DJ 2024 Full Year Results Announcement
Gulf Keystone Petroleum Ltd (GKP)
2024 Full Year Results Announcement
20-March-2025 / 07:00 GMT/BST
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20 March 2025
Gulf Keystone Petroleum Ltd. (LSE: GKP)
("Gulf Keystone", "GKP", "the Group" or "the Company")
2024 Full Year Results Announcement
USD25 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 USD25 million interim dividend as we reiterate our 2025 operational and financial
guidance. We remain focused on facilitating a solution to restart oil exports as we continue to seek fair and
transparent agreements regarding payment surety, the repayment of receivables and the preservation of current contract
economics."
Highlights to 31 December 2024 and post reporting period
Operational
-- Zero Lost Time or Recordable incidents in 2024, well below the relevant Kurdistan and international peer
benchmarks, with safety track record extended to over 790 LTI-free days as at 18 March 2025
-- 2024 gross average production of 40,689 bopd, an 86% increase versus the prior year (2023: 21,891 bopd)
- Reflects a full year of local sales in 2024 following the impact of the suspension of pipeline
exports in March 2023
- Despite temporary disruptions to truck availability during regional holidays and elections and the
impact of the planned PF-1 shutdown in November 2024, strong local market demand from Q2 2024 onwards enabled
the return to production at full capacity in several months
- Average realised price for 2024 sales of USD26.8/bbl, with prices stabilising in a range of c.USD27-USD28/
bbl in H2 2024
-- 2025 year to date (to 18 March 2025) gross average production of c.46,400 bopd:
- Continued strong local market demand, with realised prices averaging between USD27-USD29/bbl
Shaikan Field estimated reserves
-- The Company estimates gross 2P reserves of 443 MMstb as at 31 December 2024, reflecting the Company's
year end 2023 internal estimate of 458 MMstb reduced by gross production of 15 MMstb in 2024
Financial
-- Strong financial performance, with a full year of robust local sales combined with capital and cost
discipline underpinning a return to free cash flow generation and the restart of shareholder distributions
-- Adjusted EBITDA increased 52% to USD76.1 million in 2024 (2023: USD50.1 million) as higher production more
than offset the decline in realised prices related to the transition from exports to discounted local sales
- Revenue increased 22% to USD151.2 million (2023: USD123.5m) as the increase in 2024 volumes more than
offset the 34% decline in average realised price to USD26.8/bbl (2023: USD40.9/bbl)
- Gross operating costs per barrel decreased 21% to USD4.4/bbl (2023: USD5.6/bbl), primarily reflecting
higher production and a continued focus on efficient operations
-- Net capital expenditure of USD18.3 million (2023: USD58.2 million), reflecting the Company's disciplined work
programme comprised of safety critical upgrades at PF-1 and production optimisation expenditures
-- 2024 monthly average net capital expenditure, operating costs and other G&A of USD6.8 million, below the
Company's guidance of c.USD7 million
-- Free cash flow generation of USD65.4 million, relative to a USD13.1 million outflow in 2023, funding the
restart of shareholder distributions and preservation of a robust, debt-free balance sheet:
- USD45 million of shareholder distributions in 2024 consisting of USD35 million of dividends and USD10
million of share purchases completed under the buyback programme launched in May 2024
- 2024 year-end cash balance of USD102 million (31 December 2023: USD82 million)
- Cash balance as at 19 March 2025 of USD115 million
Outlook
-- 2025 operational and financial guidance reiterated:
- Gross average production of 40,000 - 45,000 bopd:
- Subject to local market demand remaining at current strong levels
- Continues to reflect assumptions regarding the planned PF-2 shut-in, truck availability during
regional holidays and field declines
- Should there be any significant unforeseen disruptions to demand or the restart of pipeline
exports, the Company will update its production expectations as appropriate
- Net capital expenditure of USD25-USD30 million:
- c.USD20 million: Safety and maintenance upgrades at PF-2, scheduled for Q4 2025 and expected to
require the shut-in of the facility for c.3 weeks, similar to PF-1 in 2024
- USD5-USD10 million: Production optimisation programme consisting of low cost, quick payback well
interventions
- Continue to explore range of additional plant initiatives to enhance production, including water
handling, with planned reviews later in 2025 based on the Company's liquidity position and operating
environment
- Operating costs of USD50-USD55 million and other G&A expenses below USD10 million
-- USD25 million interim dividend announced today, the first semi-annual dividend to be paid under the
shareholder distributions framework announced on 8 October 2024
- The dividend will be paid on 23 April 2025, based on a record date of 4 April 2025 and ex-dividend
date of 3 April 2025
- USD and GBP rate per share to be announced ahead of the payment date based on the Company's latest
total issued share capital
-- The recent share buyback programme of up to USD10 million, expiring 20 March 2025, has not been renewed in
light of the interim dividend declaration and the strength of the Company's share price
- Share buybacks will continue to be considered opportunistically by the Board
-- The Company continues to proactively engage with government stakeholders regarding a solution to enable
the restart of Kurdistan crude exports through the Iraq-Türkiye Pipeline:
- Several recent meetings held with the Kurdistan Regional Government and Federal Government of Iraq
- The Company remains ready to resume oil exports provided we have agreements on payment surety for
future oil exports, the repayment of outstanding receivables and the preservation of current contract economics
Investor & analyst presentations
GKP's management team will be hosting a presentation for analysts and investors at 10:00am (GMT) today via live audio
webcast:
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:
Gulf Keystone: +44 (0) 20 7514 1400
Aaron Clark, Head of Investor Relations
& Corporate Communications aclark@gulfkeystone.com
FTI Consulting +44 (0) 20 3727 1000
Ben Brewerton
GKP@fticonsulting.com
Nick Hennis
or visit: www.gulfkeystone.com
Notes to Editors:
Gulf Keystone Petroleum Ltd. (LSE: GKP) is a leading independent operator and producer in the Kurdistan Region of Iraq. Further information on Gulf Keystone is available on its website: www.gulfkeystone.com
Disclaimer
This announcement contains certain forward-looking statements that are subject to the risks and uncertainties associated with the oil & gas exploration and production business. These statements are made by the Company and its Directors in good faith based on the information available to them up to the time of their approval of this announcement but such statements should be treated with caution due to inherent risks and uncertainties, including both economic and business factors and/or factors beyond the Company's control or within the Company's control where, for example, the Company decides on a change of plan or strategy. This announcement has been prepared solely to provide additional information to shareholders to assess the Group's strategies and the potential for those strategies to succeed. This announcement should not be relied on by any other party or for any other purpose.
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 USD10 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 USD35 million of dividends in July and October 2024. The total shareholder distributions completed during the year were USD45 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 USD26.8/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 USD27-USD29/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 USD7 million, in line with guidance, enabled us to generate USD65.4 million of free cash flow. In line with our commitment to return excess cash to shareholders, we distributed USD45 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 USD25-USD30 million in 2025. The increase relative to 2024 is driven by incremental expenditures on production optimisation, accounting for USD5-USD10 million of the guidance, as we target quick payback, low-cost and efficient interventions on existing wells to offset declines. Around USD20 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.
