to be received.
For sales up to the shut-in of the ITP on 25 March 2023, the delivery point was the export pipeline and the consideration was variable and is dependent upon the monthly average oil market price with deductions for quality and transportation fees, with other fees and royalties due as determined by commercial agreements; revenue was reported net of these deductions.
Effective September 1, 2022, the KRG proposed a new pricing mechanism for crude oil export sales, which continued until 25 March 2023 when the ITP was shut-in. Under the new pricing mechanism, the realised export sales price for a month was based on the average market price realised by the KRG for the Kurdistan blend (“KBT”) sold at Ceyhan, Türkiye, as advised by the KRG. The change in the benchmark market price from dated Brent to KBT has not been agreed and no lifting agreement was in place for oil sales from 1 September 2022 until the ITP shut-in referenced above. Nonetheless, the Shaikan Contractor continued production and the KRG accepted delivery of oil at the delivery points. GKP considers that the control of crude oil was transferred at the delivery points despite no commercial agreement being in place and recognised revenue for the period until 25 March 2023, based on the proposed new pricing terms. A summary of the currently estimated financial impact of the proposed change in pricing mechanism is detailed in note 2 to the consolidated financial statements.
Income tax arising from the Company’s activities under its PSC is settled by the KRG on behalf of the Company. Since the Company is not able to measure the amount of income tax that has been paid on its behalf, the notional income tax amounts have not been included in revenue or in the tax charge.
Finance income Finance income is recognised on an accruals basis, by reference to the principal outstanding and at the effective rate of interest applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset’s net carrying amount on initial recognition.
Intangible assets Intangible assets include computer software and are measured at cost and amortised over their expected useful economic lives of three years.
Property, plant and equipment (“PPE”)
Oil and gas assets Development and production assets Development and production assets are accumulated on a field-by-field basis and represent the costs of acquisition and developing the commercial reserves discovered and bringing them into production, together with the exploration and evaluation expenditure incurred in finding commercial reserves, directly attributable overheads and costs for future restoration and decommissioning. These costs are capitalised as part of PPE and depreciated based on the Group’s depreciation of oil and gas assets policy.
The net book values of producing assets are depreciated generally on a field-by-field basis using the unit of production (“UOP”) basis which uses the ratio of oil and gas production in the period to the remaining commercial reserves plus the production in the period. Costs used in the calculation comprise the net book value of the field and estimated future development expenditures required to produce those reserves.
Commercial reserves are proven and probable (“2P”) reserves which are estimated using standard recognised evaluation techniques. The reserves estimate used in the depreciation, depletion and amortisation (“DD&A”) calculation in 2024 was based on the December 2022 Competent Person’s Report (“CPR”), a reserves report completed by ERC Equipoise as at 31 December 2022; this estimate combined with the Group’s subsequent production and economic modelling formed the basis of the updated estimate used in the year.
Other property, plant and equipment Other property, plant and equipment are principally equipment used in the field which are separately identifiable to development and production assets and typically have a shorter useful economic life. Assets are carried at cost, less any accumulated depreciation and accumulated impairment losses. Costs include purchase price, construction and installation costs.
These assets are expensed on a straight-line basis over their estimated useful lives of three-years from the date they are put in use.
Fixtures and equipment Fixtures and equipment assets are stated at cost less accumulated depreciation and any accumulated impairment losses. These assets are expensed on a straight-line basis over their estimated useful lives of five-years from the date they are available for use.
Impairment of PPE and intangible non-current assets At each balance sheet date, the Group reviews the carrying amounts of its tangible and intangible assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset, or group of assets, is estimated in order to determine the extent of the impairment loss (if any).
For assets which do not generate cash flows that are independent from other assets, the Group estimates the recoverable amount of the cash-generating unit to which the asset belongs.
Recoverable amount is the higher of fair value less costs to sell (“FVLCTS”) and value in use. In assessing FVLCTS and value in use, the estimated future cash flows are discounted to their present value using a post-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.
Any impairment identified is immediately recognised as an expense. Conversely, any reversal of an impairment is immediately recognised as income.
Taxation Tax expense or credit represents the sum of tax currently payable or recoverable and deferred tax.
Tax currently payable or recoverable is based on taxable profit or loss for the year. Current tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities, based on tax rates and laws that are enacted or substantively enacted by the balance sheet date.
As described in the revenue accounting policy section above, it is not possible to calculate the amount of notional tax in relation to any tax liabilities settled on behalf of the Group by the KRG.
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that future taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from the initial recognition of goodwill or from the initial recognition of other assets and liabilities in a transaction that affects neither the taxable profit nor the accounting profit and does not give rise to equal taxable and deductible temporary differences.
