Caspian Sunrise PLC
("Caspian Sunrise" or the "Company")
Annual Report and Financial Statements for the Year Ended 31 December 2023
Caspian Sunrise, the Central Asian oil and gas company with a focus on Kazakhstan, is pleased to announce its audited final results for the year ended 31 December 2023. The Company anticipates that the suspension of the Company's shares will be lifted today.
2023 Financial highlights
· Total revenues $36.7 million (Restated 2022: $40.9 million)
o Oil sales revenues $21.6 million (2022: $39.2 million)
o Oil trading revenues $10.3 million (2022: nil)
o Oil services revenues $4.1 million. (Restated 2022: $1.6 million)
· EBITDA $18.1 million (Restated 2022; $15.7 million)
· Operating profit $15.5 million (Restated 2022: $12.9 million)
· Profit before tax $14.8 million (2022: $12.3 million)
· Profit after tax $11.1 million (Restated 2022: $10.0 million)
· Gross assets $134.9 million (2022: $117.7 million)
2023 Operational highlights
· Production volumes 665,114 barrels (bbls) (2022: 792,284 bbls)
· Commencement of oil trading
· Continuing workover programme at MJF structure
· Horizontal drilling approach at Soviet era South Yelemes wells
· Deep Well 803 spudded - the third deep well on the Yelemes Deep structure
· Two new deep wells completed at Block 8
· First commercial drilling contract signed for the Caspian Explorer
· BNG shallow structure reserves at 31 December 2023:
o P1 13.6 million barrels (mmbls); (2022 14.3 mmbls)
o P2 24.8 mmbls (2022: 25.5 mmbls)
2024 Highlights to date
· Independent shareholder approval of the acquisition of the West Shalva Contract Area
· Shallow Well 155 spudded in February 2024 and drilled to 2,400 meters now testing a 16 meter interval
· Deep Well 803 drilled to a depth of 3,420 meters now testing a 15 meter interval
· Conditional agreement to sell the MJF and South Yelemes structures for $83 million
· Reserves in the immediate vicinity of the drainage areas around Deep Wells A5, A6 & A7 independently assessed at approximately
o C1 49.0 million barrels
o C2 28.9 million barrels
· Commencement of the Caspian Explorer ENI charter
Expected future events
Q3 2024
· Licence renewal at Block 8
· Caspian Explorer charter completed
· Confirmation of C1 style reserves for the Yelemes Deep structure at BNG
· Award of licence extension for BNG's Airshagyl & Yelemes Deep structures
· Production commences from Block 8 from existing wells
· Testing new well at Block 8
· First well drilled at West Shalva
· Acquisition of a G70 rig
Q4 2024
· First mining acquisition
· Completion of the West Shalva acquisition
· Completion of the Block 8 acquisition
CHAIRMAN'S STATEMENT
Introduction
Over the past few years, Caspian Sunrise has evolved from essentially one commercial asset with just a single producing structure, to now being a diversified and profitable natural resources group, with significant income flowing from a range of activities and with additional near term opportunities for further successful growth and diversification. The Group also has strong asset backing.
This transformation has been achieved in the face of some significant hurdles, including the oil price falling to $6 per barrel during the Covid-19 pandemic, assessed historic costs of $32 million to be repaid over a 10 year period, and the financial and operational impact of Russian sanctions, which for much of the past two years has ruled out international sales and significantly added to operational complexity. Notably, this transition was achieved against the backdrop of the financial constraints of a demanding work programme at our flagship BNG asset. It has also been implemented without undue dilution to shareholders.
Funding for the transition came principally from the sale of oil produced at BNG's MJF structure, from loans from our largest shareholding group and by running creditors and short term debt at higher levels than usual.