3In addition to our existing budget, we are actively exploring additional plant initiatives to enhance production, including water handling. We have scheduled reviews and expect to take appropriate actions later in 2025 considering the Company's liquidity position and operating environment at the time.
As we execute against delivering our annual guidance, we continue to actively pursue a solution to restart the export of our crude to international markets via the ITP, with a number of recent meetings between the IOCs, KRG and FGI, in which Gulf Keystone has played an active role. As we approach the two-year anniversary of the ITP's closure on 25 March 2025, we remain hopeful that we are now nearing a solution.
We continue to believe a return to international exports with the right agreements in place regarding payment surety, receivables repayment and the preservation of our contractual rights would be transformative for the Company, Kurdistan and Iraq, both in unlocking additional revenue from a vital source of global oil supply which is currently selling for significantly discounted prices but also by signalling that Kurdistan and Iraq are open for business and are attractive destinations for foreign investment.
Jon Harris
Chief Executive Officer
19 March 2025
Financial review
Key financial highlights
Year ended Year ended
31 December 2024 31 December 2023
Gross average production(1) bopd 40,689 21,891
Dated Brent(2) USD/bbl 80.8 82.6
Realised price(1)(3) USD/bbl 26.8 40.9
Discount to Dated Brent USD/bbl 53.9 41.7
Revenue USDm 151.2 123.5
Operating costs USDm 52.4 36.1
Gross operating costs per barrel(1) USD/bbl 4.4 5.6
Other general and administrative expenses USDm 11.4 10.5
Share option expense USDm 4.4 10.8
Adjusted EBITDA(1) USDm 76.1 50.1
Profit/(loss) after tax USDm 7.2 (11.5)
Basic earnings/(loss) per share cents 3.3 (5.3)
Revenue receipts(1) USDm 144.1 109.2
Net capital expenditure(1) USDm 18.3 58.2
Free cash flow(1) USDm 65.4 (13.1)
Shareholder distributions(4) USDm 45 25
Cash and cash equivalents USDm 102.3 81.7 1. Represents either a non-financial or non-IFRS measure which are explained in the summary of non-IFRSmeasures where applicable. 2. Provided as a comparator for realised price. Realised prices for local sales are currently driven bysupply and demand dynamics in the local market, with no direct link to Dated Brent. 3. 2024 realised prices reflect a full year of local sales, 2023 realised prices reflect export sales from 1January to 24 March 2023 and local sales from 19 July to 31 December 2023. 4. 2024: USD35 million of dividends and USD10 million of completed share buybacks; 2023: USD25 million dividend.
GKP delivered a strong financial performance in 2024, with a full year of robust local sales combined with capital and cost discipline underpinning a return to free cash flow generation and the restart of shareholder distributions. We are pleased to declare, alongside the 2024 full-year results, a USD25 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 USD76.1 million in 2024 (2023: USD50.1 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 USD151.2 million (2023: USD123.5m) as the increase in 2024 volumes more than offset the 34% decline in average realised price to USD26.8/bbl (2023: USD40.9/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 USD27-USD29/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 USD4.4/bbl (2023: USD5.6/bbl) and operating costs increased to USD52.4 million (2023: USD36.1 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 USD11.4 million in 2024 (2023: USD10.5 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 USD4.4 million was 59% lower year-on-year (2023: USD10.8 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 USD144.1 million, 32% higher than the previous year (2023: USD109.2 million) primarily driven by higher production but also supported by pre-payments for local sales.
Net capital expenditure in 2024 was USD18.3 million (2023: USD58.2 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 USD65.4 million, compared to a USD13.1 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 USD6.8 million, below the Company's guidance of c.USD7 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 USD151.1 million (comprising of USD120.4 million cost oil and USD30.7 million profit oil net to GKP after capacity building payment ('CBP') deduction). The total owed to GKP and MOL (who form together the 'Shaikan Contractor' or the 'Contractor') amounts to USD192.8 million (comprising USD150.5 million cost oil and USD42.3 million profit oil). The Company continues to expect to recover the invoices in full (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 USD10 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 USD35 million, increasing completed shareholder distributions in the year to USD45 million. A second share buyback programme of up to USD10 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 USD25 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 USD102.3 million as at 31 December 2024 (31 December 2023: USD81.7 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 USD115 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 USD162.9 million of unrecovered cost oil for the Shaikan Contractor (USD130.3 million net to GKP), subject to potential cost audit by the KRG. The R-factor, calculated as cumulative Contractor revenue receipts of USD2,417 million divided by cumulative Contractor costs of USD1,963 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 USD150.5 million of the total unrecovered cost oil of USD162.9 million as at 31 December 2024 (or on a net basis to GKP, USD120.4 million of the unrecovered cost oil of USD130.3 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 USD30.7 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 USD25-USD30 million in 2025, which includes USD20 million on the implementation of safety upgrades and maintenance at PF-2, currently scheduled to take place in Q4 2025, and USD5-USD10 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 USD50-USD55 million and other G&A expenses forecast below USD10 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 USD25 million interim dividend. The dividend will be paid on 23 April 2025, based on a record date of 4 April 2025 and ex-dividend date of 3 April 2025. Shareholders will have the option of being paid the dividend in either GBP or USD, with the default currency GBP. The USD and GBP rate per share will be announced ahead of the payment date based on the Company's latest total issued share capital.
Gabriel Papineau-Legris
Chief Financial Officer
19 March 2025
Non-IFRS measures
The Group uses certain measures to assess the financial performance of its business. Some of these measures exclude amounts that are included in, or include amounts that are excluded from, the most directly comparable measure calculated and presented in accordance with International Financial Reporting Standards ("IFRS"), or are calculated using financial measures that are not calculated in accordance with IFRS. As a result, these measures are termed "non- IFRS measures" and include financial measures such as operating costs and non-financial measures such as gross average production.
The Group uses such measures to measure and monitor operating performance and liquidity, in presentations to the Board and as a basis for strategic planning and forecasting. The Directors believe that these and similar measures are used widely by certain investors, securities analysts and other interested parties as supplemental measures of performance and liquidity.
The non-IFRS measures may not be comparable to other similarly titled measures used by other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of the Group's operating results as reported under IFRS. An explanation of the relevance of each of the non-IFRS measures and a description of how they are calculated is set out below. Additionally, a reconciliation of the non-IFRS measures to the most directly comparable measures calculated and presented in accordance with IFRS and a discussion of their limitations is set out below, where applicable. The Group does not regard these non-IFRS measures as a substitute for, or superior to, measures that are equivalent to financial measures that are calculated or presented in accordance with IFRS.
Gross operating costs per barrel
Gross operating costs are divided by gross production to arrive at operating costs per barrel.
2024 2023 Gross production (MMbbls) 14.9 8.0 Gross operating costs (USD million)(1) 65.5 45.1 Gross operating costs per barrel (USD per bbl) 4.4 5.6
(1) Gross operating costs equate to operating costs (see note 3 to the consolidated financial statements) adjusted for the Group's 80% working interest in the Shaikan Field.
Adjusted EBITDA
Adjusted EBITDA is a useful indicator of the Group's profitability, and excludes the impact of the costs noted below.