The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient future taxable profits will be available to allow all or part assets to be recovered.
Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised based on tax laws and rates that have been enacted or substantively enacted by the balance sheet date. Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also recognised in equity.
Foreign currencies The individual financial statements of each company are presented in the currency of the primary economic environment in which it operates (its functional currency). For the purpose of the consolidated financial statements, the results and the financial position of the Group are expressed in US dollars, which is the presentation currency for the consolidated financial statements. In preparing the financial statements of the individual companies, transactions in currencies other than the entity’s functional currency are recorded at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated at the rates prevailing on the balance sheet date. Non-monetary assets and liabilities carried at fair value that are denominated in foreign currencies are translated at the rates prevailing at the date when the fair value was determined. Gains and losses arising on retranslation are included in the income statement for the year.
On consolidation, the assets and liabilities of the Group’s foreign operations which use functional currencies other than US dollars are translated at exchange rates prevailing on the balance sheet date. Income and expense items are translated at the average exchange rates for the period. Exchange differences arising, if any, are recognised in other comprehensive income and accumulated in equity in the Group’s translation reserve. On the disposal of a foreign operation, such translation differences are reclassified to profit or loss.
Inventories Inventories, except for hydrocarbon inventories, are stated at the lower of cost and net realisable value. Cost comprises direct materials and, where applicable, direct labour costs and those overheads that have been incurred in bringing the inventories to their present location and condition. Cost is calculated using the weighted average cost method. Hydrocarbon inventories are recorded at net realisable value with changes in the value of hydrocarbon inventories being adjusted through cost of sales.
Financial instruments Financial assets and financial liabilities are recognised on the Group’s balance sheet when the Group has become a party to the contractual provisions of the instrument.
Trade receivables Trade receivables are measured at amortised cost using the effective interest method less any impairment.
Cash Cash comprises cash on hand and demand deposits that are not subject to a risk of changes in value other than foreign exchange gain or loss.
Impairment of financial assets The Group recognises a loss allowance for expected credit losses (“ECL”) on trade receivables and contract assets, as well as on financial guarantee contracts. The amount of ECL is updated at each reporting date to reflect changes in credit risk since initial recognition of the respective financial instrument.
The Group considers a counterparty to be in default if it can no longer be reasonably expected to recover receivable amounts at a future date; no counterparties are currently considered to be in default.
The Group recognises lifetime ECL for trade receivables, contract assets and lease receivables. The ECL on these financial assets are estimated based on observed market data and convention, existing market conditions and forward-looking estimates at the end of each reporting period.
For all other financial instruments, the Group recognises lifetime ECL when there has been a significant increase in credit risk since initial recognition. However, if the credit risk on the financial instrument has not increased significantly since initial recognition, the Group measures the loss allowance for that financial instrument at an amount equal to 12-month ECL.
Lifetime ECL represents the ECL that will result from all possible default events over the expected life of a financial instrument; this is known as a stage 2 receivable and GKP’s trade outstanding receivable is classified within this category. In contrast, 12-month ECL represents the portion of lifetime ECL that is expected to result from default events on a financial instrument that are possible within 12 months after the reporting date; this is known as a stage 1 receivable.
Financial liabilities and equity Financial liabilities and equity instruments are classified according to the substance of the contractual arrangements entered into. An equity instrument is any contract that evidences a residual interest in the assets of the Group after deducting all of its liabilities.
Equity instruments Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs, which are charged to share premium.
Trade payables Trade payables are stated at amortised cost.
Provisions Provisions are recognised when the Group has a present obligation as a result of a past event which it is probable will result in an outflow of economic benefits that can be reliably estimated.
Decommissioning provision Provision for decommissioning is recognised in full when there is an obligation to restore the site to its original condition. The amount recognised is the present value of the estimated future expenditure for restoring the sites of drilled wells and related facilities to their original status. A corresponding amount equivalent to the provision is also recognised as part of the cost of the related oil and gas asset. The amount recognised is reassessed each year in accordance with local conditions and requirements. Any change in the present value of the estimated expenditure is dealt with prospectively. The unwinding of the discount is included as a finance cost.
Share-based payments Equity-settled share-based payments to employees are measured at the fair value of the instruments at the grant date. Details regarding the determination of the fair value of equity-settled share-based transactions are set out in note 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 lease liability is initially measured at the present value of the future lease payments from the commencement date of the lease. The lease payments are discounted using the interest rate implicit in the lease or, if not readily determinable, the company specific incremental borrowing rate.
The lease liability is subsequently measured by increasing the carrying amount to reflect interest on the lease liability (using the effective interest method) and by reducing the carrying amount to reflect the lease payments made. The lease liability is recognised in creditors as current or non-current liabilities depending on underlying lease terms.
