21 March 2024

 

 

Gulf Keystone Petroleum Ltd. (LSE: GKP)

("Gulf Keystone", "GKP", "the Group" or "the Company")

 

2023 Full Year Results announcement

 

Gross average sales in 2024 year to 19 March of c.33,300 bopd; March 2024 to date sales of c.43,000 bopd

Cash balance as at 20 March of $86 million, accounts payable current

Cash generative in current environment with upside potential from exports restart and payments normalisation

 

Gulf Keystone, a leading independent operator and producer in the Kurdistan Region of Iraq ("Kurdistan"), today announces its results for the full year ended 31 December 2023.  

 

Jon Harris, Gulf Keystone's Chief Executive Officer, said:

"Following a challenging year in 2023, in which our operational and financial performance was impacted by the suspension of Kurdistan exports and delays to KRG payments, we successfully adapted to the new local sales environment. Local sales volumes have rebounded since the beginning of 2024, with year to date gross average sales of c.33,300 bopd and March to date sales of c.43,000 bopd. We are more than covering our monthly expenditures and have significantly reduced accounts payable, with all invoices now current. Free cash flow from current robust local sales demand is being used to further improve our liquidity position. Looking ahead, we remain resilient with upside potential from the restart of exports and normalisation of payments. While there is no defined timeline, we continue to actively engage with government stakeholders to secure a solution to unlock significant value for all stakeholders."

 

Highlights to 31 December 2023 and post reporting period

 

Operational

 

·     Continued rigorous focus on safety, with Zero Lost Time Incidents for 430 days as at 20 March 2024

·     Significant operational transition following the Iraq-Turkey Pipeline ("ITP") closure on 25 March 2023 as GKP moved from pipeline exports and reservoir development to the shut-in of production, suspension of all expansion activities and subsequent start-up of local sales

·     2023 gross average production of 21,891 bopd (2022: 44,202 bopd), reflecting strong growth prior to the suspension of exports followed by the start-up of local sales in H2 2023 at lower levels

o  Gross production averaged 49,165 bopd between 1 January and 24 March 2023, with the ramp-up of SH-16 and start-up of SH-17 driving production to highs of over 55,000 bopd on several days in March 2023

o  Gross average local sales of 23,331 bopd between 19 July and 31 December 2023

·     Increasing local demand in 2024 year to date has driven a rebound in sales volumes

o  Year to date gross average sales of 33,300 bopd, with gross average sales in March 2024 to date of c.43,000 bopd, as at 19 March 2024

o  Ramp up in local sales reflects strong market demand for certain refined products, the further easing of seasonal logistic challenges and a realised price of c.$25/bbl

Financial

 

·     Material impact on 2023 financial performance from the suspension of exports and continued delays to payments from the Kurdistan Regional Government ("KRG")

·     Decisive action taken to preserve liquidity¸ with significant expenditure reductions and transition to local sales

·     Reduction in revenue and profitability from lower production and realised prices

o  Revenue reduced to $123.5 million (2022: $460.1 million), reflecting the 50% decrease in gross average production to 21,891 bopd and lower average realised prices from local sales in H2 2023 of $30/bbl

o  Loss after tax of $11.5 million (2022: profit after tax of $266.1 million), including an increase in the expected credit loss provision determined under IFRS 9 of $21.4 million (2022: $2.0 million) related to the $151 million overdue receivables from the KRG for October 2022 to March 2023 export sales. The Company continues to expect to recover the receivables

·     Free cash outflow of $13.1 million (2022 free cash flow of $266.5 million), reflecting lower Adjusted EBITDA and delays to KRG payments, partially offset by reduced net capex and costs

o  Adjusted EBITDA declined to $50.1 million (2022: $358.5 million)

o  Revenue receipts of $109.2 million (2022: $450.4 million), reflecting $65.7 million for export sales in August and September 2022 received in Q1 2023 and $43.5 million from local sales in H2 2023

o  2023 net capex of $58.2 million (2022: $114.9 million), of which $11.2 million was in H2 2023, as the Company suspended all Shaikan Field expansion activity

o  2023 operating costs of $36.1 million were 14% lower year-on-year (2022: $41.9 million), reflecting the shut-in of production for more than three months and cost saving initiatives

o  2023 Other G&A reduced to $10.5 million (2022: $12.2 million) principally due to cost savings and no bonus payments to staff, partially offset by non-recurring corporate costs of $2.1 million in H1 2023

·     Cash generated from local sales has enabled the Company to more than cover its monthly expenditures and strengthen its balance sheet

o  Net capex, operating costs and Other G&A reduced to a monthly run rate below $6 million in H2 2023

o  GKP's 36% net entitlement from local sales have enabled the Company to more than cover its costs since commencement, with current breakeven at gross sales of c.22,200 bopd

o  Excess cash generation facilitated the reduction in accounts payable, including trade payables and accrued expenditures, to $26.0 million at 31 December 2023 (31 December 2022: $44.1 million)

o  The payment of all remaining overdue invoices in 2024 has resulted in a further reduction in accounts payable to roughly half the balance at the end of 2023

·     Following the payment of a $25 million interim dividend in March 2023, the Company's ordinary dividend policy was suspended to preserve liquidity

·     Cash balance of $86 million at 20 March 2024 with no debt

 

Shaikan Field estimated reserves

 

·     In March 2023, the Company published the 2022 Competent Person's Report ("CPR"), an independent third-party evaluation confirming 817 MMstb of estimated gross reserves and resources, including 506 MMstb million stock tank barrels ("MMstb") of estimated gross proved and probable ("2P") reserves

·     We have seen no degradation to the reservoir from the extended shut-in of production in 2023 and the field is performing in line with our expectations

o  However, we do not expect to consider a return to development of the Shaikan Field until exports have restarted and we have confidence in KRG payments and the commercial environment

·     To assess the impact of the production shut-in and suspension of expansion activity on gross 2P reserves, we have prepared internal estimates that incorporate a delay in return to development drilling

o  Adjusting year end 2022 gross 2P reserves of 506 MMstb for 2023 production of 8 MMstb, we estimate that the development delay has reduced gross 2P reserves by 40 MMstb or 8% to 458 MMstb at 31 December 2023, as recoverable volumes are pushed beyond licence expiry in 2043

·     Based on 2022 gross average production of 44,202 bopd, the last full year of production prior to the ITP closure, the estimated gross 2P reserves-to-production ratio is c.28 years, underpinning the case for eventual further investment when the environment improves

·     We expect to commission an updated CPR, including a comprehensive independent assessment of proved reserves, 2P reserves and contingent resources, once the operating environment has normalised

 

Outlook

 

·     The Company is focused on maximising local sales and minimising costs to improve its liquidity position, while pushing for an exports restart and payment solution to unlock significant value

·     While we continue to expect variable local sales demand in 2024, we see robust market demand in the near term and remain focused on maintaining our strong performance

·     Subject to local sales demand and considering our limited capital programme, gross production potential is currently between 43,000 - 45,000 bopd:

o  Continue to manage well productivity to avoid traces of water and field declines estimated at 6-10% per year

·     Expect to maintain aggregate net capex, operating costs and other G&A monthly run rate at or below c.$6 million in 2024:

o  Estimated 2024 net capex of c.$20 million, comprising safety critical upgrades and production maintenance expenditures

o  Continuing to focus on further reducing costs while retaining operational capability to respond to local sales demand and resume exports

·     The Company continues to actively engage with government stakeholders to push for a pipeline exports restart solution:

o  While it remains uncertain when exports will restart, political and commercial negotiations between the Federal Government of Iraq ("FGI") and the KRG are ongoing

o  Together with other International Oil Companies operating in Kurdistan, we continue to emphasise the importance of payment surety for future oil exports, the repayment of outstanding receivables and the preservation of current contract economics

·     With the resumption of exports and normalisation of payments and arrears, GKP will consider incremental field investment to realise Shaikan's substantial potential and return to previous production levels

·     We continue to believe the distribution of excess cash by way of dividends or share buybacks is important to reward shareholders. As the operating environment and the Company's liquidity position improve, we will keep under review our capability to reinstate distributions

 

Investor & analyst presentation

 

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_FY23   

 

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

 

 

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	[email protected]
FTI Consulting	+44 (0) 20 3727 1000
Ben Brewerton Nick Hennis	[email protected]

 

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.

Chairman's statement

 

I'm pleased to be writing to you for the first time as Non-Executive Chairman of Gulf Keystone Petroleum following my appointment at the Annual General Meeting in June 2023. It was a privilege to take on the role after almost five years on GKP's Board of Directors. I joined the company as Senior Independent Director in July 2018 before also becoming Deputy Chairman from June 2019. During that time, I was fortunate to work closely with Jaap Huijskes, who I succeeded as Chairman. Jaap oversaw a period of significant value creation for our shareholders and Kurdistan and provided strong leadership during periods of significant volatility, in particular the COVID-19 pandemic.

 

My first few months as Chairman have been characterised by a challenging operational and economic environment for the Company. The closure of the Iraq-Turkey Pipeline ("ITP") and suspension of Kurdistan exports on 25 March 2023 compounded the impact of increasing delays to payments from the Kurdistan Regional Government ("KRG"), prompting the Company to take decisive action to protect its balance sheet. In adapting to this new environment, the management team have demonstrated considerable agility and commitment in transitioning the company away from Shaikan crude being exported by pipeline, with continued execution of the development programme, to establishing sales of crude to local buyers with 24-hour truck loading operations, whilst maintaining a sustained focus on liquidity preservation. This has enabled the company to more than cover its reduced monthly expenditures with local pre-paid sales revenue.