2024 2023
USD million USD million
Profit/(loss) after tax 7.2 (11.5)
Finance costs 1.7 1.8
Finance income (4.1) (3.8)
Tax charge 0.7 0.1
Depreciation of oil and gas assets 75.8 39.5
Depreciation of other PPE assets and amortisation of intangibles 3.0 2.6
(Decrease)/increase of expected credit loss provision on trade receivables (8.2) 21.4
Adjusted EBITDA 76.1 50.1
Net cash
Net cash is a useful indicator of the Group's indebtedness and financial flexibility indicating the level of cash and cash equivalents less cash borrowings within the Group.
2024 2023
USD million USD million
Cash 102.3 81.7
Borrowings - -
Net cash 102.3 81.7
The Company was debt free at 31 December 2024 and 31 December 2023.
Net capital expenditure
Net capital expenditure is the value of the Group's additions to oil and gas assets excluding the change in value of the decommissioning asset or any asset impairment.
2024 2023
USD million USD million
Net capital expenditure (see note 10 to the consolidated financial statements) 18.3 58.2
Free cash flow
Free cash flow represents the Group's cash flows before any dividends and share buybacks including related fees.
2024 2023
USD million USD million
Net cash generated from operating activities 93.5 51.3
Net cash used in investing activities (27.6) (63.9)
Payment of leases (0.5) (0.5)
Free cash flow 65.4 (13.1)
Consolidated income statement
For the year ended 31 December 2024
Notes 2024 2023
USD'000 USD'000
Revenue 2 151,208 123,514
Cost of sales 3 (138,866) (93,953)
Decrease/(increase) of expected credit loss provision on trade receivables 13 8,191 (21,378)
Gross profit 20,533 8,183
Other general and administrative expenses 4 (11,412) (10,466)
Share option related expenses 5 (4,419) (10,760)
Profit/(loss) from operations 4,702 (13,043)
Finance income 7 4,116 3,803
Finance costs 7 (1,676) (1,765)
Foreign exchange gain/(loss) 724 (384)
Profit/(loss) before tax 7,866 (11,389)
Tax charge 8 (708) (111)
Profit/(loss) after tax for the year 7,158 (11,500)
Profit/(loss) per share (cents)
Basic 9 3.26 (5.28)
Diluted 9 3.13 (5.28)
Consolidated statement of comprehensive income
For the year ended 31 December 2024
2024 2023
USD'000 USD'000
Profit/(loss) after tax for the year 7,158 (11,500)
Items that may be reclassified to the income statement in subsequent periods:
Exchange (loss)/gain on translation of foreign operations (517) 952
Total comprehensive income/(loss) for the year 6,641 (10,548)
Consolidated balance sheet
As at 31 December 2024
Notes 31 December 2024 31 December 2023
USD'000 USD'000
Non-current assets
Trade receivables 13 138,175 140,218
Intangible assets 1,255 2,813
Property, plant and equipment 10 388,450 445,842
Deferred tax asset 16 825 1,545
528,705 590,418
Current assets
Inventories 12 9,852 9,901
Trade and other receivables 13 26,779 15,118
Cash 102,346 81,709
138,977 106,728
Total assets 667,682 697,146
Current liabilities
Trade and other payables 14 (117,277) (109,394)
Deferred income 14 (716) (5,164)
(117,993) (114,558)
Non-current liabilities
Trade and other payables 14 (1,112) (39)
Provisions 15 (36,247) (35,312)
(37,359) (35,351)
Total liabilities (155,352) (149,909)
Net assets 512,330 547,237
Equity
Share capital 18 217,005 222,443
Share premium 18 463,985 503,312
Exchange translation reserve (4,283) (3,766)
Accumulated losses (164,377) (174,752)
Total equity 512,330 547,237
The financial statements were approved by the Board of Directors and authorised for issue on 19 March 2025 and signed on its behalf by:
Jon Harris
Chief Executive Officer
Gabriel Papineau-Legris
Chief Financial Officer Consolidated statement of changes in equity
For the year ended 31 December 2024
Attributable to equity holders of the Company
Share Exchange translation Accumulated Total
Share reserve losses
premium equity
capital
Notes USD'000 USD'000 USD'000 USD'000 USD'000
Balance at 1 January 2023 216,247 528,125 (4,718) (166,729) 572,925
Loss after tax for the year - - - (11,500) (11,500)
Exchange difference on translation of foreign - - 952 - 952
operations
Total comprehensive loss for the year - - 952 (11,500) (10,548)
Dividends paid 22 - (24,813) - - (24,813)
Employee share schemes 21 - - - 9,673 9,673
Share issues 18 6,196 - - (6,196) -
Balance at 31 December 2023 222,443 503,312 (3,766) (174,752) 547,237
Profit after tax for the year - - - 7,158 7,158
Exchange difference on translation of foreign - - (517) - (517)
operations
Total comprehensive profit for the year - - (517) 7,158 6,641
Dividends paid 22 - (34,933) - - (34,933)
Employee share schemes 21 - - - 3,472 3,472
Share issues 18 255 - - (255) -
Repurchase of ordinary shares 18 (5,693) (4,394) - - (10,087)
Balance at 31 December 2024 217,005 463,985 (4,283) (164,377) 512,330
Consolidated cash flow statement
For the year ended 31 December 2024
2024 2023
Notes
USD'000 USD'000
Operating activities
Cash generated from operations 19 89,427 47,520
Interest received 7 4,116 3,803
Net cash generated from operating activities 93,543 51,323
Investing activities
Purchase of intangible assets (420) -
Purchase of property, plant and equipment 19 (27,178) (65,386)
Sale of drilling stock - 1,449
Net cash used in investing activities (27,598) (63,937)
Financing activities
Payment of dividends 22 (34,933) (24,813)
Share buyback (10,087) -
Payment of leases (452) (503)
Net cash used in financing activities (45,472) (25,316)
Net increase/(decrease) in cash 20,473 (37,930)
Cash at beginning of year 81,709 119,456
Effect of foreign exchange rate changes 164 183
Cash at end of the year being bank balances and cash on hand 102,346 81,709
Summary of material accounting policies
General information
Gulf Keystone Petroleum Limited (the "Company") is domiciled and incorporated in Bermuda (registered address: c/o Carey Olsen Services Bermuda Limited, 5th Floor, Rosebank Centre, 11 Bermudiana Road, Pembroke, HM08 Bermuda); together with its subsidiaries it forms the "Group". On 25 March 2014, the Company's common shares were admitted, with a standard listing, to the Official List of the United Kingdom Listing Authority ("UKLA") and to trading on the London Stock Exchange's Main Market for listed securities. On 29th July 2024, new Listing Rules came into effect for the London Stock Exchange. The former categories for Main Market listed companies of Premium and Standard Listed were ceased (GKP being a Standard Listed company up until this point). From that date, GKP moved to the Equity Shares - Transition category. The Company serves as the parent company for the Group, which is engaged in oil and gas exploration, development and production, operating in the Kurdistan Region of Iraq.
The financial information set out in this results announcement does not constitute the Company's annual report and accounts for the years ended 31 December 2023 or 2024 but is derived from those accounts. The auditors have reported on those accounts; their reports were unqualified and did not draw attention to any matters by way of emphasis without qualifying their report.