The right-of-use assets are initially recognised on the balance sheet at cost, which comprises the amount of the initial measurement of the corresponding lease liability, adjusted for any lease payments made at or prior to the commencement date of the lease and any lease incentive received.
For short-term leases (periods less than 12 months) and leases of low value, the Group has opted to recognise lease expense on a straight-line basis.
Critical accounting judgements and key sources of estimation uncertainty In the application of the accounting policies described above, the Group is required to make judgements, estimates and assumptions about the carrying amounts of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and other factors that are considered to be relevant. Actual results may differ from these estimates.
The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of revision and future periods if the revision affects both current and future periods.
Critical judgements in applying the Group’s accounting policies The following are the critical judgements, apart from those involving estimations (which are presented separately below), that the Directors have made in the process of applying the Group’s accounting policies and that have the most significant effect on the amounts recognised in financial statements.
Production sharing contract entitlement: Revenue and capacity building payments The recognition of revenue, particularly the recognition of revenue from pipeline exports, is considered to be a key accounting judgement. The Group began commercial production from the Shaikan Field in July 2013 and historically made sales to both the domestic and export markets. The Group considers that revenue can be reliably measured as it passes the delivery point into the export pipeline or truck, as appropriate. The critical accounting judgement applied in the comparative financial statements for 2023 considered whether it was appropriate to recognise export revenue for deliveries from 1 January to 25 March 2023 based on the proposed new pricing mechanism, notwithstanding that there was no signed lifting agreement for that period and the pricing mechanism. Further details of this judgement are provided in the sales revenue accounting policy above. In making this judgement, consideration was given to the fact that the Group received payment for September 2022 deliveries at an amount that was consistent with the proposed new pricing terms; no further receipts for the period of pipeline exports from 1 October 2022 to 25 March 2023 have been received. No adjustments were made in 2024 in respect of the above as revenue was earned via local sales, with no agreement yet reached in respect of the export period mentioned above.
A summary of the currently estimated financial impact of the proposed change in pricing mechanism is detailed in note 2.
Any future agreements between the Group and the KRG might change the amounts of revenue recognised.
During past PSC negotiations with the Ministry of Natural Resources (“MNR”), it was tentatively agreed that the Shaikan Contractor would provide the KRG a 20% carried working interest in the PSC. This would result in a reduction of GKP’s working interest from 80% to 61.5%. To compensate for such decrease, capacity building payments expense would be reduced to 20% of profit petroleum. While the PSC has not been formally amended, it was agreed that GKP would invoice the KRG for oil sales based on the proposed revised terms from October 2017. The financial statements reflect the proposed revised working interest of 61.5%. Relative to the PSC terms, the proposed revised invoicing terms result in a decrease in both revenue and cost of sales and on a net basis are slightly positive for the Group.
As part of earlier PSC negotiations, on 16 March 2016, GKP signed a bilateral agreement with the MNR (the “Bilateral Agreement”). The Bilateral Agreement included a reduction in the Group’s capacity building payment from 40% to 30% of profit petroleum. Subsequent to signing the Bilateral Agreement, further negotiations resulted in the capacity building payment rate being reduced from 30% to 20%, which has formed the basis for all oil sales invoices to date as noted above. Since PSC negotiations have not been finalised, GKP has included a non-cash payable for the difference between the capacity building rate of 20% and 30%, which is recognised in cost of sales and other payables. See note 14 for further details.
The Group expects to confirm with the MNR whether to proceed with a formal amendment to the PSC to reflect current invoice terms.
Material sources of estimation uncertainty The key assumptions concerning the future, and other key sources of estimation uncertainty at the reporting period that may have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the next financial year, are discussed below.
Expected credit loss (“ECL”) The recoverability of receivables is a key accounting judgement. The difference between the nominal value of receivables and the expected value of receivables after allowing for counterparty default risk is the basis for the ECL. This ECL is offset against current and non-current receivable amounts as appropriate within the balance sheet with the change in the receivable balance during the period recognised in the income statement.
In making this judgement, a weighted average has been applied to modelled receipt profiles, upon which a counterparty default allowance has been applied to derive the ECL. When modelling receipt profiles management have made a number of key estimates that are dependent upon uncertain future events including: the KRG’s deemed credit rating, the export pipeline reopening date, the unrecovered cost pool is depleted on a cash basis as invoices for crude sales are paid which can be recovered through local and export sales, estimated timeline of cost oil and profit oil recoveries via commercial terms which have not yet been agreed with the KRG, future oil price including an estimate of both local and export prices, future oil production, and the probabilities allocated to various scenarios incorporating the aforementioned variables. Management has estimated the KRG’s probability of default based on credit default swap ratings (“CDS”) applicable to sovereign nations with similar characteristics to the KRG. Material sensitivities of the ECL to discrete variables are summarised in note 13.