 

I and the rest of GKP's Board have spent significant time since the ITP closure analysing the geopolitical environment and the pathway to a potential exports restart solution. It is our continued belief that crude exports from the Kurdistan Region are of vital economic importance to both Kurdistan and Federal Iraq. While it remains uncertain when exports will restart, progress has been made in negotiations between the KRG and the Federal Government of Iraq towards a solution and the Company has proactively made its voice heard along with other companies operating in the region. The Company remains focused on protecting shareholder interests by ensuring that current Production Sharing Contract economics are preserved, clarity is provided around the payment mechanism for future exports and a pathway to the repayment of the Company's outstanding receivables is defined.

 

The Company has a strong team in place to navigate through the current challenges. Collectively they have many years of experience working in Kurdistan and other emerging market environments. They also have significant technical expertise in fractured carbonate reservoirs. The Board has been pleased to see the reservoir performing in line with expectations, enabling the ramp up of production in recent weeks to respond to the current strong demand in the local market. This has confirmed the Company's decision to maintain the operational flexibility required to increase local sales quickly and retain the optionality to restart exports at full capacity when required.

 

We were pleased to welcome Julien Balkany to the Board in July 2023 as a non-independent non-executive director representing funds managed by Lansdowne Partners Austria GmbH, replacing Garrett Soden. We are also looking forward to welcoming Gabriel Papineau-Legris as he succeeds Ian Weatherdon as Chief Financial Officer following his retirement at the 2024 AGM in June. On behalf of the Board, I would like to thank Ian for his substantial contribution over the past four years.

 

We are currently looking to recruit two new Non-Executive Directors to meet the UK Corporate Governance Code and UK Listing Rules requirements in respect of independence, gender and ethnic diversity, to broaden the operational and technical experience of the Board, and to replace Kimberley Wood as current Senior Independent Director following her previously announced intention to stand down from the Board because of her time commitments to an executive role she has recently taken on elsewhere. This recruitment process began in early 2023 but was suspended, until late in the year, following the ITP closure given the then prevailing, uncertain geo-political and trading background and the Company's necessary focus on short term liquidity.

 

The Board continued to engage with the Company's shareholders in 2023 and welcomes ongoing interaction and feedback with all investors. We would like to thank all of the Company's shareholders for their continued support. The Company has demonstrated resilience and continues to take prudent actions to protect the balance sheet, ensuring that it is well positioned to unlock the Shaikan Field's significant value when pipeline exports restart and the operating environment improves.

 

Martin Angle

Non-Executive Chairman

 

20 March 2024

 

Chief Executive Officer's review

 

GKP's operational and financial performance in 2023 was materially impacted by the suspension of Kurdistan exports and delays to KRG oil sales payments. Our actions to reduce capital expenditures and costs and safely transition our operations to trucking and local sales have enabled us to protect our business as we continue to engage with government stakeholders for an exports restart solution.

 

The unexpected closure of the Iraq-Turkey Pipeline ("ITP") on 25 March 2023 was the consequence of a long running International Chamber of Commerce arbitration case between Iraq and Turkey being awarded in Iraq's favour. With no route to market, we shut-in the Shaikan Field on 13 April following curtailed production into storage and moved swiftly to suspend the drilling and development project that had driven gross production to highs of over 55,000 bopd on several days in March. Following the payment of a $25 million interim dividend prior to the ITP closure, we suspended the ordinary annual dividend. By taking decisive action, we were able to reduce monthly capex and costs to below $6 million in the second half of the year. Despite the significant disruption to our organisation, we have maintained our focus on safe operations, with 430 days without a Lost Time Incident to date.

 

In July 2023, we started sales of Shaikan Field crude via truck to the local downstream market. While volumes have fluctuated and realised prices have been at steep discounts to Brent, all crude has been paid for in advance by buyers and demand has been sufficient for us to more than cover our monthly costs and significantly reduce accounts payable balances. Gross average sales were 23,331 bopd in the second half of 2023 from commencement on 19 July 2023. The local market has been stronger in 2024, driven by increased demand for certain refined products and the easing of seasonal logistic challenges. Gross average sales in the year to 19 March have been c.33,300 bopd, with gross average sales in March to date of c.43,000 bopd. Realised prices are currently c.25/bbl, in line with local market pricing.

 

We continue to minimise our capital expenditures and costs, with our aggregate monthly run rate expected to remain at or below c.$6 million in 2024. We continue to focus on maximising local sales to cover our costs and strengthen our balance sheet. While we continue to expect variable local sales demand in 2024, we see strong near-term demand. At current local sales levels, we are cash generative, with our current low gross production breakeven of c.22,200 bopd providing downside protection.

 

While there remains no defined timeline, we are actively engaging with government stakeholders to push for the restart of pipeline exports. Kurdistan production, historically around 400,000 bopd, is integral to funding the Iraqi Budget and represents a material source of global oil supply. The re-establishment of a constructive environment for international investors is also important to encourage foreign direct investment for both Kurdistan and Iraq. Negotiations are ongoing between the KRG and Federal Government of Iraq and the path forward appears to be linked to amending the Iraqi Budget to integrate a more accurate reflection of the production and transportation costs associated with the Kurdistan industry. We believe progress has been made but continue to seek clarity, along with other International Oil Companies, on how the industry will be compensated for future exports and when outstanding receivables will be repaid, of which GKP is owed $151 million net. We continue to strongly emphasise that the current economics in our Production Sharing Contract must be preserved and have received contract sanctity assurances from the KRG.

 

With the resumption of exports and normalisation of payments, we would consider incremental field investment to realise Shaikan's potential. We also continue to believe the return of excess cash by way of dividends or share buybacks is important to reward shareholders and we will keep under review our capability to reinstate distributions as the operating environment and Company's liquidity position improves. While we are resilient and cash generative at current local sales levels, we see the potential for significant free cash flow generation once an exports restart solution has been achieved, enabled by capital discipline, the continued recovery of previous costs and a return to selling Shaikan Field crude at international oil prices, which could more than double current realised prices.

 

Given delays experienced in the development of the Shaikan Field, current internal estimates show an 8% reduction in gross 2P reserves at year end 2023 to 458 MMstb after adjusting for 2023 production, as explained in the Operational Review. Nonetheless, the Shaikan Field remains a large, underdeveloped asset, with more than enough barrels to underpin strong production growth in our licence period. Our current reserves-to-production ratio of around 28 years, based on estimated gross 2P reserves and our last year of full production in 2022, underlines this fact.

 

As ever, I want to thank the entire team at GKP for their unwavering commitment who have adapted well to the many changes we have experienced. I continue to believe the normalisation of our operating environment and opportunity to create significant value for our stakeholders is ahead of us.

 

I want to extend my thanks to Ian Weatherdon, GKP's Chief Financial Officer, who will be retiring in the summer following the 2024 AGM. Ian has been instrumental in guiding the Company through the COVID-19 pandemic and the past year and has also overseen a period of industry leading returns, strong production growth and the strengthening of our balance sheet through the retirement of our $100 million bond in 2022. As previously announced, he will be succeeded by Gabriel Papineau-Legris, currently Chief Commercial Officer, who has been pivotal to GKP's success over the past seven years.

 

Jon Harris

Chief Executive Officer

 

20 March 2024

 

Operational review

 

2023 was a year of significant operational transition for Gulf Keystone. From progressing the Jurassic reservoir expansion project and moving towards sanction of the Shaikan Field Development Plan, we were forced to completely change the direction of the business following the closure of the Iraq-Turkey Pipeline ("ITP") in March 2023 and, after over three months of shut-in, switch from pipeline exports to trucking operations in the second half of the year.

 

Despite these changes, we maintained a rigorous focus on safety. While we unfortunately experienced a Lost Time Incident ("Lost Time Incident") in January 2023 during drilling operations, we have been operating since then for 430 days without an LTI. Given the ever-changing environment, the team has performed exceptionally, and with 24-hour truck loading operations running at both production facilities in recent weeks, often in difficult weather conditions, we remain focussed on extending this record.

 

2023 gross average production was 21,891 bopd, 50% lower year-on-year (2022: 44,202 bopd), primarily reflecting the shut-in of Shaikan Field production from 13 April to 19 July 2023 prior to the commencement of local sales, which were at a lower level than compared to when the Company was exporting.

 

Prior to the ITP closure gross production average 49,165 bopd, including five days in excess of 55,000 bopd, as we progressed the Jurassic expansion project, ramped up production from SH-16 and started up SH-17. Following the ITP closure on 25 March 2023, production continued at curtailed rates into storage prior to a full shut-in on 13 April 2023.

 

As it became apparent that pipeline exports were unlikely to resume in the short term, we suspended all expansion activity. Following the completion of SH-18, we released our drilling rig and suspended well workover activity. We also halted all production facilities expansion activity, including the installation of water handling, as well as the preparation of future well pads and flowlines. Regrettably, we also had to take action to reduce the size of the organisation. Our expat workforce was reduced by over 60% and around half of our local workforce were placed on reduced working hours prior to the start-up of local sales.