Amendments to International Financial Reporting Standards ("IFRS") that are mandatorily effective for the current year
In the current year, the Group has applied a number of amendments to IFRS issued by the International Accounting Standards Board (IASB) that are mandatorily effective for an accounting period that begins on or after 1 January 2024.
The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2024: Classification of Liabilities as Current or Non-Current & Non-current Liabilities with Covenants (Amendments to IAS 1), Lease Liability in a Sale and Leaseback (Amendments to IFRS 16), and Supplier Finance Arrangements (Amendments to IAS 7 and IFRS 7). These standards do not and are not expected to have a material impact on the Company's results or financials statement disclosures in the current or future reporting periods.
New and revised IFRSs issued but not yet effective
At the date of approval of these financial statements, the Group has not applied the following new and revised IFRSs that have been issued but are not yet effective by United Kingdom adopted International Accounting Standards:
IFRS S1 General Requirements for Disclosure of Sustainability-related Financial Information
IFRS S2 Climate-related Disclosures
IFRS 19 Subsidiaries without Public Accountability: Disclosures
Amendments IFRS 9 and Classification and measurement of financial instruments; Contracts Referencing Nature-dependent
IFRS 7 Electricity
Amendments to IAS 21 Lack of Exchangeability: when a currency is exchangeable and how to determine the exchange rate
when it is not.
Amendments to the SASB Amendments to the SASB standards to enhance their international applicability without
standards substantially altering industries, topics or metrics
The directors do not expect that the adoption of the Standards listed above will have a material impact on the financial statements of the Group in future periods.
IFRS 18 replaces IAS 1, carrying forward many of the requirements in IAS 1 unchanged and complementing them with new requirements. In addition, some IAS 1 paragraphs have been moved to IAS 8 and IFRS 7. Furthermore, the IASB has made minor amendments to IAS 7 and IAS 33 Earnings per Share.
IFRS 18 introduces new requirements to:
-- present specified categories and defined subtotals in the statement of profit or loss
-- provide disclosures on management-defined performance measures (MPMs) in the notes to the financialstatements
-- improve aggregation and disaggregation
An entity is required to apply IFRS 18 for annual reporting periods beginning on or after 1 January 2027, with earlier application permitted. The amendments to IAS 7 and IAS 33, as well as the revised IAS 8 and IFRS 7, become effective when an entity applies IFRS 18. IFRS 18 requires retrospective application with specific transition provisions.
The Directors of the company anticipate that the application of these amendments may have an impact on the Group's consolidated financial statements in future periods.
Statement of compliance
The financial statements have been prepared in accordance with United Kingdom adopted International Accounting Standards.
Basis of accounting
The financial statements have been prepared using the going concern basis of accounting and under the historical cost basis except for the valuation of hydrocarbon inventory which has been measured at net realisable value and the valuation of certain financial instruments which have been measured at fair value. Equity-settled share-based payments are recognised at fair value at the date of grant and are not subsequently revalued. The principal accounting policies adopted are set out below.
Going concern
The Group's business activities, together with the factors likely to affect its future development, performance and position, are set out in the Chair's statement, the Chief Executive Officer's review and the Management of principal risks and uncertainties. The financial position of the Group at the year end and its cash flows and liquidity position are included in the Financial review.
As at 19 March 2025 the Group had USD115 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 USD45 million to shareholders in 2024 via buybacks and dividends, with a further USD25 million interim dividend declared in March 2025.
Nonetheless, the Group is aware there could be a potential decline in local sales, and potential delays in Kurdistan Regional Government ("KRG") revenue receipts once the ITP has been reopened.
The key uncertainties of the alternative crude sale methods are summarised below:
-- Local sales: the Group continues local sales with payments from buyers required in advance followingextensive due diligence. During 2024 the Group received over USD144 million related to local sales. However, localsales volumes (average c.40,700 bopd in 2024) and prices have fluctuated in the past and may be difficult topredict; and
-- Export sales: In February 2025, the Iraqi Parliament approved an amendment to Article 12 of the Iraqi2023-2025 Budget Law regarding the compensation for Kurdistan's oil production and transportation costs,potentially facilitating the resumption of Kurdistan's oil exports. Whilst the approval of the amendment is a keystep towards the resumption of Kurdistan oil exports, a number of key details remain outstanding regarding paymentsurety for future oil exports, the repayment of outstanding receivables and the preservation of current contracteconomics. As such, the timing of the reopening of the ITP and payment mechanism remain uncertain.
The Directors believe an agreement will ultimately be reached to reopen the ITP, and reasonably expect that overdue balances will be paid and receipts from the KRG will return to a more regular basis. However, a reduction in local sales or reopening of the pipeline with a deferral of revenue receipts could result in liquidity pressures within the 12-month going concern period.
The Directors have considered sensitivities, including local sales volumes and potential delays in KRG revenue receipts once the ITP reopens, to assess the impact on the Group's liquidity position and believe sufficient mitigating actions are available to withstand such impacts within the 12-month going concern period. Specifically, the Directors considered stress tests that included no further local sales or KRG revenue receipts and confirmed that cost reduction opportunities exist to ensure that the Group can continue to discharge its liabilities for a period of at least 12 months.
As explained in note 14, although the Group has recognised current liabilities of around USD81 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 ?nancial asset to that asset's net carrying amount on initial recognition.
Intangible assets
Intangible assets include computer software and are measured at cost and amortised over their expected useful economic lives of three years.
Property, plant and equipment ("PPE")
Oil and gas assets
Development and production assets
Development and production assets are accumulated on a field-by-field basis and represent the costs of acquisition and developing the commercial reserves discovered and bringing them into production, together with the exploration and evaluation expenditure incurred in finding commercial reserves, directly attributable overheads and costs for future restoration and decommissioning. These costs are capitalised as part of PPE and depreciated based on the Group's depreciation of oil and gas assets policy.
The net book values of producing assets are depreciated generally on a field-by-field basis using the unit of production ("UOP") basis which uses the ratio of oil and gas production in the period to the remaining commercial reserves plus the production in the period. Costs used in the calculation comprise the net book value of the field and estimated future development expenditures required to produce those reserves.