The Group now:
· owns (or is in the process of acquiring) three active oilfields with production expected from all three before the end of the year;
· is building a significant reserve base with further additions expected in the next 3 months;
· owns sufficient equipment and rigs to drill four wells at the same time and is also able to drill for third parties to farm into new oilfields;
· owns the only drilling vessel of its type capable of exploring the shallow reaches of the highly prospective northern Caspian Sea, which the Directors estimate would have a replacement cost of approximately $300 million and would take up to 3 years to become operational; and
· holds a coveted oil trading licence under the new rules introduced in 2023.
The financial rewards of these achievements are expected to become more apparent during the second half of the current financial year following:
· increasing production from BNG, Block 8 & West Shalva;
· if completed on the terms set out in the exclusivity agreement the proposed sale of the MJF and South Yelemes structures at the BNG Contract Area would result in $83 million gross proceeds;
· reduced operational expenditure following the completion of the current work programme commitments at BNG;
· the start of production revenues from Block 8 and West Shalva;
· continued oil trading profit; and
· receipt of income from the first commercial drilling charter for the Caspian Explorer under the Group's ownership.
Operational overview
BNG
At BNG our prime focus was to complete the work programme obligations required to renew the licence for the Airshagyl & Yelemes Deep structures from July 2024, being principally Well 155 on the MJF structure and Deep Well 803 on the Yelemes Deep structure.
We currently have a combined licence for the Airshagyl and Yelemes Deep structures which we intend to extend for a two year period before applying for separate 25 year licences for both structures. We already have separate production licences at both the MJF and South Yelemes structures running until 2043 and 2046 respectively.
The licence upgrade process requires independent assessments of the reserves under the former Soviet classification system operated by the Geological Committee of the Republic of Kazakhstan as required under the Kazakh reserve reporting rules at both the Airshagyl and Yelemes Deep structures based on the information gathered from the wells drilled on each.
In June 2024 we announced that SciRes, an independent Kazakh consultancy, had assessed the C1 reserves in the immediate vicinity of the Deep Wells A5, A6 & A7 on the Airshagyl structure as 6.809 million tonnes or approximately 49.0 million barrels and C2 reserves on the same basis as 4.009 million tonnes or approximately 28.9 million barrels.
A similar exercise is underway on the Yelemes Deep structure, the second deep structure on the BNG Contract Area, where to date three wells have been drilled. The reserve estimate requires the completion of the current work at Deep Well 803 and is therefore expected to be available in Q3 2024.
To maximise the revenues from the MJF structure to fund the development of the Group we pushed the original wells hard over prolonged periods with the result that they are no longer as productive as they could have been if our priority had been to maximise their useful lives.
The MJF structure is clearly a maturing structure with higher levels of water content than ideal and it is inevitable that we will find it harder to maintain production levels from the earlier wells drilled on the structure. Drilling to date to return the previously best performing Wells 141 and 142 to meaningful production has yet to work.
On the positive side, we are becoming more comfortable with the use of horizontal drilling techniques which can significantly increase production volumes. However, it is clear that horizontal drilling is far more effective in new wells, such as Well 155, rather than older wells such as 141 & 142. At South Yelemes we completed horizontal side-tracks at Wells 805 and 806 from depths between approximately 2,200 and 2,300 meters.
Production levels from the BNG shallow structures fluctuated during the period under review and subsequently to a greater degree than in previous years as wells came in and out of production. Total production for 2023 was 665,114 bbls which equates to 1,822 bopd (2022: 792,284 bbls & 2,171bopd).
Well 155 on the MJF structure was spudded in Q1 2024 and drilled to a depth of 2,400 meters. Testing of a 16 meter interval commenced in June 2024 with initial flow rates between 900 and 1,000 bopd. Production rates at Well 155 have since been reduced to approximately 700 bopd to optimise the life of the well.
Deep Well 803 was spudded in Q4 2023 with a planned total depth of 4,200 meters with a primary target at a depth of 3,950 meters and a secondary target at a depth of 4,200 meters. Oil has been detected over a 60 meter interval between 3,360 meters and 3,420 meters, above the expected targets and also above the main salt layer. Testing of a 15 meter interval commenced in July 2024.