 

On 19 July 2023, we commenced local sales from PF-1 and started sales from PF-2 in August, with gross average sales from 19 July to 31 December 2023 of 23,331 bopd. Volumes increased steadily from July to October as we signed up new buyers following an extensive due diligence process. Lower levels of demand and volumes followed in November and December as other producers in the region ramped up supply, local refineries became constrained and winter weather impacted trucking logistics and dampened appetite for certain refined products. 

 

Volumes have rebounded since the beginning of 2024, with gross average sales in the year to 19 March 2024 of c.33,300 bopd and gross average sales in March 2024 to date of c.43,000 bopd. Subject to local sales demand and considering our limited capital programme, we see the current gross production potential of the Shaikan Field as between 43,000 - 45,000 bopd. As ever, we continue to manage natural field declines, estimated at between 6-10% per annum, and the productivity of wells to avoid traces of water. We see robust local sales demand in the near term and are focused on maintaining our current strong performance.

 

Shaikan Field estimated reserves

 

A few days prior to the ITP closure in March 2023, the Company published the 2022 Competent Person's Report ("2022 CPR"), an independent third-party evaluation of the Shaikan Field's reserves and resources prepared by ERC Equipoise ("ERCE"), as at 31 December 2022. The CPR confirmed the Shaikan Field as a large, long-life asset, with 817 MMstb of estimated gross reserves and resources, including 506 MMstb of estimated gross 2P reserves.

 

We have seen no degradation to the reservoir from the extended shut-in of production in 2023 and the Field is performing in line with our expectations. However, we do not expect to consider a return to development of the Shaikan Field until exports have restarted and we have confidence in payments and the commercial environment.

 

To assess the impact of the production shut-in and suspension of expansion activity on gross 2P reserves, we have prepared internal estimates that incorporate an estimated return to facilities expansion, including water handling, in 2025 and development drilling in H1 2026. This timeline is subject to an improvement in the operating environment and restart of Kurdistan exports, which for modelling purposes we assume occurs in Q4 2024, and incorporates several months of preparatory and planning work in advance of development activities.

 

Adjusting year end 2022 gross 2P reserves of 506 MMstb for 2023 production of 8 MMstb, we estimate that the development delay has reduced gross 2P reserves by 40 MMstb or 8% to 458 MMstb at 31 December 2023, as recoverable volumes are pushed beyond the end of the licence period in 2043. Based on 2022 gross average production of 44,202 bopd, the last full year of export sales prior to the ITP closure, the revised estimate of gross 2P reserves-to-production ratio is around 28 years, underpinning the case for further investment.

 

We expect to commission an updated Competent Person's Report, including a comprehensive independent assessment of 1P and 2P reserves and 2C resources, at the appropriate time once the operating environment has normalised.

 

Sustainability strategy

 

We remain committed to building a more sustainable business. Our sustainability strategy is focused on reducing emissions and protecting the local environment, maintaining high standards of safety, ensuring a great place to work for our people, generating significant economic value for Kurdistan and doing business the right way with outstanding levels of governance and ethical behaviour.

 

In 2023, progress against our strategy, in particular our focus on reducing emissions, was impacted by the suspension of exports and reduction in investment and costs across the business. While our Scope 1 emissions in the year were 51% lower due to the decrease in Shaikan Field production, the Gas Management Plan, which is an important component of the Shaikan Field Development Plan, has been delayed. We have also paused the assessment and development of a number of other decarbonisation projects, including an initiative to eliminate methane venting from our storage tanks. As a result, our previous emissions reduction targets, including reducing our scope 1 emissions intensity by >50% by 2025 against a 2020 baseline, have been suspended.

 

We remain committed to significantly reducing our emissions and will review and reinstate our targets when we have more clarity on the outlook. In the meantime, we are in the early stages of exploring alternative options to the Gas Management Plan, with a focus on optimising scope, implementation timing and cost. We are also prioritising our list of additional decarbonisation opportunities so we are ready to progress at the appropriate time.

 

Looking to the future, we remain committed to executing our sustainability strategy and improving our performance. In the short term, we are acting within the constraints of the current environment to extend our excellent safety performance, assess more effective ways to decarbonise our business, make GKP a better place to work for our employees and contractors and direct as much support as possible to local communities and people. Full details will be published in our 2023 Annual Report and Sustainability Report. With the restart of exports and the re-establishment of a more constructive investment environment for international oil companies, we will be able to return to investment, reinvigorate our progress towards a more sustainable business and unlock significant value for all stakeholders.

 

John Hulme

Chief Operating Officer

 

20 March 2024

 

Financial review

 

Key financial highlights

 

		Six months ended 30 June 2023	Six months ended 31 December 2023	Year ended 31 December 2023	Year ended 31 December 2022
Gross average production(1)	bopd	23,256	20,549	21,891	44,202
Dated Brent(2)	$/bbl	81.2	85.3	82.6	101.4
Realised price	$/bbl	51.3	30.0	40.9	74.1
Discount to Dated Brent	$/bbl	29.9	55.3	41.7	27.2
Revenue	$m	79.6	44.0	123.5	460.1
Operating costs	$m	18.9	17.2	36.1	41.9
Gross operating costs per barrel(1)	$/bbl	5.6	5.7	5.6	3.2
Other general and administrative expenses	$m	9.1	1.3	10.5	12.2
Share option expense	$m	8.4	2.4	10.8	13.8
Adjusted EBITDA(1)	$m	34.2	17.9	50.1	358.5
Profit/(loss) after tax	$m	(2.9)	(8.6)	(11.5)	266.1
Basic earnings/(loss) per share	cents	(1.3)	(3.9)	(5.3)	123.5
Revenue and arrears receipts(1)(3)	$m	65.7	43.5	109.2	450.4
Net capital expenditure(1)	$m	47.0	11.2	58.2	114.9
Free cash flow(1)	$m	(9.9)	(3.2)	(13.1)	266.5
Dividends	$m	25	-	25	215
Cash and cash equivalents	$m	84.9	81.7	81.7	119.5

 

(1) Gross average production, realised price, gross operating costs per barrel, Adjusted EBITDA, revenue and arrears receipts, net capital expenditure and free cash flow are either non-financial or non-IFRS measures and, where necessary, are explained in the summary of non-IFRS measures.

(2) For the period six months ended 31 December 2023, a simple average Dated Brent price is provided as a comparator for realised price. Realised prices for local sales are currently driven by supply and demand dynamics in the local market, with no direct link to Dated Brent. For prior periods, Dated Brent reflects the weighted average price used for export sales.

(3) Arrears receipts relate to historic receivables settled in H1 2022; all receipts in 2023 were for current invoices.

 

While GKP started the year with production and development momentum, the Company's financial performance in 2023 was significantly impacted by the suspension of Kurdistan crude exports on 25 March 2023 and continued delays to KRG payments. To protect our balance sheet, we took decisive action to preserve liquidity by reducing net capital expenditures, operating costs and other G&A expenses to a monthly run rate of less than $6 million in the second half of the year. With the commencement of local sales in July, we have been able to more than cover our monthly expenditures while significantly reducing outstanding accounts payable. Looking ahead, we remain focused on minimising costs while maintaining operational capability to maximise local sales and fully capitalise on the restart of Kurdistan exports.     

 

Adjusted EBITDA

 

Adjusted EBITDA declined to $50.1 million (2022: $358.5 million), driven by the impact on production from the suspension of exports and lower realised prices from local sales in H2 2023.

 

Gross average production was 21,891 bopd, 50% lower year-on-year (2022: 44,202 bopd) reflecting the shut-in of Shaikan Field production from 13 April to 19 July prior to the commencement of local sales, which were at lower levels than export sales.

 

Revenue decreased to $123.5 million (2022: $460.1 million), reflecting no revenue in the second quarter and lower local sales volumes and realised prices in the second half of the year. Production in the second half of the year was sold to local buyers at an average realised price of $30/bbl, well below historical discounts to Dated Brent. Realised prices for local sales are currently driven by supply and demand dynamics in the local market, with no direct link to Dated Brent.

 

The Company took decisive action to reduce expenses following the suspension of Kurdistan crude exports.

 

Operating costs of $36.1 million were 14% lower year-on-year (2022: $41.9 million), reflecting the shut-in of production for more than three months and cost saving initiatives. The increase in gross operating costs per barrel to $5.6/bbl in the year (2022: $3.2/bbl) reflected the halving of annual production. The Company expects unit costs will decrease with increased local sales or the resumption of pipeline exports.

 

Despite non-recurring corporate costs of $2.1 million in the first half of 2023, Other G&A has decreased by $1.7 million in 2023 to $10.5 million due principally to costs savings and the Remuneration Committee's decision at the end of the year to not pay a bonus to staff.

 

After the shut-in of the Iraq-Turkey Pipeline, GKP significantly reduced contractual commitments related to expansion activities and monetised certain drilling inventory with the suspension of the continuous drilling programme. As a result, the Company incurred a one-off expense of $9.6 million, included in cost of sales, related to the cancellation and suspension of contracts and loss on sale and write-down of inventory held for sale. $4.1 million of the expense was non-cash.

 

Share option related expense in the year of $10.8 million primarily reflected the vesting of the 2020 LTIP award, most of which was non-cash. The 22% decrease versus the prior period (2022: $13.8 million) reflected the final vesting of the Value Creation Plan ("VCP") in 2022.  