Commercial reserves are proven and probable ("2P") reserves which are estimated using standard recognised evaluation techniques. The reserves estimate used in the depreciation, depletion and amortisation ("DD&A") calculation in 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 USD348.9 million (2023: USD408.0 million). The Group performed an impairment indicator evaluation as at 31 December 2024 and concluded that no impairment indicators arose. The key areas of estimation in assessing the potential impairment indicators are as follows:
-- While the date of the re-opening of the ITP remains uncertain, management have assessed a re-opening dateof October 2025 as being reasonable. Although the estimated re-opening date is one year later than the base caseassessment at 31 December 2023, management previously performed sensitivities of up to two years with noimpairment, therefore this delay to the projected re-opening was not assessed to be an impairment trigger;
-- The Group's netback oil price applied only to export pipeline sales was based on the Brent forward curveand market participants' consensus, including banks, analysts and independent reserves evaluators, as at 31December 2024 for the period 2025 to 2030 with inflation of 2.50% per annum thereafter, less transportation costsand quality adjustments. Brent consensus prices are as follows
Scenario (USD/bbl - nominal) 2024 2025 2026 2027 2028 2029 2030 31 December 2024 - base case n/a 74.0 72.0 74.0 75.0 73.0 80.0 31 December 2024 - stress case n/a 66.6 64.8 66.6 67.5 65.7 72.0 31 December 2023 - base case 83.0 80.0 77.0 77.0 77.0 80.0 81.8 31 December 2023 - stress case 74.7 72.0 69.3 69.3 69.3 72.0 73.6
-- Management have previously applied sensitivities in reviewing stress case pricing including a 10%reduction from base case pricing to derive a stress case price with no impairment impact. The stress case pricingis noted above;
-- Discount rates are adjusted to reflect risks specific to the Shaikan Field and the Kurdistan Region ofIraq. Management assessed changes to the key variables that could impact discount rate and concluded no change wasnecessary. The post-tax nominal discount rate was estimated to be 16%, unchanged from 31 December 2023;
-- Operating costs and capital expenditure are based on financial budgets and internal management forecasts.Costs assumptions incorporate management experience and expectations, as well as the nature and location of theoperation and the risks associated therewith. There were no indicators that costs will increase in comparison to 31December 2023 impairment assessment;
-- No adverse changes were noted for commercial reserves and production profiles;
-- No changes were noted in the operating environment such as local market conditions, tax or other legal orregulatory changes. Specifically, management considered if there had been any update with respect to the IraqiFederal Supreme Court ruling announced in 2022 and concluded there was no movement in the period which would impactthe impairment analysis; and
-- The Group continues to develop its assessment of the potential impacts of climate change and theassociated risks of the transition to a low-carbon future. Our ambition to reduce scope one per barrel CO2emissions intensity by at least 50% versus the original 2020 baseline of 38 kgCO2e per barrel is dependent on thetiming of sanction and implementation of the Gas Management Plan. The International Energy Agency's ("IEA") mostrecent Announced Pledges Scenario ("APS") and Net Zero Emissions ("NZE") climate scenario oil prices and carbontaxes were used to evaluate the potential impact of the principal climate change transition risks. The APS scenarioassumes that governments will meet, in full and on time, all of the climate-related commitments that they haveannounced, including longer term net zero emissions targets and pledges in Nationally Determined Contributions("NDCs") to reduce national emissions and adapt to the impacts of climate change leading to a global temperaturerise of 1.7°C in 2100. NZE scenario portrays a pathway for the global energy sector to reach net zero CO2 emissionsby 2050 which is consistent with limiting long-term global warming to 1.5 °C with limited overshoot. The estimatedre-opening date is one year later than the base case assessment at 31 December 2023, management previouslyperformed sensitivities of up to two years. There was no impairment under the APS scenario, but a potentialimpairment under the NZE scenario. While the IEA oil price assumptions incorporate carbon prices, the IEA has notdisclosed the assumed average carbon intensity per barrel of production. Therefore, the Group has performed asensitivity to conservatively include IEA carbon pricing on all production which results in no impairment under theAPS scenario, but a potential impairment under the NZE scenario.
Notes to the consolidated financial statements
1. Geographical information
The Chief Operating Decision Maker, as per the definition in IFRS 8 'Operating Segments', is considered to be the Board of Directors. The Group operates in a single segment, that of oil and gas exploration, development and production, in a single geographical location, the Kurdistan Region of Iraq ("KRI"); 100% (2023: 100%) of the group's non-current assets, excluding deferred tax assets and other financial assets, are located in the KRI. The financial information of the single segment is materially the same as set out in the consolidated statement of comprehensive income, the consolidated balance sheet, the consolidated statement of changes in equity, the consolidated cash flow statement and these related notes.
2. Revenue
2024 2023
USD'000 USD'000
Oil sales via export pipeline - 78,955
Local oil sales 151,208 44,559
151,208 123,514
The Group's accounting policy for revenue recognition is set out in the 'Summary of material accounting policies', with revenue recognised upon crude oil passing the delivery points, either being entry into pipeline or delivered into trucks.
Local oil sales (from 19 July 2023 and throughout 2024)
In July 2023, GKP began selling oil to local buyers at negotiated prices. The realised price achieved in 2024 was USD27/bbl (July to December 2023: USD30/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 USD51.3/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 USD12.0 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 USD11.4 million.
Information about major customers
Customers making up greater than 10% of revenue are as follows:
2024 2023 Kurdistan Regional Government 0% 68% Customer A 88% <10% Customer B<10% 11% Customer C<10% 0% Customer D 0% 10% Customer E 0% 10%
3. Cost of sales
2024 2023
USD'000 USD'000
Operating costs 52,435 36,082
Capacity building payments 10,818 8,872
Change in oil inventory value (168) (75)
Depreciation of oil and gas assets and operational assets 75,781 39,470
Contract termination costs - 5,525
Provision against inventory held for sale - 2,627
Loss on disposal of drilling stock - 1,452
138,866 93,953
Capacity building payments from 1 January until 25 March 2023 have been recorded in line with the proposed pricing mechanism (see note 2); any difference between the proposed and final pricing mechanism will be reflected in future periods.
The Group accounting policy for depreciation of oil and gas assets and operational assets, as well as the recognition of capacity building payments, are set out in the Summary of material accounting policies section.
The depreciation charge in 2024 is based upon internal reserves and development cost estimates. The 2023 depreciation charge was derived from the CPR prepared by ERC Equipoise as at 31 December 2022. The increase in charge compared to the corresponding period in 2023 is principally derived from higher production in 2024.
Contract termination, provision against inventory held for sale and loss on disposal of drilling stocks in 2023 relate to non-recurring activities undertaken following the ITP export pipeline suspension in March 2023.
4. Other general and administrative expenses
2024 2023
USD'000
USD'000
Depreciation and amortisation 3,033 2,652
Auditor's remuneration (see below) 679 635
Other general and administrative costs 7,700 7,179
11,412 10,466
2024 2023
USD'000 USD'000
Fees payable to the Company's auditor for the audit of the Company's annual accounts 530 474
Fees payable to the Company's auditor for other services to the Group
- audit of the Company's subsidiaries pursuant to legislation 32 26
Total audit fees
562 500
Other assurance services (including a half year review) 117 135
Total fees 679 635
5. Share option related expense
2024 2023
USD'000 USD'000
Share-based payment expense 3,472 9,673
Payments related to share options exercised 704 797
Share-based payment related provision for taxes 243 290
4,419 10,760
Under the Long Term Incentive Plan ("LTIP") schemes, GKP awards share options to employees annually that have a three-year vesting period, the share price at the date of award is a significant determinant of the number of shares issued to employees (see note 21).
In the event the Company pays dividends to shareholders during the vesting period, upon vesting the Company would compensate employees for an amount equivalent to the dividends paid during the vesting period and such amount would be settled at the Company's discretion with shares or cash. Given the financial challenges following the ITP closure, the Company used its discretion in 2023 to pay the dividend equivalent predominantly in shares to preserve liquidity. The significant decrease in share-based payment expense in 2024 is due to the decrease in shares issued in 2024 versus 2023 as compensation related to dividends paid in the vesting periods of the 2021 LTIP and 2020 LTIP.
6. Staff costs
The average number of employees, including Executive directors, and contractors employed by the Group was 411 (2023: 471); the number of full-time equivalents of these workers was 274 (2023: 303).