Decommissioning provision Decommissioning provisions are estimated based upon the obligations and costs to be incurred in accordance with the PSC at the end of field life in 2043. There is uncertainty in the decommissioning estimate due to factors including potential changes to the cost of activities, potential emergence of new techniques or changes to best practice. The Group performed an estimate of the value of obligations and costs to decommission the asset as at 31 December 2023, which was reviewed by ERC Equipoise, an independent third party; this estimate formed the basis of the updated estimate of the current value of obligations and costs at 31 December 2024.
Management have increased these costs by estimated compound interest rates, to future value in 2043, and reduced to present value by an estimated discount rate, there is also uncertainty regarding the inflation and discount rates used. For the carrying amount of the item, see note 15.
Carrying value of producing assets In line with the Group’s accounting policy on impairment, management performs an impairment review of the Group’s oil and gas assets at least annually with reference to indicators as set out in IAS 36 ‘Impairment of Assets’. The Group assesses its group of assets, called a cash-generating unit (“CGU”), for impairment, if events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Where indicators are present, management calculates the recoverable amount using key estimates such as future oil prices, estimated production volumes, the cost of development and production, post-tax discount rates that reflect the current market assessment of the time value of money and risks specific to the asset, commercial reserves and inflation. The key assumptions are subject to change based on market trends and economic conditions. Where the CGU’s recoverable amount is lower than the carrying amount, the CGU is considered impaired and is written down to its recoverable amount.
The Group’s sole CGU at 31 December 2024 was the Shaikan Field with a carrying value, being Oil and Gas assets less capitalised decommissioning provision, of $348.9 million (2023: $408.0 million). The Group performed an impairment indicator evaluation as at 31 December 2024 and concluded that no impairment indicators arose. The key areas of estimation in assessing the potential impairment indicators are as follows:
Notes to the consolidated financial statements
1. Geographical information The Chief Operating Decision Maker, as per the definition in IFRS 8 ‘Operating Segments’, is considered to be the Board of Directors. The Group operates in a single segment, that of oil and gas exploration, development and production, in a single geographical location, the Kurdistan Region of Iraq (“KRI”); 100% (2023: 100%) of the group’s non-current assets, excluding deferred tax assets and other financial assets, are located in the KRI. The financial information of the single segment is materially the same as set out in the consolidated statement of comprehensive income, the consolidated balance sheet, the consolidated statement of changes in equity, the consolidated cash flow statement and these related notes.
2. Revenue
The Group’s accounting policy for revenue recognition is set out in the ‘Summary of material accounting policies’, with revenue recognised upon crude oil passing the delivery points, either being entry into pipeline or delivered into trucks.
Local oil sales (from 19 July 2023 and throughout 2024) In July 2023, GKP began selling oil to local buyers at negotiated prices. The realised price achieved in 2024 was $27/bbl (July to December 2023: $30/bbl). Local buyers are contracted to pay GKP in advance of receipt of oil; such amounts are recognised as deferred income (see note 14) until a customer’s receipt of oil at the delivery point.
Oil sales via export pipeline (from 1 January - 25 March 2023) The International Court of Arbitration in Paris ruled on the long running ITP arbitration case in Iraq’s favour, which led to the shut-in of the ITP on 25 March 2023. Negotiations are ongoing to reopen the pipeline.
From 1 September 2022 until shut-in of the ITP on 25 March 2023 there was no lifting agreement in place between the Shaikan Contractor and the KRG. The KRG proposed a new pricing mechanism based upon the average monthly KBT sales price realised by the KRG at Ceyhan; formerly the pricing mechanism was based upon Dated Brent. The Group has not accepted the proposed contract modification and continued, until suspension of the export pipeline, to invoice the KRG for oil sales based on the pre-1 September 2022 pricing formula. Considering the uncertainty with respect to the variable consideration within the pricing mechanism, the Group has concluded that it is an appropriate judgement to recognise revenue based on the proposed contract modification for the period to the pipeline shutdown on 25 March 2023.
Export sales covering the period from 1 January to 25 March 2023 were based upon the monthly KBT price, the realised price in this period was $51.3/bbl. The revenue impact of using the proposed KBT pricing mechanism instead of Dated Brent for the export sales period in 2023 is estimated to be a reduction of revenue by $12.0 million; taking into account the associated reduction in capacity building payments results in a total reduction of profit after tax for the export sales period in 2023 of $11.4 million.
Information about major customers Customers making up greater than 10% of revenue are as follows:
3. Cost of sales
Capacity building payments from 1 January until 25 March 2023 have been recorded in line with the proposed pricing mechanism (see note 2); any difference between the proposed and final pricing mechanism will be reflected in future periods.