 

Profit/(loss) after tax

 

The Company generated a loss after tax of $11.5 million (2022: profit after tax of $266.1 million), including an increase in the expected credit loss provision of $21.4 million (2022: $2.0 million) on overdue receivables from the KRG for the months of October 2022 to March 2023 totalling $151 million, net of capacity building payments, on the basis of the KBT pricing mechanism. The Company continues to expect to recover the full value of overdue receivables.

 

Cash flows

 

In 2023, GKP's revenue receipts were $109.2 million (2022: $450.4 million). Prior to the suspension of exports, $65.7 million was received from the KRG related to invoices for crude sold in August and September 2022, received in January and March 2023 respectively. In H2 2023, $43.5 million was generated from local sales, with advance payments received for all crude.

 

Net capital expenditure in the year was $58.2 million (2022: $114.9 million), primarily reflecting works related to the suspended Jurassic reservoir expansion project, including the completion of SH-17 and SH-18, well workovers, well pad preparation, long lead items and the expansion of production facilities. Net capex decreased 76% to $11.2 million in H2 2023 relative to H1 2023, reflecting the focus on safety-critical works and recurring capex only.

 

The Company paid a $25 million interim dividend at the beginning of March 2023. Following the suspension of exports, the Board cancelled the proposed final 2022 ordinary annual dividend of $25 million to preserve liquidity.

 

The reduction in net capex, combined with reductions to operating costs and Other G&A, enabled the Company to reduce monthly expenditures to below $6 million in H2 2023. Cash generated by local sales in the period more than covered expenditures while providing flexibility to reduce accounts payable, comprised of trade payables and accrued expenditures, to $26.0 million as at 31 December 2023 (30 June 2023: $48.1 million).

 

The free cash outflow in the year of $13.1 million (2022 free cash flow of $266.5 million), combined with the payment of the interim dividend of $25 million, resulted in a reduction of GKP's cash balance from $119.5 million at 31 December 2022 to $81.7 million at 31 December 2023.

 

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 and pricing cannot be predicted, based on which the Directors have a reasonable expectation that the Group has adequate resources to continue to operate for twelve months. Therefore, the going concern basis of accounting is used to prepare the financial statements.

 

Net entitlement

 

The Company shares Shaikan Field revenues with the KRG and our partner MOL, based on the terms of the Shaikan Production Sharing Contract. GKP's net entitlement includes the recovery of our investment in the Shaikan Field through cost oil and a share of the profits through profit oil, less a Capacity Building Payment owed to the KRG. The Company's net entitlement of gross Shaikan Field sales was 36% in 2023 and as at 31 December 2023.

 

The unrecovered cost oil and R-factor are used to calculate monthly cost oil and profit oil entitlements, respectively, owed to the Company from crude oil sales. As at 31 December 2023, there was $224 million of gross unrecovered cost oil, subject to potential cost audit by the KRG. The R-factor, calculated as cumulative gross revenue receipts of $2,219 million divided by cumulative gross costs of $1,878 million, was 1.18.

 

Outlook

 

To date in 2024, gross average sales volumes have averaged c.33,300 bopd at an average realised price of c.$25/bbl, enabling us to cover our monthly capex and costs and pay all overdue invoices, resulting in a roughly halving of accounts payable of $26 million that were outstanding at year-end.

 

Looking ahead to the remainder of 2024, the Company remains focused on maximising local sales and minimising costs to further improve our liquidity position.

 

We expect to maintain the aggregate net capex, operating costs and other G&A monthly run rate at or below c.$6 million in 2024 and continue to review further cost reduction opportunities. Estimated 2024 net capex of c.$20 million comprises safety critical upgrades and production maintenance expenditures, while gross Opex per barrel guidance remains suspended. We continue to retain the operational capability to maximise local sales and capitalise on a resumption of exports.

 

We continue to believe the distribution of excess cash by way of dividends or share buybacks is important to reward shareholders. As the operating environment and the Company's liquidity position improve, we will keep under review our capability to reinstate distributions.

 

Ian Weatherdon

Chief Financial Officer

 

20 March 2024

 

 

Non-IFRS measures

 

The Group uses certain measures to assess the financial performance of its business. Some of these measures are termed "non-IFRS measures" because they exclude amounts that are included in, or include amounts that are excluded from, the most directly comparable measure calculated and presented in accordance with IFRS, or are calculated using financial measures that are not calculated in accordance with IFRS. These non‑IFRS measures include financial measures such as operating costs and non-financial measures such as gross average production.

 

The Group uses such measures to measure and monitor operating performance and liquidity, 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, the equivalent measures calculated and presented in accordance with IFRS or those calculated using financial measures that are calculated in accordance with IFRS.

 

Gross operating costs per barrel

Gross operating costs are divided by gross production to arrive at operating costs per barrel.

 

	2023	2022
Gross production (MMbbls)	8.0	16.1
Gross operating costs ($ million)(1)	45.1	52.3
Gross operating costs per barrel ($ per bbl)	5.6	3.2

 

⁽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, which excludes the impact of costs attributable to tax (expense)/credit, finance costs, finance revenue, depreciation, amortisation and impairment of receivables.

 

	2023 $ million	2022 $ million
(Loss)/profit after tax	(11.5)	266.1
Finance costs	1.8	9.7
Finance revenue	(3.8)	(0.6)
Tax (charge)/credit	0.1	(0.3)
Depreciation of oil and gas assets	39.5	80.2
Depreciation of other PPE assets and amortisation of intangibles	2.6	1.4
Impairment of receivables	21.4	2.0
Adjusted EBITDA	50.1	358.5

 

Net cash

Net cash is a useful indicator of the Group's financial flexibility because it indicates the level of cash and cash equivalents less cash borrowings within the Group's business. Net cash is defined as cash less borrowings.

	2023 $ million	2022 $ million
Cash	81.7	119.5
Borrowings	-	-
Net cash	81.7	119.5

 

The Company was debt free at 31 December 2023 and 31 December 2022.

 

 

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.

	2023 $ million	2022 $ million
Net capital expenditure (note 10 to the consolidated financial statements)	58.2	114.9

 

Free cash flow

Free cash flow represents the Group's cash flows, before any dividends, share buybacks and notes redemption, including related fees.

	2023 $ million	2022 $ million
Net cash generated from operating activities	51.3	374.3
Net cash used in investing activities	(63.9)	(107.4)
Payment of leases	(0.5)	(0.4)
Free cash flow	(13.1)	266.5

 

Consolidated income statement

For the year ended 31 December 2023

 

	Notes	2023	2022
		$'000	$'000
Revenue	2	123,514	460,113
Cost of sales	3	(93,953)	(158,651)
Increase of expected credit loss provision on trade receivables	13	(21,378)	(1,960)
Gross profit		8,183	299,502
Other general and administrative expenses	4	(10,466)	(12,202)
Share option related expenses	5	(10,760)	(13,756)
(Loss)/profit from operations		(13,043)	273,544
Finance income	7	3,803	648
Finance costs	7	(1,765)	(9,655)
Foreign exchange (loss)/gain		(384)	1,232
(Loss)/profit before tax		(11,389)	265,769
Tax (charge)/credit	8	(111)	325
(Loss)/profit after tax for the year		(11,500)	266,094
(Loss)/profit per share (cents)
Basic	9	(5.28)	123.52
Diluted	9	(5.28)	118.62

 

 

Consolidated statement of comprehensive income

For the year ended 31 December 2023

 

		2023	2022
		$'000	$'000
(Loss)/profit after tax for the year		(11,500)	266,094
Items that may be reclassified to the income statement in subsequent periods:
Exchange gain/(loss) on translation of foreign operations		952	(1,950)
Total comprehensive (loss)/income for the year		(10,548)	264,144

 

Consolidated balance sheet

As at 31 December 2023

	Notes	31 December 2023	31 December 2022
		$'000	$'000
Non-current assets
Trade receivables	13	140,218	-
Intangible assets		2,813	4,307
Property, plant and equipment	10	445,842	436,443
Deferred tax asset	17	1,545	1,576
		590,418	442,326
Current assets
Inventories	12	9,901	6,372
Trade and other receivables	13	15,118	176,203
Cash		81,709	119,456
		106,728	302,031
Total assets		697,146	744,357
Current liabilities
Trade and other payables	14	(109,394)	(128,561)
Deferred income	14	(5,164)	-
		(114,558)	(128,561)
Non-current liabilities
Trade and other payables	14	(39)	(325)
Provisions	16	(35,312)	(42,546)
		(35,351)	(42,871)
Total liabilities		(149,909)	(171,432)
Net assets		547,237	572,925
Equity
Share capital	19	222,443	216,247
Share premium	19	503,312	528,125
Exchange translation reserve		(3,766)	(4,718)
Accumulated losses		(174,752)	(166,729)
Total equity		547,237	572,925

 

 

The financial statements were approved by the Board of Directors and authorised for issue on 20 March 2024 and signed on its behalf by:

 

Jon Harris

Chief Executive Officer

 

Ian Weatherdon

Chief Financial Officer

Consolidated statement of changes in equity

For the year ended 31 December 2023

 