Average number of employees Average number of full-time equivalents
2024 2023 2024 2023
Kurdistan 387 444 250 276
United Kingdom 24 27 24 27
Total 411 471 274 303
Staff costs as follows are shown net of amounts recharged to joint operations:
2024 2023
USD'000 USD'000
Wages and salaries 37,833 37,645
Social security costs 2,723 1,826
Pension costs 472 468
Share-based payment (see note 21) 4,419 10,760
45,447 50,699
Staff costs include costs relating to contractors who are long-term workers in key positions and are included in PPE additions, cost of sales and other general and administrative expenditure depending on the nature of such costs. Staff costs are shown net of amounts recharged to joint operations.
7. Finance costs and finance income
2024 2023
USD'000 USD'000
Lease interest (48) (66)
Unwinding of discount on provisions (see note 15) (1,628) (1,699)
Total finance costs (1,676) (1,765)
Finance income 4,116 3,803
Net finance income 2,440 2,038
Since redemption of USD100m notes on 2 August 2022, the Group has remained debt free.
8. Income tax
2024 2023
USD'000 USD'000
Prior year adjustment - 195
Deferred UK corporation tax charge (see note 16) (708) (306)
Tax (charge)/credit attributable to the Company and its subsidiaries (708) (111)
The Group is not required to pay taxes in Bermuda on either income or capital gains. The Group has received an undertaking from the Minister of Finance in Bermuda exempting it from any such taxes at least until the year 2035.
In the KRI, the Group is subject to corporate income tax on its income from petroleum operations under the Kurdistan PSC. Under the Shaikan PSC, any corporate income tax arising from petroleum operations will be paid from the KRG's share of petroleum profits. Due to the uncertainty over the payment mechanism for oil sales in Kurdistan, it has not been possible to measure reliably the taxation due that has been paid on behalf of the Group by the KRG and therefore the notional tax amounts have not been included in revenue or in the tax charge. This is an accounting presentational issue and there is no taxation to be paid.
The annual UK corporation tax rate for the years ended 31 December 2024 and 31 December 2023 was 19% on profits up to GBP50k tapered to 25% on profits above GBP250k.
Deferred tax is provided for due to the temporary differences, which give rise to such a balance in jurisdictions subject to income tax. All deferred tax arises in the UK.
9. Earnings per share
The calculation of the basic and diluted profit/(loss) per share is based on the following data:
2024 2023
Profit/(loss) after tax for basic and diluted per share calculations (USD'000) 7,158 (11,500)
Number of shares ('000s):
Basic weighted average number of ordinary shares 219,562 217,992
Basic EPS (cents) 3.26 (5.28)
The Group followed the steps specified by IAS 33 in determining whether potential common shares are dilutive or anti-dilutive.
Reconciliation of dilutive shares:
2024 2023
Number of shares ('000s)
Basic weighted average number of ordinary shares outstanding 219,562 217,992
Effect of potential dilutive share options(1) 9,134 -
Diluted number of ordinary shares outstanding 228,696 217,992
Diluted EPS (cents)(1) 3.13 (5.28)
(1) At the reporting date, the Company had 9,134k dilutive (2023: 8,224k antidilutive) ordinary shares relating to outstanding share options. Earnings per share are calculated on the assumption of conversion of all potentially dilutive ordinary shares however, during a period where a company makes a loss, anti-dilutive shares are not included in the loss per share calculation as they would reduce the reported loss per share.
The weighted average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee ("EBT") of 0.1 million, (2023: 0.2 million).
10. Property, plant and equipment
Total
Oil and gas Fixtures and
Right of use assets
assets equipment
USD'000
USD'000 USD'000
USD'000
Year ended 31 December 2023
Opening net book value 433,556 2,257 630 436,443
Additions 58,240 453 86 58,779
Disposals' cost - - (70) (70)
Revision to decommissioning asset (8,933) - - (8,933)
Depreciation charge (39,470) (649) (356) (40,475)
Disposals' depreciation - - 66 66
Foreign currency translation differences - 5 27 32
Closing net book value 443,393 2,066 383 445,842
At 31 December 2023
Cost 992,870 9,404 2,188 1,004,462
Accumulated depreciation (549,477) (7,338) (1,805) (558,620)
Net book value 443,393 2,066 383 445,842
Year ended 31 December 2024
Opening net book value 443,393 2,066 383 445,842
Additions 18,252 284 1,559 20,095
Disposals' cost - - (2,040) (2,040)
Revision to decommissioning asset (693) - - (693)
Depreciation charge (75,781) (576) (394) (76,751)
Disposals' depreciation - - 2,004 2,004
Foreign currency translation differences - (1) (6) (7)
Closing net book value 385,171 1,773 1,506 388,450
At 31 December 2024
Cost 1,010,429 9,687 1,701 1,021,817
Accumulated depreciation (625,258) (7,914) (195) (633,367)
Net book value 385,171 1,773 1,506 388,450
The net book value of oil and gas assets at 31 December 2024 is comprised of property, plant and equipment relating to the Shaikan block with a carrying value of USD385.2 million (2023: USD443.4 million).
The additions to the Shaikan asset amounting to USD18.3 million during the year included safety critical upgrades at PF-1 and production optimisation expenditures.
The USD0.7 million (2023: USD8.9 million) decrease in decommissioning asset value relates to a USD1.1 million decrease in changes to inflation and discount rates (2023: USD13.1 million), offset by an increase of USD0.4 million relating to facilities work (2023: USD4.2 million).
The DD&A charge of USD75.8 million (2023: USD39.5 million) on oil and gas assets has been included within cost of sales (see note 3). The depreciation charge of USD0.6 million (2023: USD0.6 million) on fixtures and equipment and USD0.4 million (2023: USD0.4 million) on right of use assets has been included in general and administrative expenses (see note 4).
Right of use assets at 31 December 2024 of USD1.5 million (2023: USD0.4 million) consisted principally of buildings, with a new office lease entered into in 2024.
For details of the key assumptions and judgements underlying the impairment assessment, refer to the "Critical accounting estimates and judgements" section of the Summary of material accounting policies.
11. Group companies
Details of the Company's subsidiaries and joint operations at 31 December 2024 is as follows:
Place of Principal
Name of subsidiary incorporation Proportion of
ownership interest activity
Gulf Keystone Petroleum (UK)
Limited
1st Floor United Kingdom 100%
Management, support, geological, geophysical and
Brownlow Yard engineering services
7 Roger Street
London, WC1N 2JU
Gulf Keystone Petroleum
International Limited
c/o Carey Olsen Services
Bermuda Limited
Bermuda 100% Exploration, evaluation, development and
5th Floor production activities in Kurdistan
Rosebank Centre
11 Bermudiana Road
Pembroke, HM08 Bermuda
Principal
Name of joint operation Location
Proportion of ownership interest activity
Shaikan Kurdistan 80%
Production and development activities
12. Inventories
2024 2023
USD'000 USD'000
Warehouse stocks and materials 6,829 6,900
Crude oil 234 374
Inventory held for sale 2,789 2,627
9,852 9,901
13. Trade and other receivables
Non-current receivables
2024 2023
USD'000 USD'000
Trade receivables - non-current 138,175 140,218
Non-current trade receivables relate to overdue amounts due from the KRG, after deducting the expected credit loss, that are expected to be received more than 12 months from the reporting date (see Reconciliation of trade receivables below).