Total production at the date of this report, before any contribution from Well 803, is approximately 2,300 bopd.
Block 8
In 2023 in anticipation of the completion of the acquisition of the Block 8 Contract Area, details of which are set out under the Corporate Events section below, we drilled two new deep wells to depths of 3,922 and 3,408 meters. These wells cannot be tested until the licence at Block 8 is renewed.
Once the licence is renewed our intention is now to use our G20 workover rig to test these two new wells.
3A Best
There was no operational activity at 3A Best during the period under review or subsequently.
Further information on the BNG, Block 8, and 3A Best Contract Areas together with the West Shalva Contract Area is set out below under the section entitled Our Assets.
Caspian Technical Services (CTS)
All the Group's onshore drilling is conducted via our 100% owned drilling subsidiary CTS, which also drills for third parties and currently has the capacity to drill four wells simultaneously using its own rigs and approximately 150 specialist contractors.
CTS owns 4 rigs, being one G50, two G40s, and a G20 workover rig, with the number indicating the maximum drill string weight the rig can support. Negotiations to acquire a G70 rig, which will allow future faster drilling of deep wells, are at an advanced stage.
Caspian Explorer
During the period under review and subsequently, significant effort has been expended on preparing the Caspian Explorer for its first commercial drilling contract under the Group's ownership.
In February 2023 we announced a two well charter for a consortium in which Eni S.p,A, the Italian multinational energy company (ENI) is the leading member. Contracts for the first of the two wells are in place and the first charter commenced in July 2024. As the contract specifies day rates rather than a fixed amount for the use of the Caspian Explorer it will not be until drilling is completed that the total revenue will be known. However, we expect to receive at least a further $10 million in the next few months in addition to the upfront payments already received.
We are also in discussions to charter the Caspian Explorer in 2025 to a different consortium, with 2026 identified should the ENI led consortium exercise their option for a second well.
Oil Trading
Being principally a financial function our introduction into oil trading is covered under the Financial Review below.
Corporate activities
BNG
In March 2024 we reported early stage discussions with a number of parties, which could result in a partial or complete sale of our interest in the BNG Contract Area. Our belief is that this heightened level of corporate interest in the BNG Contract Area reflects a combination of the relative scarcity of such assets and also the changes to the Kazakh oil trading regulations, which now require production to qualify for a trading licence.
In May 2024 we granted Absolute Resources LLP, a Kazakh registered entity, a 90 day exclusivity period to complete their due diligence on a proposed $83 million acquisition of the MJF and South Yelemes shallow structures on the BNG Contract Area.
We remain proud owners of the BNG Contract Area and have not initiated these discussions. However, accepting that there is a price for any of our assets at which shareholders would be better served by selling, we have a duty to listen and if appropriate act. We believe that realising $83 million to use on other Group assets would enhance shareholder value over the medium / longer term.
If progressed the sale of the MJF and South Yelemes structures would require the approval of Caspian Sunrise shareholders and the customary regulatory approvals in Kazakhstan and the UAE.
To date, in aggregate, approaching $200 million has been spent on the BNG Contract Area of which the Group has spent approximately $120 million, most of which was spent on the deep structures. Any corporate activity in respect of the deep structures at the BNG Contract Area would need to reflect both the gross investment made to date and the Contract Area's future prospects as evidenced by expected future production levels and reserves.
Block 8
In September 2023 we exercised the option to acquire the Block 8 Contract Area, which was first announced in September 2022.
On renewal of the licence, which is a condition of the acquisition, completion of the acquisition will be dependent on the customary approvals from the Kazakh authorities and the re-registration of ownership in the UAE.
Under the terms of the Block 8 Acquisition Agreement there is no significant up-front cash payment or issue of shares. Virtually all the purchase consideration is to be satisfied in cash via a royalty of $5 per barrel from oil produced from Block 8 once owned by the Group. The maximum purchase price is capped at $60 million.