		Attributable to equity holders of the Company
Notes		Share capital	Share premium	Exchange translation reserve	Accumulated losses	Total equity
		$'000	$'000	$'000	$'000	$'000
Balance at 1 January 2022		213,731	742,914	(2,768)	(432,173)	521,704
Profit after tax for the year		-	-	-	266,094	266,094
Exchange difference on translation of foreign operations		-	-	(1,950)	-	(1,950)
Total comprehensive income for the year		-	-	(1,950)	266,094	264,144
Dividends paid	24	-	(214,789)	-	-	(214,789)
Employee share schemes	23	-	-	-	1,866	1,866
Share issues	19	2,516	-	-	(2,516)	-
Balance at 31 December 2022		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 operations		-	-	952	-	952
Total comprehensive loss for the year		-	-	952	(11,500)	(10,548)
Dividends paid	24	-	(24,813)	-		(24,813)
Employee share schemes	23	-	-	-	9,673	9,673
Share issues	19	6,196	-	-	(6,196)	-
Balance at 31 December 2023		222,443	503,312	(3,766)	(174,752)	547,237

 

Consolidated cash flow statement

For the year ended 31 December 2023

 

	Notes	2023 $'000	2022 $'000
Operating activities
Cash generated from operations	20	47,520	383,846
Interest received	7	3,803	648
Interest paid	15	-	(10,194)
Net cash generated from operating activities		51,323	374,300
Investing activities
Purchase of intangible assets		-	(2,074)
Purchase of property, plant and equipment	20	(65,386)	(105,291)
Sale of drilling stock		1,449	-
Net cash used in investing activities		(63,937)	(107,365)
Financing activities
Payment of dividends	24	(24,813)	(214,789)
Payment of leases	21	(503)	(458)
Notes redemption	15	-	(100,000)
Notes repayment fee	15	-	(2,000)
Net cash used in financing activities		(25,316)	(317,247)
Net decrease in cash		(37,930)	(50,312)
Cash at beginning of year		119,456	169,866
Effect of foreign exchange rate changes		183	(98)
Cash at end of the year being bank balances and cash on hand		81,709	119,456

Summary of material accounting policies

 

General information

Gulf Keystone Petroleum Limited (the "Company") is domiciled and incorporated in Bermuda (registered address: Cedar House, 3rd Floor, 41 Cedar Avenue, Hamilton, HM12, 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. Previously, the Company was quoted on Alternative Investment Market, a market operated by the London Stock Exchange. The Company serves as the holding 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 2022 or 2023 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 2023.

 

The following new accounting standards, amendments to existing standards and interpretations are effective on 1 January 2023: IFRS 17 Insurance Contracts, Disclosure of Accounting Policies (Amendments to IAS 1 and IFRS Practice Statement 2), Definition of Accounting Estimates (Amendments to IAS 8), Deferred Tax related to Assets and Liabilities arising from a Single Transaction (Amendments to IAS 12), Initial Application of IFRS 17 and IFRS 9 - Comparative Information (Amendment to IFRS 17). 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
Amendments to IAS 1	Classification of Liabilities as Current or Non-current; Classification of Liabilities as Current or Non-current - Deferral of Effective Date; Non-current Liabilities with Covenants
Amendments to IFRS 16	Lease Liability in a Sale and Leaseback
Amendments to IAS 7 and IFRS 7	Qualitative and quantitative information about supplier finance arrangements.
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 standards	Amendments to the SASB standards to enhance their international applicability without 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.

 

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 Chairman's statement, the Chief Executive Officer's review, the Operational 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 20 March 2024 the Group had $86 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 closure of the ITP, the Group significantly reduced expenditures to preserve liquidity. In the current year, further consideration has been given to the impact on the Group's working capital position due to a potential decline in local sales, and potential delays in KRG revenue receipts once the ITP has been reopened:

 

·      Local sales: The Group commenced local sales on 19 July 2023 with payments from buyers required in advance following extensive due diligence. In 2023 the Group received $43.5m related to local sales. Local sales volumes have fluctuated and remain difficult to predict, and

·      Export sales: While political negotiations and commercial negotiations are ongoing between the Government of Iraq and the KRG, the timing of reopening the ITP and payment mechanism remain uncertain.

 

The Directors believe an agreement will ultimately be reached to reopen the ITP, and we 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 $75 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 2023 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 Kurdistan Regional Government ("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.

 

Prior to the shut-in of the Iraq-Turkey pipeline ("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. For sales to the local market from 19 July 2023, 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.

 

Effective September 1, 2022, the KRG proposed a new pricing mechanism for crude oil export sales, which continued in the year 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, Turkey, 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 has been in place since 1 September 2022. 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 as such has 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 revenue

Finance income is recognised on an accruals basis, by reference to the principal outstanding and at the effective rate of interest applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount on initial recognition.

 

Intangible assets

Intangible assets include computer software and are measured at cost and amortised over their expected useful economic lives of three years.

 

Property, plant and equipment ("PPE")

 

Oil and gas assets

Development and production assets

Development and production assets are accumulated on a field-by-field basis and represent the costs of acquisition and developing the commercial reserves discovered and bringing them into production, together with the exploration and evaluation expenditure incurred in finding commercial reserves, directly attributable overheads and costs for future restoration and decommissioning. These costs are capitalised as part of PPE and depreciated based on the Group's depreciation of oil and gas assets policy.

 

The net book values of producing assets are depreciated generally on a field-by-field basis using the unit of production ("UOP") basis which uses the ratio of oil and gas production in the period to the remaining commercial reserves plus the production in the period. Costs used in the calculation comprise the net book value of the field and estimated future development expenditures required to produce those reserves.

 

Commercial reserves are proven and probable ("2P") reserves which are estimated using standard recognised evaluation techniques. The reserves estimate used in the depreciation, depletion and amortisation ("DD&A") calculation in 2023 was based on the December 2022 Competent Person's Report ("CPR") reserves report completed by ERC Equipoise as at 31 December 2022.

 

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.

 

Borrowing costs

Borrowing costs directly relating to the acquisition or construction of qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, are capitalised and added to the cost of those assets, until such time as the assets are substantially ready for their intended use or sale.

 

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

 

All other borrowing costs are recognised in the income statement in the period in which they are incurred.

 

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 expected credit losses is updated at each reporting date to reflect changes in credit risk since initial recognition of the respective financial instrument.

 

The Group recognises lifetime expected credit losses for trade receivables, contract assets and lease receivables. The expected credit losses 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 expected credit losses that will result from all possible default events over the expected life of a financial instrument. 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.

 

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.

 

Borrowings

Interest-bearing loans and overdrafts are recorded at the fair value of proceeds received, net of transaction costs. Finance charges, including premiums payable on settlement or redemption, are accounted for on an accrual basis and are added to the carrying amount of the instrument to the extent that they are not settled in the year in which they arise. The liability is carried at amortised cost using the effective interest rate method until maturity.

 

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 and others providing similar services 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 24. 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 24.

 

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.

 

PSC 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 preparing the 2023 financial statements is that it is appropriate to recognise export revenue for deliveries from 1 January to 25 March 2023 based on the proposed new pricing mechanism, notwithstanding that there is no signed lifting agreement for that period and the pricing mechanism has not yet been agreed. 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.

 

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 Company 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 Company.

 

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.

 

The Company expects to confirm with the MNR whether to proceed with a formal amendment to the PSC to reflect current invoice terms.

 

Key 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 gives the ECL. In making this judgement, management has estimated the timing of the receipt of receivables which will be dependent upon uncertain future events, in particular the expected timing of the re-opening of the ITP. Management have considered scenarios for recovering receivables and assigned probabilities to these scenarios. A weighted average has been applied to receipt profiles, upon which a counterparty default allowance has been applied to derive 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. 

 

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 Company commissioned ERC Equipoise to perform an assessment of the Company's estimate of the current value of such obligations and costs at 31 December 2023 (2022: internal estimate). 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 (note 16), there is also uncertainty regarding the inflation and discount rates used.

 

Carrying value of producing assets

In line with the Group's accounting policy on impairment, management performs an impairment review of the Group's oil and gas assets at least annually with reference to indicators as set out in IAS 36. 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, PSC commercial terms, cost recovery, estimated production volumes, the timing of revenue receipts and field development activities, the cost of development and production, potential climate change transition risk impacts, pre-tax discount rate that incorporate risks specific to the asset and inflation. The key assumptions are subject to change based on geopolitical factors, 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 2023 was the Shaikan Field with a carrying value, being Oil and Gas assets less capitalised decommissioning provision, of $408.0 million (2022: $391.0 million). The Group performed an impairment trigger assessment and concluded that the shutdown of the Iraq Turkey Pipeline ("ITP") in March 2023 following the ITP Arbitration ruling was a potential indicator of impairment. Accordingly, an impairment evaluation was completed, and it was concluded that no impairment write-down was required.