The Group accounting policy for depreciation of oil and gas assets and operational assets, as well as the recognition of capacity building payments, are set out in the Summary of material accounting policies section.
The depreciation charge in 2024 is based upon internal reserves and development cost estimates. The 2023 depreciation charge was derived from the CPR prepared by ERC Equipoise as at 31 December 2022. The increase in charge compared to the corresponding period in 2023 is principally derived from higher production in 2024.
Contract termination, provision against inventory held for sale and loss on disposal of drilling stocks in 2023 relate to non-recurring activities undertaken following the ITP export pipeline suspension in March 2023.
4. Other general and administrative expenses
5. Share option related expense
Under the Long Term Incentive Plan (“LTIP”) schemes, GKP awards share options to employees annually that have a three-year vesting period, the share price at the date of award is a significant determinant of the number of shares issued to employees (see note 21).
In the event the Company pays dividends to shareholders during the vesting period, upon vesting the Company would compensate employees for an amount equivalent to the dividends paid during the vesting period and such amount would be settled at the Company’s discretion with shares or cash. Given the financial challenges following the ITP closure, the Company used its discretion in 2023 to pay the dividend equivalent predominantly in shares to preserve liquidity. The significant decrease in share-based payment expense in 2024 is due to the decrease in shares issued in 2024 versus 2023 as compensation related to dividends paid in the vesting periods of the 2021 LTIP and 2020 LTIP.
6. Staff costs The average number of employees, including Executive directors, and contractors employed by the Group was 411 (2023: 471); the number of full-time equivalents of these workers was 274 (2023: 303).
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
Since redemption of $100m notes on 2 August 2022, the Group has remained debt free.
8. Income tax
The Group is not required to pay taxes in Bermuda on either income or capital gains. The Group has received an undertaking from the Minister of Finance in Bermuda exempting it from any such taxes at least until the year 2035.
In the KRI, the Group is subject to corporate income tax on its income from petroleum operations under the Kurdistan PSC. Under the Shaikan PSC, any corporate income tax arising from petroleum operations will be paid from the KRG’s share of petroleum profits. Due to the uncertainty over the payment mechanism for oil sales in Kurdistan, it has not been possible to measure reliably the taxation due that has been paid on behalf of the Group by the KRG and therefore the notional tax amounts have not been included in revenue or in the tax charge. This is an accounting presentational issue and there is no taxation to be paid.
The annual UK corporation tax rate for the years ended 31 December 2024 and 31 December 2023 was 19% on profits up to £50k tapered to 25% on profits above £250k.
Deferred tax is provided for due to the temporary differences, which give rise to such a balance in jurisdictions subject to income tax. All deferred tax arises in the UK.
9. Earnings per share The calculation of the basic and diluted profit/(loss) per share is based on the following data:
The Group followed the steps specified by IAS 33 in determining whether potential common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
(1) At the reporting date, the Company had 9,134k dilutive (2023: 8,224k antidilutive) ordinary shares relating to outstanding share options. Earnings per share are calculated on the assumption of conversion of all potentially dilutive ordinary shares however, during a period where a company makes a loss, anti-dilutive shares are not included in the loss per share calculation as they would reduce the reported loss per share.
The weighted average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee (“EBT”) of 0.1 million, (2023: 0.2 million).
10. Property, plant and equipment
The net book value of oil and gas assets at 31 December 2024 is comprised of property, plant and equipment relating to the Shaikan block with a carrying value of $385.2 million (2023: $443.4 million).
The additions to the Shaikan asset amounting to $18.3 million during the year included safety critical upgrades at PF-1 and production optimisation expenditures.
The $0.7 million (2023: $8.9 million) decrease in decommissioning asset value relates to a $1.1 million decrease in changes to inflation and discount rates (2023: $13.1 million), offset by an increase of $0.4 million relating to facilities work (2023: $4.2 million).
The DD&A charge of $75.8 million (2023: $39.5 million) on oil and gas assets has been included within cost of sales (see note 3). The depreciation charge of $0.6 million (2023: $0.6 million) on fixtures and equipment and $0.4 million (2023: $0.4 million) on right of use assets has been included in general and administrative expenses (see note 4).
Right of use assets at 31 December 2024 of $1.5 million (2023: $0.4 million) consisted principally of buildings, with a new office lease entered into in 2024.
For details of the key assumptions and judgements underlying the impairment assessment, refer to the “Critical accounting estimates and judgements” section of the Summary of material accounting policies.