The resumption of production at Block 8 will trigger the commencement of the repayment of the $3.1 million loan advanced to allow the 2023 drilling work at Block 8 to be completed. For further details see Note 16.
We believe Block 8 represents, in addition to the deep structures at BNG, a second potentially transformative asset in that either or both could enjoy the same geological characteristics of the nearby world class Tengiz and Kashagan assets.
West Shalva
In April 2024 independent shareholders approved the acquisition of the West Shalva Contract Area for an initial consideration of $5 million to be satisfied by the issue of 99,206,349 shares to be issued at 4p per share. On first oil an additional $5 million becomes payable by the issue of a further 99,206,349 shares, again to be issued at 4p per share. Additionally, the first $5 million of revenue derived from the sale of West Shalva oil once under the Group's ownership is payable in cash to the vendor in which case the maximum total consideration would be $15 million.
West Shalva is expected to be a far easier oilfield from which to produce oil than either BNG or Block 8. It does not have the salt layer present at both BNG and Block 8, beneath which the exceptional temperatures and pressures have made drilling difficult. Conversely, it does not have the same potential to become a world class asset.
It is better located for access and to deliver oil being much closer to refineries than either BNG or Block 8. It is also approximately 600 km further south than BNG and Block 8 thereby enjoying a better climate, which should result in fewer weather related delays than we encounter at BNG and are likely to encounter at Block 8.
More strategically, owning West Shalva makes it easier to consider selling all or part of BNG without the need to have rigs idle.
3A Best
The 3A Best licence expired some years ago and there are overdue social obligations to pay to be in a position to apply to renew the licence. However, we believe the complexity of the situation set out below is the reason why the Kazakh authorities have not sought to put the licence back into a tender process and that in time it will be renewed.
The 3A Best Contract Area surrounds and goes beneath the established shallow Dunga Contract Area, which is believed to have produced at rates up to 15,000 bopd. When we acquired our interest in 3A Best Dunga was owned by Maersk, the Danish conglomerate, who then sold it to Total Energies, the French energy company. KazMunaiGas, the Kazakh state oil company is now the owner.
Our interest in the 3A Best Contract Area was for accounting purposes fully written down several years ago. In 2021 we entered into an agreement to sell the majority of our interest in 3A Best conditional on the licence renewal but the delays involved resulted in that agreement falling away. Now the ownership of Dunga has been resolved we cpcan decide how best to proceed at 3A Best.
Caspian Explorer
Given its unique nature and the resurrection of exploration activity in the shallow northern Caspian Sea, it was not a surprise to receive interest from potential buyers at sums vastly greater than the $1.7 million that the Caspian Explorer is carried at in these financial statements.
In June 2023 we announced the proposed sale of a 50% interest in the UAE registered company that holds a 100% interest in the Kazakh entity that in turn owns the Caspian Explorer at a sum that valued our 100% interest at $45 million. That proposed transaction did not complete as the prospective purchasers did not make the agreed payments citing a failure to obtain the required Kazakh exchange control approvals.
As with BNG, the Group is not looking to sell the Caspian Explorer as we recognise its true potential. However, as noted above, we are duty bound to consider meaningful offers. Our preference would be to use our ownership of the Caspian Explorer as an entry point to join consortia to develop the hugely prospective offshore blocks in the shallow northern Caspian Sea now being prepared for exploration.
CTS
Our investment in CTS with its ability to drill several deep wells at the same time has led to early stage discussions for the Group to farm into an existing asset in return for CTS drilling wells to help that third party meet existing work programme obligations that may otherwise be missed.
Mining
For some time, it has been our stated intention to add mining investments to the Group's portfolio in recognition that a key strength of the Group is the identification, assessment and negotiation of asset acquisitions in Kazakhstan, which in addition to being a leading world producer of oil is also home to vast mineral resources.
An asset has been identified and we are in the evaluation stage with the intention, if what we believe is confirmed under an internal and external due diligence process, to seek to conclude its acquisition later this financial year.