 

In accordance with accounting standards, the impairment assessment was prepared based on available information combined with management estimates as at 31 December 2023. This includes a number of key assumptions, some of which have a high degree of uncertainty. 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, the impairment calculation base case assumes that local sales contracts, whilst short-term in nature, will continue until the ITP reopens and exports resume in October 2024. Given the reopening date remains uncertain, we have applied sensitivities of up to a further two-year delay in the re-opening of the ITP and no impairment was identified except under the Net Zero Emissions climate scenario as described below;

·     The Group's netback oil price was based on the forward curve and market participants' consensus, including banks, analysts and independent reserves evaluators, as at 31 December 2023 for the period 2024 to 2029 with inflation of 2.25% per annum thereafter, less transportation costs and quality adjustments. Prices at 31 December 2022 were based on the dated brent forward curve as at December 2022 for the period 2023 to 2028 with inflation of 2% per annum thereafter, less transportation and quality adjustments. The stress case reflects a 10% reduction in base case oil prices;

 

Scenario ($/bbl - nominal)	2023	2024	2025	2026	2027	2028	2029
31 December 2023 - base case	n/a	83.0	80.0	77.0	77.0	77.0	80.0
31 December 2023 - stress case	n/a	74.7	72.0	69.3	69.3	69.3	72.0
31 December 2022 - base case	83.4	78.2	74.5	71.7	69.6	68.1	69.5
31 December 2022 - stress case	75.1	70.4	67.1	64.5	62.6	61.3	62.5

 

·     Cost assumptions used in the assessment were based on an updated Jurassic development plan commencing in 2025 and the estimated cost of a Gas Management Plan with investment commencing in 2026. Further development remains contingent upon the reopening of the ITP and normalisation of KRG payments. Cost assumptions incorporated management's experience and expectations, including the nature and location of the operations and the associated risks. The impact of near-term inflationary pressures were also considered and no impairment was identified;

·     The Group continues to develop its assessment of the potential impacts of climate change and the associated risks of the transition to a low‑carbon future. Our ambition to reduce scope one per barrel CO₂ emissions by at least 50% versus the original 2020 baseline of 38 kgCO₂e per barrel is dependent on the timing of sanction and implementation of the Gas Management Plan. The International Energy Agency's ("IEA") most recent Announced Pledges Scenario ("APS") and Net Zero Emissions ("NZE") climate scenario oil prices and carbon taxes were used to evaluate the potential impact of the principal climate change transition risks. The APS scenario assumes that governments will meet, in full and on time, all of the climate‑related commitments that they have announced, including longer term net zero emissions targets and pledges in Nationally Determined Contributions ("NDCs") to reduce national emissions and adapt to the impacts of climate change leading to a global temperature rise of 1.7°C in 2100. NZE is the normative scenario pathway to the stabilisation of global average temperatures at 1.5°C above pre‑industrial levels. Under the APS and NZE scenarios there was no impairment. However, while the IEA oil price assumptions incorporate carbon prices, it has not disclosed the assumed average carbon intensity per barrel of production. Therefore, the Group has performed a sensitivity to conservatively include IEA carbon pricing on all production which results in no impairment under the APS scenario. Under the NZE scenario, there was a potential impairment; however, if the Group's assumed future average carbon intensity per barrel of production is in fact at or below the undisclosed IEA carbon intensity per barrel of production, there would have been no impairment;

·     Discount rates that are adjusted to reflect risks specific to the Shaikan Field and the Kurdistan Region of Iraq. The post-tax nominal discount rate was estimated to be 16% (2022: 15%). The impact of an increase in discount rate to 20% was considered as a sensitivity to reflect potential increased geopolitical risks and no impairment was identified;

·     Commercial reserves and production profiles used are based on internal estimates; and

·     Timing of revenue receipts.

Notes to the consolidated financial statements

 

1. Geographical information

The Chief Operating Decision Maker, as per the definition in IFRS 8, 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% (2022: 99%) of the group's non-current assets, excluding deferred tax assets and other financial assets, are located in the KRI. The financial information of the single segment is materially the same as set out in the condensed consolidated statement of comprehensive income, the condensed consolidated balance sheet, the condensed consolidated statement of changes in equity, the condensed consolidated cash flow statement and the related notes.

 

2. Revenue

	2023 $'000	2022 $'000
Oil sales via export pipeline	78,955	460,113
Local oil sales	44,559	-
	123,514	460,113

 

The Group's accounting policy for revenue recognition is set out in the 'Summary of significant accounting policies', with revenue recognised upon crude oil passing the delivery points, either being entry into pipeline or delivered into trucks.

 

Oil sales via export pipeline (until 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.

 

Since 1 September 2022, there has been no lifting agreement in place between the Shaikan Contractor and the KRG. The KRG proposed a new pricing mechanism based upon the average monthly Kurdistan blend ("KBT") sales price realised by the KRG at Ceyhan; formerly the pricing mechanism was based upon Dated Brent. The Company 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 Company 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 Kurdistan blend ("KBT") price. The realised price in this period was $51.3/bbl (2022: full year $84.3/bbl).

 

The revenue impact of using the proposed KBT pricing mechanism instead of Dated Brent for the year is estimated to be a reduction of $12.0 million (2022: $23.4 million). Taking into account the associated reduction in capacity building payments results in a total reduction of profit after tax for the year of $11.4 million (2022: $21.7 million). Any difference between the proposed and final pricing mechanism will be reflected in future periods.

 

Local oil sales (from 19 July 2023)

In July 2023, GKP began selling oil to local buyers at negotiated prices. The realised price achieved in 2023 was $30/bbl (2022: not applicable). Local buyers pay GKP in advance of receipt of oil; such amounts are recognised as deferred income (see note 14).

 

Information about major customers

In 2023, 68% (2022: 100%) of oil sales were made to the KRG. Additionally, 31% of revenue (2022: 0%) was attributable to three local customers comprising 10%, 10% and 11% of revenue individually. 

 

3. Cost of sales

	2023 $'000	2022 $'000
Operating costs	36,082	41,835
Capacity building payments	8,872	34,927
Change in oil inventory value	(75)	555
Depreciation of oil and gas assets and operational assets	39,470	80,225
Contract termination costs	5,525	-
Provision against inventory held for sale	2,627	-
Loss on disposal of drilling stock	1,452	-
Impairment of surplus drilling stock	-	1,109
	93,953	158,651

 

Capacity building payments 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.

 

Further details on the 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 significant accounting policies section.

 

For purposes of calculating the DD&A per barrel of production in 2023, a Competent Person's Report from ERC Equipoise Limited with 2P reserves estimates at 31 December 2022 was used in conjunction with the Group's economic forecasts to determine entitlement production, commercial reserves and capital costs for Shaikan.

 

Following ITP shut-in, GKP reacted quickly to preserve liquidity and significantly reduce expenditures. This led to the termination of certain contracts, drilling stock sales less than carrying value and a provision for inventory items held for sale.

 

4. Other general and administrative expenses

	2023 $'000	2022 $'000
Depreciation and amortisation	2,652	1,563
Auditor's remuneration (see below)	635	703
Other general and administrative costs	7,179	9,936
	10,466	12,202

 

Of the $10.5 million (2022: $12.2 million) of general and administrative expenses, $3.4 million (2022: $5.2 million) were incurred in relation to the Shaikan Field.

 

	2023 $'000	2022 $'000
Fees payable to the Company's auditor for the audit of the Company's annual accounts	474	430
Fees payable to the Company's auditor for other services to the Group
- audit of the Company's subsidiaries pursuant to legislation	26	26
Total audit fees	500	456
Advisory services	-	112
Other assurance services (including a half year review)	135	135
Total fees	635	703

 

5. Share option related expense

	2023 $'000	2022 $'000
Share-based payment expense	9,673	3,266
Payments related to share options exercised	797	8,690
Share-based payment related provision for taxes	290	1,800
	10,760	13,756

 

The 2022 payments related to share options exercised includes the final year of the legacy Value Creation Plan ("VCP") share options awarded to former Directors. There will be no further awards under the plan.

 

6. Staff costs

The average number of employees and contractors (including Executive directors) employed by the Group was 471 (2022: 460); the number of full-time equivalents of these workers was 303 (2022: 317), reflecting the increase in staff in 2022 to progress expansion activities and the decrease in staff after the ITP was shut-in on 25 March 2023.

 

	Average number of employees		Average number of full-time equivalents		Number of employees in December		Number of full-time equivalents in December
	2023	2022	2023	2022	2023	2022	2023	2022
Kurdistan	438	421	272	280	379	472	247	312
United Kingdom	33	39	31	37	27	40	26	38
Total	471	460	303	317	406	512	273	350

 

 

Staff costs as follows are shown net of amounts recharged to joint operations:
	2023 $'000	2022 $'000
Wages and salaries	37,645	46,879
Social security costs	1,826	2,503
Pension costs	468	420
Share-based payment (see note 23)	10,760	4,260
	50,699	54,062

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

	2023 $'000	2022 $'000
Notes interest expense (see note 15)	-	(5,833)
Unwinding of finance and arrangement fees (see note 15)	-	(879)
Notes repayment fee (see note 15)	-	(2,000)
Finance lease interest	(66)	(77)
Unwinding of discount on provisions (see note 16)	(1,699)	(866)
Total finance costs	(1,765)	(9,655)
Finance income	3,803	648
Net finance income/(costs)	2,038	(9,007)

 

Since redemption of $100m notes on 2 August 2022, the Group has remained debt free (see note 15).  

 

8. Income tax

	2023 $'000	2022 $'000
Current year credit	-	216
Prior year adjustment	195	-
Deferred UK corporation tax (charge)/credit (see note 17)	(306)	109
Tax (charge)/credit attributable to the Company and its subsidiaries	(111)	325

 

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 year ended 31 December 2023 was 19% on profits up to £50k tapered to 25% on profits above £250k (2022: flat rate of 19.0%).

 

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 loss per share is based on the following data:

	2023	2022
(Loss)/profit after tax for basic and diluted per share calculations ($'000)	(11,500)	266,094
Number of shares ('000s):
Basic weighted average number of ordinary shares	217,992	215,420
Basic EPS (cents)	(5.28)	123.52

The Group followed the steps specified by IAS 33 in determining whether potential common shares are dilutive or anti-dilutive.