11. Group companies Details of the Company’s subsidiaries and joint operations at 31 December 2024 is as follows:
12. Inventories
13. Trade and other receivables Non-current receivables
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
Reconciliation of trade receivables
Gross trade receivables relating to export sales of $171.0 million (2023: $171.0 million) are comprised of invoiced amounts due, based upon KBT pricing, from the KRG for crude oil sales totalling $158.8 million (2023: $158.8 million) related to October 2022 – March 2023 and a share of Shaikan amounts due from the KRG that GKP purchased from MOL amounting to $12.2 million (2023: $12.2 million). Although no legal right of offset exists, the net balance due from the KRG comprises $158.8 million (2023: $158.8 million) included in trade receivables and $7.7 million (2023: $7.7 million) included within current liabilities (see note 14), resulting in a net receivable balance due from the KRG relating to crude oil sales of $151.1 million (2023: $151.1 million).
As detailed in the Sales Revenue accounting policies, entitlement has two components: cost oil, which is the mechanism by which the Company recovers its costs incurred, and profit oil, which is the mechanism through which profits are shared between the Company, its partner and the KRG. The outstanding receivable balance of $151.1 million above, comprises $120.4 million cost oil and $30.7 million profit oil (net of Capacity Building Payment).
While GKP expects to recover the full value of the outstanding invoices and purchased revenue arrears, an ECL of $16.3 million (2023: $24.5 million) was provided against the trade receivables balance in accordance with IFRS 9 ‘Financial Instruments’. During the year, a $8.2 million credit was recognised due to the decrease in the ECL provision (2023: charge of $21.4 million) arising from the earlier repayment profile estimated compared to the prior year. During 2025 the Company expects to begin recovering the cost oil component of the trade receivables balance due from the KRG via the settlement of invoices (inclusive of both cost and profit oil) due from oil sales to local customers as the outstanding cost pool balance declines to a level at or below the trade receivable balance. Following the export pipeline reopening the remaining overdue trade receivables is expected to be recovered from the KRG including both the outstanding cost oil balance at that time and the full profit oil balance referenced above.
As detailed in the Summary of material accounting policies and note 2, the outstanding sales invoices from October 2022 – March 2023 receivable have been recognised based on a proposed pricing mechanism, which GKP has not accepted.
ECL sensitivities
Considering the variables listed within the Summary of material accounting policies, the only variables with a significant impact upon the profit before tax, when varied reasonably, are the estimation of the KRG's credit rating for which no official market data exists and the estimated date of the re-opening of the ITP.
For the purpose of GKP’s ECL calculation, the KRG's deemed CDS was estimated to be 4.88%. An increase of the CDS of 2% would increase the ECL provision by $6.1 million, conversely a decrease of the CDS by 2% would decrease the ECL provision by $6.4 million.
GKP estimates that the re-opening of the ITP will occur in October 2025, should this be delayed by 12 months there would be a $7.5 million increase in the ECL provision.
All other variables listed within the Summary of material accounting policies, when individually reasonably varied, do not have a material impact upon the ECL valuation.
Other receivables Included within Other receivables is an amount of $0.5 million (2023: $0.4 million) being the deposits for leased assets which are receivable after more than one year. There are no receivables from related parties as at 31 December 2024 (2023: nil). No impairments of other receivables have been recognised during the year (2023: nil).
14. Current liabilities Trade and other payables
Trade payables and accrued expenditures principally comprise amounts outstanding for trade purchases and ongoing costs and the Directors consider that carrying amounts approximate fair value. The stabilising of local sale revenues during 2024 enabled the Group to settle all overdue trade payables in the first quarter of 2024.
Amounts due to KRG not expected to be cash settled of $80.9 million (2023: $74.7 million) include:
Overlift is the volumes owed by the Company to the KRG through the lifting of volumes in excess of contractual entitlement in accordance with the PSC. The overlift is valued at the year-end sales price. The overlift was temporary and the KRG lifted the volumes in 2025.
Deferred income
At 31 December 2024, deferred income of $0.7 million (2023: $5.2 million) related to cash advances paid by local oil buyers in advance of lifting oil (See note 2).
Non-current liabilities
15. Provisions
The $0.7 million decrease in new provisions and changes in estimates (2023: $8.9 million decrease) comprises an increase relating to new drilling and facilities work of $0.4 million (2023: $4.2 million), offset by a reduction of $1.1 million (2023: $13.1 million) due to changes in inflation and discount rates. The provision for decommissioning is based on the net present value of the Group’s estimated share of expenditure, inflated at 2.5 % (2023: 2.25%) and discounted at 4.9 % (2023: 4.6%), which may be incurred for the removal and decommissioning of the wells and facilities currently in place and restoration of the sites to their original state. Most expenditures are expected to take place towards the end of the PSC term in 2043.