Current receivables
2024 2023
USD'000 USD'000
Trade receivables 16,583 6,350
Underlift - 3,806
Other receivables 7,291 3,080
Prepayments and accrued income 2,905 1,882
Total current receivables 26,779 15,118
Total receivables 164,954 155,336
Reconciliation of trade receivables
2024 2023
USD'000 USD'000
Gross carrying amount 171,026 171,026
Less: Impairment allowance (16,267) (24,458)
Carrying value at 31 December 154,759 146,568
Gross trade receivables relating to export sales of USD171.0 million (2023: USD171.0 million) are comprised of invoiced amounts due, based upon KBT pricing, from the KRG for crude oil sales totalling USD158.8 million (2023: USD158.8 million) related to October 2022 - March 2023 and a share of Shaikan amounts due from the KRG that GKP purchased from MOL amounting to USD12.2 million (2023: USD12.2 million). Although no legal right of offset exists, the net balance due from the KRG comprises USD158.8 million (2023: USD158.8 million) included in trade receivables and USD7.7 million (2023: USD7.7 million) included within current liabilities (see note 14), resulting in a net receivable balance due from the KRG relating to crude oil sales of USD151.1 million (2023: USD151.1 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 USD151.1 million above, comprises USD120.4 million cost oil and USD30.7 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 USD16.3 million (2023: USD24.5 million) was provided against the trade receivables balance in accordance with IFRS 9 'Financial Instruments'. During the year, a USD8.2 million credit was recognised due to the decrease in the ECL provision (2023: charge of USD21.4 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 USD6.1 million, conversely a decrease of the CDS by 2% would decrease the ECL provision by USD6.4 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 USD7.5 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 USD0.5 million (2023: USD0.4 million) being the deposits for leased assets which are receivable after more than one year. There are no receivables from related parties as at 31 December 2024 (2023: nil). No impairments of other receivables have been recognised during the year (2023: nil).
14. Current liabilities
Trade and other payables
2024 2023
USD'000 USD'000
Trade payables 1,746 11,953
Accrued expenditures 22,228 14,009
Amounts due to KRG not expected to be cash settled 80,905 74,703
Capacity building payment due to KRG on trade receivables 7,687 7,687
Other payables 4,080 683
Lease obligations 395 359
Overlift 236 -
Total trade and other payables 117,277 109,394
Trade payables and accrued expenditures principally comprise amounts outstanding for trade purchases and ongoing costs and the Directors consider that carrying amounts approximate fair value. The stabilising of local sale revenues during 2024 enabled the Group to settle all overdue trade payables in the first quarter of 2024.
Amounts due to KRG not expected to be cash settled of USD80.9 million (2023: USD74.7 million) include:
-- USD40.1 million (2023: USD37.7 million) expected to be offset against oil sales to the KRG up to 2018,together with other amounts since due from the KRG, that have not been recognised in the financial statements asmanagement consider that the criteria for revenue recognition have not been satisfied.
-- USD40.8 million (2023: USD37.0 million) related to an accrual for the difference between the capacitybuilding rate of 20%, as per the invoicing basis in effect since October 2017, and 30% as per the 2016 BilateralAgreement. The working interest under the 2016 bilateral agreement is 80% whereas the invoicing basis is 61.5%. Ifthe commercial position were to revert to the full terms of the executed amended PSC and the 2016 BilateralAgreement, the Group would not expect to cash settle this balance as a more than offsetting increase in GKP's netentitlement is expected to result in revenue being due to GKP (see critical accounting judgements), the value ofwhich is expected to exceed the accrued USD40.8 million.
Overlift is the volumes owed by the Company to the KRG through the lifting of volumes in excess of contractual entitlement in accordance with the PSC. The overlift is valued at the year-end sales price. The overlift was temporary and the KRG lifted the volumes in 2025.
Deferred income
At 31 December 2024, deferred income of USD0.7 million (2023: USD5.2 million) related to cash advances paid by local oil buyers in advance of lifting oil (See note 2).
Non-current liabilities
2024 2023
USD'000 USD'000
Non-current lease liability 1,112 39
15. Provisions
2024 2023 Decommissioning provision USD'000 USD'000 At 1 January 35,312 42,546 New provisions and changes in estimates (693) (8,933) Unwinding of discount 1,628 1,699 At 31 December 36,247 35,312
The USD0.7 million decrease in new provisions and changes in estimates (2023: USD8.9 million decrease) comprises an increase relating to new drilling and facilities work of USD0.4 million (2023: USD4.2 million), offset by a reduction of USD1.1 million (2023: USD13.1 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.
Total
Share-based payments
Accelerated tax depreciation Tax losses carried forward
USD'000 USD'000
USD'000
USD'000
At 1 January 2023 (572) 1,181 967 1,576
(Charge)/credit to income statement 882 (741) (447) (306)
Exchange differences (17) 42 250 275
At 31 December 2023 293 482 770 1,545
(Charge)/credit to income statement (271) 238 (675) (708)
Exchange differences - (11) (1) (12)
At 31 December 2024 22 709 94 825
17. Financial instruments
2024 2023
USD'000 USD'000
Financial assets
Cash 102,346 81,709
Receivables 161,426 152,709
263,772 234,418
Financial liabilities
Trade and other payables 118,152 109,433
118,152 109,433
All financial liabilities, except for non-current lease liabilities (see note 14), are due to be settled within one year and are classified as current liabilities. All financial liabilities are recognised at amortised cost.
Fair values of financial assets and liabilities
With the exception of the receivables from the KRG which the Group expects to recover in full (see note 13), the Group considers the carrying value of all its financial assets and liabilities to be materially the same as their fair value.
The financial assets balance includes a USD16.3 million provision against trade receivables (2023: USD24.5 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 USD171.0 million (2023: USD171.0 million). Although the Group is confident in the recovery of the trade receivables balance, a provision of USD16.3 million (2023: USD24.5 million) was recognised against the trade receivables balance.
The credit risk on liquid funds is limited because the counterparties for a significant portion of the cash at the balance sheet date are banks with investment grade credit ratings assigned by international credit-rating agencies.
Liquidity risk management
Ultimate responsibility for liquidity risk management rests with the Group's management under the oversight of the Board of Directors. It is the Group's policy to finance its business by means of internally generated funds, external share capital and debt. The Group seeks to raise further funding as and when required.
18. Share capital
2024 2023
USD'000 USD'000
Authorised:
Common shares of USD1 each 292,105 292,105
Common shares
No. of shares Share capital Share premium Total amount
'000 USD'000 USD'000 USD'000
Balance 1 January 2023 216,247 216,247 528,125 744,372
Dividends paid - - (24,813) (24,813)
Shares issued 6,196 6,196 - 6,196
Balance 31 December 2023 222,443 222,443 503,312 725,755
Dividends paid - - (34,933) (34,933)
Shares issued 255 255 - 255
Repurchase of ordinary shares (5,693) (5,693) (4,394) (10,087)
Balance 31 December 2024 217,005 217,005 463,985 680,990
At 31 December 2024, a total of 0.1 million common shares at USD1 each were held by the EBT (2023: 0.2 million at USD1 each). These common shares were included within reserves.