 

Reconciliation of dilutive shares:

	2023	2022
Number of shares ('000s)
Basic weighted average number of ordinary shares outstanding	217,992	215,420
Effect of potential dilutive share options	-	8,909
Diluted number of ordinary shares outstanding	217,992	224,329
Diluted EPS (cents)(1)	(5.28)	118.62

 

⁽¹⁾ At the reporting date, the Company had 8,224k antidilutive (2022: 8,909k dilutive) ordinary shares relating to outstanding share options. EPS is calculated on the assumption of conversion of all potentially dilutive ordinary shares however, during a period where a company makes a loss, anti-dilutive shares are not included in the loss per share calculation as they would reduce the reported loss per share.

 

The weighted average number of ordinary shares in issue excludes shares held by Employee Benefit Trustee ("EBT").  

 

10. Property, plant and equipment

	Oil and gas assets $'000	Fixtures and equipment $'000	Right of use assets $'000	Total     $'000
Year ended 31 December 2022
Opening net book value	402,094	1,033	1,078	404,205
Additions	114,909	1,595	-	116,504
Impairment of surplus drilling stocks	(1,109)	-	-	(1,109)
Revision to decommissioning asset	(2,161)	-	-	(2,161)
Depreciation charge	(80,177)	(359)	(347)	(80,883)
Foreign currency translation differences	-	(12)	(101)	(113)
Closing net book value	433,556	2,257	630	436,443
At 31 December 2022
Cost	943,563	8,946	2,145	954,654
Accumulated depreciation	(510,007)	(6,689)	(1,515)	(518,211)
Net book value	433,556	2,257	630	436,443
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

 

The net book value of oil and gas assets at 31 December 2023 is comprised of property, plant and equipment relating to the Shaikan block with a carrying value of $443.4 million (2022: $433.6 million).

 

The additions to the Shaikan asset amounting to $58.2 million during the year include the costs of completing SH-17 and the drilling and completion of SH-18, well workovers, well pad preparation, long lead items and expansion of production facilities.

 

The decrease in the decommissioning asset represents the change in accounting estimates as detailed in note 16 partially offset by additional decommissioning liabilities arising from capital projects completed during the year.

 

The DD&A charge of $39.5 million (2022: $80.2 million) on oil and gas assets has been included within cost of sales (note 3). The depreciation charge of $0.6 million (2022: $0.4 million) on fixtures and equipment and $0.4 million (2022: $0.3 million) on right of use assets has been included in general and administrative expenses (note 4).

 

Right of use assets at 31 December 2023 of $0.4 million (2022: $0.6 million) consisted principally of buildings.

 

For details of the key assumptions and judgements underlying the impairment assessment, refer to the "Critical accounting estimates and judgements" section of the Summary of significant accounting policies.

 

11. Group companies

Details of the Company's subsidiaries and joint operations at 31 December 2023 is as follows:

 

Name of subsidiary	Place of incorporation	Proportion of ownership interest	Principal activity
Gulf Keystone Petroleum (UK) Limited 6th floor New Fetter Place 8-10 New Fetter Lane London EC4A 1AZ	United Kingdom	100%	Management, support, geological, geophysical and engineering services
Gulf Keystone Petroleum International Limited Cedar House, 3rd Floor 41 Cedar Avenue Hamilton HM12 Bermuda	Bermuda	100%	Exploration, evaluation, development and production activities in Kurdistan

 

Name of joint operation	Location	Proportion of ownership interest	Principal activity
Shaikan	Kurdistan	80%	Production and development activities

 

12. Inventories

	2023 $'000	2022 $'000
Warehouse stocks and materials	6,900	6,074
Crude oil	374	298
Inventory held for sale	2,627	-
	9,901	6,372

 

13. Trade and other receivables

Non-current receivables

	2023 $'000	2022 $'000
Trade receivables - non-current	140,218	-

 

Non-current trade receivables relates 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 below).

 

Current receivables

	2023 $'000	2022 $'000
Trade receivables	6,350	158,032
Underlift	3,806	-
Other receivables	3,080	16,828
Prepayments and accrued income	1,882	1,343
Total current receivables	15,118	176,203
Total receivables	155,336	176,203

Underlift is the volumes owed to the Company by the KRG who lifted volumes in excess of their contractual entitlement in accordance with the PSC. The underlift is valued at the year-end sales price. The underlift was temporary and the group lifted the volumes in 2024.

 

Reconciliation of Trade Receivables

		2023 $'000		2022 $'000
Gross carrying amount	171,026				161,112
Less: Impairment allowance	(24,458)				(3,080)
Carrying value at 31 December	146,568				158,032

 

Gross trade receivables of $171.0 million (2022: $161.1 million) are comprised of invoiced amounts due, based upon KBT pricing, from the KRG for crude oil sales totalling $158.8 million (2022: $148.9 million) related to October 2022 - March 2023 and a share of Shaikan amounts due from the KRG that the Group purchased from MOL amounting to $12.2 million (2022: $12.2 million). Trade receivables net of capacity building payments payable of $7.7 million (2022: $7.1 million) are $151.1 million (2022: $141.8 million).

 

While the Group expects to recover the full value of the outstanding invoices and purchased revenue arrears, an ECL of $24.5 million (2022: $3.1 million) was provided against the trade receivables balance in accordance with IFRS 9. During the year, a $21.4 million charge was recognised due to the increase in the ECL provision (2022: $2.0 million).

 

As detailed in the Summary of significant 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 receipt profile scenarios, the only variable expected to materially change profit before tax is the timing of receipt. If the pipeline reopening is delayed beyond October 2024 resulting in the receipt of past-due trade receivables being delayed by a further 12 months, then the ECL would increase by $10.7 million. Conversely, if the repayment profile was brought forward by 6 months then the ECL would decrease by $6.2 million.

The Group's profit before tax was not materially sensitive to a movement of ±10% in the default spread or recovery rate.

Other receivables

 

Other receivables includes an amount relating to advances to suppliers of $0.4 million (FY 2022: $11.5 million). $0.4 million (FY 2022: $10.6 million of the $11.5 million) relates to advances for capital expenditure and is included within investing activities in the consolidated cash flow statement.

 

Also included within Other receivables is an amount of $0.4 million (2022: $0.4 million) being the deposits for leased assets which are receivable after more than one year. There are no receivables from related parties as at 31 December 2023 (2022: nil). No impairments of other receivables have been recognised during the year (2022: nil).

 

14. Current liabilities

Trade and other payables

	2023 $'000	2022 $'000
Trade payables	11,953	3,499
Accrued expenditures	14,009	40,642
Amounts due to KRG not expected to be cash settled	74,703	70,740
Capacity building payment due to KRG on trade receivables	7,687	7,131
Other payables	683	6,164
Lease obligations	359	385
Total trade and other payables	109,394	128,561

 

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.

 

Amounts due to KRG not expected to be cash settled of $74.7 million (2022: $70.7 million) include:

·      $37.7 million (2022: $36.5 million) expected to be offset against oil sales to the KRG up to 2018, that have not been recognised in the financial statements as management consider that the criteria for revenue recognition have not been satisfied.

·      $37.0 million (2022: $34.2 million) related to an accrual for the difference between the capacity building rate of 20%, as per the invoicing basis in effect since October 2017, and 30% as per the 2016 Bilateral Agreement. The working interest under the 2016 bilateral agreement is 80% whereas the invoicing basis is 61.5%. If the commercial position were to revert to the full terms of the executed amended PSC and the 2016 Bilateral Agreement, the Company would not expect to cash settle this balance as a more than offsetting increase in GKP's net entitlement is expected to result in revenue being due to GKP (see critical accounting judgements), the value of which is expected to exceed the accrued $37.0 million.

 

Deferred income

 

At 31 December 2023, deferred income of $5.2 million (2022: $nil) relates to cash advances paid by local oil buyers in advance of lifting oil (See note 2).

 

Non-current liabilities

	2023 $'000	2022 $'000
Non-current lease liability (see note 21)	39	325

 

15. Long term borrowings

	2023 $'000	2022 $'000
Liability component at 1 January	-	103,482
Interest expense, including unwinding of finance & arrangement fees	-	8,712
Interest paid during the year	-	(10,194)
Principal repaid in year	-	(100,000)
Settlement of notes early repayment fee	-	(2,000)
Liability component at 31 December	-	-

 

On 2 August 2022 the Group redeemed the $100m bond and paid a 2% early repayment fee.

 

16. Provisions

Decommissioning provision	2023 $'000	2022 $'000
At 1 January	42,546	43,841
New provisions and changes in estimates	(8,933)	(2,161)
Unwinding of discount	1,699	866
At 31 December	35,312	42,546

 

The $8.9 million decrease in new provisions and changes in estimates (2022: $2.2 million) comprises an increase relating to new drilling and facilities work of $4.2 million (2022: $7.6 million), offset by a reduction of $13.1 million (2022: $9.8 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 in line with the table below and discounted at 4.6% (2022: 3.8%), 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.

 

	Annual Inflation Assumption (%)
	2023	2022
2023	n/a	5.00%
2024	2.25%	3.00%
2025	2.25%	2.75%
2026 - 2043	2.25%	2.75%

 

17. 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.