16. Deferred tax asset The following are the major deferred tax liabilities and assets recognised by the Group and movements thereon during the current and prior reporting periods. The deferred tax assets arise in the United Kingdom.
17. Financial instruments
All financial liabilities, except for non-current lease liabilities (see note 14), are due to be settled within one year and are classified as current liabilities. All financial liabilities are recognised at amortised cost.
Fair values of financial assets and liabilities With the exception of the receivables from the KRG which the Group expects to recover in full (see note 13), the Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value.
The financial assets balance includes a $16.3 million provision against trade receivables (2023: $24.5 million) (see note 13). All financial assets are measured at amortised cost which is materially the same as fair value.
Capital Risk Management The Group manages its capital to ensure that the entities within the Group will be able to continue as going concerns while maximising the return to shareholders through the optimisation of the debt and equity structure. The capital structure of the Group consists of cash, cash equivalents, notes (in previous years) and equity attributable to equity holders of the parent. Equity comprises issued capital, reserves and accumulated losses as disclosed in note 18 and the Consolidated statement of changes in equity.
Capital Structure The Company’s Board of Directors reviews the capital structure on a regular basis and will make adjustments in light of changes in economic conditions. As part of this review, the Board considers the cost of capital and the risks associated with each class of capital.
Material Accounting Policies Details of the material accounting policies and methods adopted, including the criteria for recognition, the basis of measurement and the basis on which income and expenses are recognised, in respect of each class of financial asset, financial liability and equity instrument are disclosed in the Summary of material accounting policies.
Financial Risk Management Objectives The Group’s management monitors and manages the financial risks relating to the operations of the Group. These financial risks include market risk (including commodity price, currency and fair value interest rate risk), credit risk, liquidity risk and cash flow interest rate risk.
As at year end, the Group did not hold any derivative assets to hedge against commodity price declines or any other financial risks. The Group does not use derivative financial instruments for speculative purposes.
The risks are closely reviewed by the Group’s management under the oversight of the Board on a regular basis and, where appropriate, steps are taken to ensure these risks are minimised.
Market risk The Group’s activities expose it primarily to the financial risks of changes in oil prices, foreign currency exchange rates and changes in interest rates in relation to the Group’s cash balances.
There have been no changes to the Group’s exposure to other market risks. The risks are monitored by the Group’s management under the oversight of the Board on a regular basis.
The Group conducts and manages its business predominantly in US dollars, the operating currency of the industry in which it operates. The Group also purchases the operating currencies of the countries in which it operates routinely on the spot market. Cash balances are held in other currencies to meet immediate operating and administrative expenses or to comply with local currency regulations.
At 31 December 2024, a 10% weakening or strengthening of the US dollar against the other currencies in which the Group’s monetary assets and monetary liabilities are denominated would not have a material effect on the Group’s net assets or profit.
Interest rate risk management The Group’s policy on interest rate management is agreed at the Board level and is reviewed on an ongoing basis. The current policy is to maintain a certain amount of funds in the form of cash for short-term liabilities and have the rest on short-term deposits to maximise returns and accessibility.
Based on the exposure to interest rates for cash at the balance sheet date, a 0.5% increase or decrease in interest rates would not have a material impact on the Group’s profit.
Credit risk management Credit risk refers to the risk that a counterparty will default on its contractual obligations resulting in financial loss to the Group. As at 31 December 2024, the maximum exposure to credit risk from a trade receivable outstanding from one customer is $171.0 million (2023: $171.0 million). Although the Group is confident in the recovery of the trade receivables balance, a provision of $16.3 million (2023: $24.5 million) was recognised against the trade receivables balance.
The credit risk on liquid funds is limited because the counterparties for a significant portion of the cash at the balance sheet date are banks with investment grade credit ratings assigned by international credit-rating agencies.
Liquidity risk management Ultimate responsibility for liquidity risk management rests with the Group’s management under the oversight of the Board of Directors. It is the Group’s policy to finance its business by means of internally generated funds, external share capital and debt. The Group seeks to raise further funding as and when required.
18. Share capital
At 31 December 2024, a total of 0.1 million common shares at $1 each were held by the EBT (2023: 0.2 million at $1 each). These common shares were included within reserves.
Rights attached to share capital The holders of the common shares have the following rights (subject to the other provisions of the Byelaws):
19. Cash flow reconciliation
Reconciliation of property, plant and equipment additions to cash flows from purchase of property, plant and equipment:
20. Commitments Exploration and development commitments
Additions to property, plant and equipment are generally funded with the cash flow generated from the Shaikan Field. As at 31 December 2024, gross capital commitments in relation to the Shaikan Field were estimated to be $9.2 million (2023: $2.2 million).