Rights attached to share capital
The holders of the common shares have the following rights (subject to the other provisions of the Byelaws):
(i) entitled to one vote per common share;
(ii) entitled to receive notice of, and attend and vote at, general meetings of the Company;
(iii) entitled to dividends or other distributions; and
in the event of a winding-up or dissolution of the Company, whether voluntary or involuntary or for a
reorganisation or otherwise or upon a distribution of capital, entitled to receive the amount of capital
(iv) paid up on their common shares and to participate further in the surplus assets of the Company only after
payment of the Series A Liquidation Value (as defined in the Byelaws) on the Series A Preferred Shares.
19. Cash flow reconciliation
2024 2023
Notes USD'000 USD'000
Cash flows from operating activities
Profit/(loss) from operations 4,702 (13,043)
Adjustments for:
Depreciation, depletion and amortisation of property, plant and equipment (including the right 76,752 40,409
of use assets)
Amortisation of intangible assets 1,980 1,648
(Decrease)/Increase of provision for impairment of trade receivables 13 (8,191) 21,378
Share-based payment expense 21 3,472 9,673
Provision against inventory held for sale 3 34 2,627
Operating cash flows before movements in working capital 78,749 62,692
Decrease/(Increase) in inventories 49 (7,605)
Increase in trade and other receivables (1,290) (10,741)
Increase in trade and other payables 11,919 3,107
Income taxes received - 67
Cash generated from operations 89,427 47,520
Reconciliation of property, plant and equipment additions to cash flows from purchase of property, plant and equipment:
2024 2023
USD'000 USD'000
Associated cash flows
Additions to property, plant and equipment 20,102 58,652
Movement in working capital 7,083 6,764
Non-cash movements
Foreign exchange differences (7) (30)
Purchase of property, plant and equipment 27,178 65,386
20. Commitments
Exploration and development commitments
Additions to property, plant and equipment are generally funded with the cash flow generated from the Shaikan Field. As at 31 December 2024, gross capital commitments in relation to the Shaikan Field were estimated to be USD9.2 million (2023: USD2.2 million).
21. Share-based payments
2024 2023
USD'000 USD'000
Total share options charge 3,472 9,673
The share options charge of USD3.5 million (2023: USD9.6 million) is comprised of USD3.2 million (2023: USD9.1 million) related to the LTIP plan and USD0.3 million (2023: USD0.6 million) related to the deferred bonus plan. See note 5 for other share option related expenses charged to the consolidated income statement.
Long Term Incentive Plan
The Gulf Keystone Petroleum 2014 LTIP is designed to reward members of staff through the grant of share options at a zero-exercise price, that vest three-years after grant, subject to the fulfilment of specified performance conditions. These performance conditions are 50% Total Shareholder Return ("TSR") over the vesting period and 50% of the Group's TSR relative to a bespoke group of comparators over the vesting period. In July 2024, Gulf Keystone Petroleum introduced the 2024 LTIP. Under this plan, Executive Directors were awarded shares consistent with the 2014 LTIP, with the addition of a two-year post-vesting holding period, during which vested awards cannot be sold except to cover the tax liability upon exercise. Similarly, the 2024 LTIP granted to senior management follows the 2014 LTIP guidelines, featuring a three-year vesting period from the grant date, without a post-vesting holding period, and subject to specific performance conditions. The 2024 LTIP granted to other staff members consists of nil-cost options with one, two, and three-year vesting periods, with no post-vesting holding periods or performance conditions attached.
2024 2023
Number of Number of
share options share options
'000 '000
Outstanding at 1 January 8,004 8,785
Granted during the year 3,590 6,295
Exercised during the year (516) (6,383)
Forfeited during the year (288) (211)
Expired during the year (1,872) (482)
Outstanding at 31 December 8,918 8,004
Exercisable at 31 December - -
The weighted average share price at the date of exercise for share options exercised during the year was GBP1.48 (2023: GBP1.17).
The inputs into the calculation of fair values of the share options granted during the year are as follows:
2024 2023 Weighted average share price GBP1.11 GBP1.07 Weighted average exercise price Nil Nil Expected volatility 56.1% 52.5% Expected life 3 years 3 years Risk-free rate 4.3% 3.3% Expected dividend yield (on the basis dividends equivalents received) Nil Nil
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 USD4.6 million (2023 USD4.6 million).
Deferred Bonus Plan
At the Company's AGM in June 2019, shareholders approved the Deferred Bonus Plan. This provides for 30% of the annual bonus attributable to executive directors to be paid in the form of nil cost options that can be exercised any time after the three-year vesting period. There are no performance conditions other than the executive director must continue to be employed for this period (subject to certain limited exceptions).
2024 2023
Number of Number of
share options share options
'000 '000
Outstanding at 1 January 216 218
Exercised during the year - (180)
Granted during the year - 178
Outstanding at 31 December 216 216
Exercisable at 31 December - -
There were no options exercised during the year under the Deferred Bonus Plan (2023: the weighted average share price at the date of exercise for share options exercised was GBP1.37).
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 USD35 million dividends (16.048 US cents per Common Share), being interim dividends, were declared and paid to shareholders. In 2023, a total of USD25 million dividends (11.561 US cents per Common Share).
An interim dividend of USD25 million was declared in March 2025.
23. Related party transactions
The Company has a related party relationship with its subsidiaries and in the ordinary course of business, enters into various sales, purchase and service transactions with joint operations in which the Company has a material interest. These transactions are under terms that are no less favourable to the Group than those arranged with third parties.
Remuneration of Directors and Officers
The Directors and Officers who served during the year ended 31 December 2024 were as follows:
M Angle - Chairman (deceased September 2024)
D Thomas - Non-Executive Director became Deputy Chair June 2023, became Interim Chair September 2024 and became Chair October 2024
J Balkany - Non-Executive Director
M Daryabegui - Non-Executive Director (appointed October 2024)
C Krajicek - Non-Executive Director (appointed October 2024)
W Mwaura - Non-Executive Director
K Wood - Non-Executive Director (resigned June 2024)
J Harris - Chief Executive Officer and Executive Director
G Papineau-Legris - Chief Commercial Officer appointed as Chief Financial Officer and Executive Director (effective June 2024)
I Weatherdon - Chief Financial Officer and Executive Director (resigned June 2024)
C Kinahan - Chief Human Resources Officer
J Hulme - Chief Operating Officer
A Robinson - Chief Legal Officer and Company Secretary
The remuneration of the Directors and Officers who are considered to be key management personnel is set out below in aggregate for each of the categories specified in IAS 24 Related Party Disclosures.
The values below are calculated in accordance with IAS 19 and IFRS 2.
2024 2023
USD'000 USD'000
Short-term employee benefits 7,196 3,463
Share-based payment - options 1,493 4,065
8,689 7,528
Further information about the remuneration of individual Directors is provided in the Directors' Emoluments section of the Remuneration Committee report.
24. Contingent Liabilities
The Group has a contingent liability of USD27.3 million (2023: USD27.3 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.
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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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(END) Dow Jones Newswires
March 20, 2025 03:01 ET (07:01 GMT)