 

	Accelerated tax depreciation $'000	Share-based payments   $'000	Tax losses carried forward $'000	Total     $'000
At 1 January 2022	(495)	1,049	831	1,385
(Charge)/credit to income statement	(139)	241	223	325
Exchange differences	62	(109)	(87)	(134)
At 31 December 2022	(572)	1,181	967	1,576
Credit/(charge) to income statement	882	(741)	(447)	(306)
Exchange differences	(17)	42	250	275
At 31 December 2023	293	482	770	1,545

 

18. Financial instruments

	2023 $'000	2022 $'000
Financial assets
Cash	81,709	119,456
Receivables	152,709	162,990
	234,418	282,446
Financial liabilities
Trade and other payables	109,433	128,886
	109,433	128,886

 

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 $24.5 million provision against trade receivables (2022: $3.1 million) (see note 13). All financial assets, except derivatives designated as a hedge, 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 prior year) and equity attributable to equity holders of the parent. Equity comprises issued capital, reserves and accumulated losses as disclosed in note 20 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.

 

Significant Accounting Policies

Details of the significant 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 significant 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 2023, 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 2023, the maximum exposure to credit risk from a trade receivable outstanding from one customer is $171.0 million (2022: $161.1 million). Although the Group is confident in the recovery of the trade receivables balance, a provision of $24.5 million (2022: $3.1 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.

19. Share capital

	2023 $'000	2022 $'000
Authorised
Common shares of $1 each	292,105	231,605
Non-voting shares of $0.01 each	-	500
Preferred shares of $1,000 each	-	20,000
Series A Preferred shares of $1,000 each	-	40,000
	292,105	292,105

 

	Common shares
	No. of shares	Share capital	Share premium	Total amount
	'000	$'000	$'000	$'000
Balance 1 January 2022	213,731	213,731	742,914	956,645
Dividends paid	-	-	(214,789)	(214,789)
Shares issued	2,516	2,516	-	2,516
Balance 31 December 2022	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

 

 

At 31 December 2023, a total of 0.2 million common shares at $1 each were held by the EBT (2022: 0.4 million at $1 each). These common shares were included within reserves.

 

Rights attached to share capital

The holders of the common shares have the following rights (subject to the other provisions of the Byelaws):

 

(i)	entitled to one vote per common share;
(ii)	entitled to receive notice of, and attend and vote at, general meetings of the Company;
(iii)	entitled to dividends or other distributions; and
(iv)	in the event of a winding-up or dissolution of the Company, whether voluntary or involuntary or for a reorganisation or otherwise or upon a distribution of capital, entitled to receive the amount of capital paid up on their common shares and to participate further in the surplus assets of the Company only after payment of the Series A Liquidation Value (as defined in the Byelaws) on the Series A Preferred Shares.

20. Cash flow reconciliation

		2023	2022
	Notes	$'000	$'000
Cash flows from operating activities
(Loss)/profit from operations		(13,043)	273,544
Adjustments for:
Depreciation, depletion and amortisation of property, plant and equipment (including the right of use assets)		40,409	80,883
Amortisation of intangible assets		1,648	859
Increase of provision for impairment of trade receivables	13	21,378	1,960
Share-based payment expense	23	9,673	1,866
Provision against inventory held for sale	3	2,627	-
Impairment of PPE items	3	-	1,109
Operating cash flows before movements in working capital		62,692	360,221
Increase in inventories		(7,605)	(354)
Decrease/(Increase) in trade and other receivables		(10,741)	11,640
Increase in trade and other payables		3,107	12,339
Income taxes received		67	-
Cash generated from operations		47,520	383,846

 

Reconciliation of property, plant and equipment additions to cash flows from purchase of property, plant and equipment:

	2023 $'000	2022 $'000
Associated cash flows
Additions to property, plant and equipment	58,652	116,617
Movement in working capital	6,764	(11,214)
Non-cash movements
Foreign exchange differences	(30)	(112)
Purchase of property, plant and equipment	65,386	105,291

 

​

21. Lease Liabilities

During 2023, the total cash outflows relating to leased assets was $0.5 million (2022: $0.5 million); this amount is the total of capital repayments, interest charges and foreign exchange impact.

	2023 $'000	2022 $'000
Current liabilities (note 14)	359	385
Non-current liabilities (note 14)	39	325
	398	710
Lease liability maturity analysis
Year 1	359	385
Year 2	19	325
Year 3	20	-
Amounts payable under leases
Within one year	377	436
In the second to fifth year inclusive	42	339
	419	775
Less future interest charges	(21)	(65)
Net present value of lease obligations	398	710

 

 

22. 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 2023, gross capital commitments in relation to the Shaikan Field were estimated to be $2.2 million (2022: $41.9 million).

 

23. Share-based payments

	2023 $'000	2022 $'000
Total share options charge	9,673	3,266

 

The share options charge of $9.6 million is comprised of $9.1 million (2022: $3.1 million) related to the LTIP plan and $0.6 million (2022: nil) 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 Long Term Incentive Plan ("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.

	2023 Number of share options '000	2022 Number of share options '000
Outstanding at 1 January	8,785	8,275
Granted during the year	6,295	2,278
Exercised during the year	(6,383)	(586)
Forfeited during the year	(693)	(1,182)
Outstanding at 31 December	8,004	8,785
Exercisable at 31 December	-	-

 

The weighted average share price at the date of exercise for share options exercised during the year was £1.17 (2022: £2.44).

 

The inputs into the calculation of fair values of the share options granted during the year are as follows:

	2023	2022
Weighted average share price	£1.07	£1.67
Weighted average exercise price	Nil	Nil
Expected volatility	52.5%	57.7%
Expected life	3 years	3 years
Risk-free rate	3.3%	1.4%
Expected dividend yield (on the basis dividends equivalents received)	Nil	Nil

 

 

The options outstanding at 31 December 2023 had a weighted average remaining contractual life of two years (2022: two years).

 

The aggregate of the estimated fair value of options granted in 2023 is $4.6 million (2022 $5.0 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).

	2023 Number of share options '000	2022 Number of share options '000
Outstanding at 1 January	218	113
Exercised during the year	(180)	-
Granted during the year	178	105
Outstanding at 31 December	216	218
Exercisable at 31 December	-	-

 

The weighted average share price at the date of exercise for share options exercised during the year was £1.37 (2022: not applicable).

 

During the year 177,832 options (2022: 104,968) were granted to employees under the Deferred Bonus Plan.

 

The options outstanding at 31 December 2023 had a weighted average remaining contractual life of two years.

 

Value Creation Plan ("VCP")

 

The VCP was approved by shareholders in December 2016. In 2022, certain nil cost share option awards vested in accordance with the VCP rules, with the Company achieving a TSR of at least 8% compound annual growth. There will be no further awards under the plan.

	2023 Number of share options '000	2022 Number of share options '000
Outstanding at 1 January	-	3,508
Exercised during the year	-	(3,508)
Outstanding at 31 December	-	-
Exercisable at 31 December	-	-

 

24. Dividends

During 2023, a total of $25 million dividends (11.561 US cents per Common Share) were declared and paid to shareholders. In 2022, a total of $215 million dividends were declared and paid to shareholders including an ordinary dividend of $25 million (11.561 US cents per Common Share), a special dividend of $50 million (23.12 US cents per Common Share) and interim dividends totalling $140 million (65.27 US cents per Common Share).

 

To date in 2024, no dividends have been declared or paid.

 

25. 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 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 Directors and Officers who served during the year ended 31 December 2023 were as follows:

 

J Huijskes - Non-Executive Chairman (resigned June 2023)

M Angle - prior Deputy Chairman who became Non-Executive Chairman June 2023

K Wood - Non-Executive Director became Deputy Chair June 2023

D Thomas - Non-Executive Director

W Mwaura - Non-Executive Director

J Balkany - Non-Executive Director (appointed July 2023)

G Soden - Non-Executive Director (resigned June 2023)

J Harris - Chief Executive Officer and Director

I Weatherdon - Chief Financial Officer and Director

G Papineau-Legris - Chief Commercial Officer

C Kinahan - Chief Human Resources Officer

A Robinson - Chief Legal Officer and Company Secretary

J Hulme - Chief Operating Officer

 

The values below are calculated in accordance with IAS 19 and IFRS 2.

	2023 $'000	2022 $'000
Short-term employee benefits	3,463	4,725
Share-based payment - options	4,065	1,499
	7,528	6,224

 

Further information about the remuneration of individual Directors is provided in the Directors' Emoluments section of the Remuneration Committee report.

 

26. Contingent Liabilities

The Group has a contingent liability of $27.3 million (2022: $27.3 million) in relation to the proceeds from the sale of test production in the period prior to the approval of the original Shaikan Field Development Plan ("FDP") in June 2013. The Shaikan PSC does not appear to address expressly any party's rights to this pre-FDP petroleum. The sales were made based on sales contracts with domestic offtakers which were approved by the KRG. The Group believes that the receipts from these sales of pre-FDP petroleum are for the account of the Contractor, rather than the KRG and accordingly recorded them as test revenue in prior years. However, the KRG has requested a repayment of these amounts and the Group is involved in negotiations to resolve this matter. The Group has received external legal advice and continues to maintain that pre-FDP petroleum receipts are for the account of the Contractor. This contingent liability forms part of the Shaikan PSC amendment negotiations and it is likely that it will be settled as part of those negotiations.