21. Share-based payments
The share options charge of $3.5 million (2023: $9.6 million) is comprised of $3.2 million (2023: $9.1 million) related to the LTIP plan and $0.3 million (2023: $0.6 million) related to the deferred bonus plan. See note 5 for other share option related expenses charged to the consolidated income statement.
Long Term Incentive Plan
The Gulf Keystone Petroleum 2014 LTIP is designed to reward members of staff through the grant of share options at a zero-exercise price, that vest three-years after grant, subject to the fulfilment of specified performance conditions. These performance conditions are 50% Total Shareholder Return (“TSR”) over the vesting period and 50% of the Group’s TSR relative to a bespoke group of comparators over the vesting period.
The weighted average share price at the date of exercise for share options exercised during the year was £1.48 (2023: £1.17).
The inputs into the calculation of fair values of the share options granted during the year are as follows:
The options outstanding at 31 December 2024 had a weighted average remaining contractual life of two years (2023: two years).
The aggregate of the estimated fair value of options granted in 2024 is $4.6 million (2023 $4.6 million).
Deferred Bonus Plan
At the Company's AGM in June 2019, shareholders approved the Deferred Bonus Plan. This provides for 30% of the annual bonus attributable to executive directors to be paid in the form of nil cost options that can be exercised any time after the three-year vesting period. There are no performance conditions other than the executive director must continue to be employed for this period (subject to certain limited exceptions).
There were no options exercised during the year under the Deferred Bonus Plan (2023: the weighted average share price at the date of exercise for share options exercised was £1.37).
During the year no options were granted to employees under the Deferred Bonus Plan (2023: 177,832 options granted).
The options outstanding at 31 December 2024 had a weighted average remaining contractual life of one year (2023: two years).
22. Dividends During 2024, a total of $35 million dividends (16.048 US cents per Common Share), being interim dividends, were declared and paid to shareholders. In 2023, a total of $25 million dividends (11.561 US cents per Common Share).
An interim dividend of $25 million was declared in March 2025.
23. Related party transactions The Company has a related party relationship with its subsidiaries and in the ordinary course of business, enters into various sales, purchase and service transactions with joint operations in which the Company has a material interest. These transactions are under terms that are no less favourable to the Group than those arranged with third parties.
Remuneration of Directors and Officers
The Directors and Officers who served during the year ended 31 December 2024 were as follows:
M Angle – Chairman (deceased September 2024) D Thomas – Non-Executive Director became Deputy Chair June 2023, became Interim Chair September 2024 and became Chair October 2024 J Balkany – Non-Executive Director M Daryabegui – Non-Executive Director (appointed October 2024) C Krajicek – Non-Executive Director (appointed October 2024) W Mwaura – Non-Executive Director K Wood – Non-Executive Director (resigned June 2024) J Harris – Chief Executive Officer and Executive Director G Papineau-Legris – Chief Commercial Officer appointed as Chief Financial Officer and Executive Director (effective June 2024) I Weatherdon – Chief Financial Officer and Executive Director (resigned June 2024) C Kinahan – Chief Human Resources Officer J Hulme – Chief Operating Officer A Robinson – Chief Legal Officer and Company Secretary
The remuneration of the Directors and Officers who are considered to be key management personnel is set out below in aggregate for each of the categories specified in IAS 24 Related Party Disclosures.
The values below are calculated in accordance with IAS 19 and IFRS 2.
Further information about the remuneration of individual Directors is provided in the Directors’ Emoluments section of the Remuneration Committee report.
24. Contingent Liabilities The Group has a contingent liability of $27.3 million (2023: $27.3 million) in relation to the proceeds from the sale of test production in the period prior to the approval of the original Shaikan Field Development Plan (“FDP”) in June 2013. The Shaikan PSC does not appear to address expressly any party’s rights to this pre-FDP petroleum. The sales were made based on sales contracts with domestic offtakers which were approved by the KRG. The Group believes that the receipts from these sales of pre-FDP petroleum are for the account of the Contractor, rather than the KRG and accordingly recorded them as test revenue in prior years. However, the KRG has requested a repayment of these amounts and the Group is involved in negotiations to resolve this matter. The Group has received external legal advice and continues to maintain that pre-FDP petroleum receipts are for the account of the Contractor. This contingent liability forms part of the Shaikan PSC amendment negotiations and it is likely that it will be resolved as part of those negotiations.
Dissemination of a Regulatory Announcement, transmitted by EQS Group. The issuer is solely responsible for the content of this announcement. |
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| ISIN: | BMG4209G2077 |
| Category Code: | MSCM |
| TIDM: | GKP |
| LEI Code: | 213800QTAQOSSTNTPO15 |
| Sequence No.: | 379576 |
| EQS News ID: | 2103402 |
| End of Announcement | EQS News Service |
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