Unlike early stage oil exploration similar mining ventures typically require far less investment and in the case of the project we are reviewing could produce income from day one. An investment in a mining project could also provide an opportunity for an expansion of our commodity trading activities, which to date have been limited to oil.
Kazakhstan
While in recent times Kazakhstan has been out of favour with some international investors, others - notably Chinese investors - have increased their interest in the country and its assets.
Kazakhstan is home to vast oil, gas and mineral reserves which will continue to attract international investment. The Kazakh economy is the strongest in Central Asia and is thriving principally based on high levels of demand for its natural resources.
Further details on the country and its assets are contained in the Kazakhstan section set out later in these financial statements.
Dilution and related party transactions
This Chairman's Statement provides an opportunity to set out some facts, which I believe to be relevant but seem not to be universally understood or appreciated.
Dilution
The Group has only issued shares specifically to raise cash on two occasions. The first being at the IPO in 2007 when we raised approximately $78 million and again in 2020 when we raised approximately $1.3 million in response to the impact of the domestic oil price falling to a Covid induced $6 per barrel.
At times over the past 18 years the Group has run short of cash and turned to the only realistic lender, being the Oraziman family. From time to time these amounts have been converted to shares but always with the prior approval of the independent directors as advised by the Group's Nominated Adviser and under the rules of the UK Takeover Panel and most importantly also approved in advance by independent shareholders. These share issues once approved have also always been at a premium to the prevailing share price.
Without this funding we would not have been able to develop the Group's activities and in all likelihood would not have survived. Other shares have been issued to buy assets (principally rigs) and companies (BNG / Caspian Explorer / 3A Best) or to satisfy specific debts where cash was not available.
Independent shareholders have also recently approved the issue of new shares at a premium to the then prevailing market price on completion of the West Shalva acquisition.
Related party transactions
Here again there seems to be a misinformed view that we have favoured the sellers when the opposite is very clearly the case.
In particular:
· Shareholders with longer memories will recall that in 2015 we sold Galaz, which was acquired as part of the Eragon acquisition in 2008 including BNG, for $100 million.
· In 2020 the Caspian Explorer drilling vessel was acquired for $3.2 million where it's resale value today is many times greater and the replacement cost is believed to be some $300 million.
· At Block 8 we will only pay for an asset with the potential to be world class from future production at the rate of $5 per barrel and with the price capped at $60 million.
· With West Shalva it is only the first $5 million that would be payable should there be no oil
It is therefore only at 3A Best that we have yet to come out on the right side of the deal and as set out above that remains a work in progress.
The advantage of related party transactions is that we fully understand and can check what we are buying. Given their existing shareholding in the Group there is no commercial purpose for the sellers seeking poor terms, even if under the regulatory framework it were possible.
For us related party transactions have worked very well and we should not be afraid to do others where the situation merits it.
Dividends
In November 2022 we initiated monthly dividend payments at the rate of approximately $1.25 million per month but after only four instalments we were forced to suspend payments for lack of available cash.
The immediate cause for the suspension in dividend payments was the operational impact of Russian sanctions, which meant instead of buying the bulk of our international drilling supplies and consumables from Russia on decent credit terms and two week delivery times, we had to order mainly from China with six month lead times and the need to pre-fund all payments.
This not only took all our available free cash but also delayed planned workovers, which in turn meant production related income was much lower than we expected at the time we set the dividend policy.
The decision to suspend dividend payments was not taken lightly and inevitably had a dramatic impact on the share price. When we suspended the dividend payments we undertook to review the position later in the year and again with these financial statements.
Opinion among shareholders who have expressed a view is divided. While some want the dividends to resume others would rather see available cash invested in new projects.
Separately, and as a consequence of both the 2022 UK High Court approved capital reduction and the UK Takeover Panel Rule 9 waiver granted in connection with the recent West Shalva acquisition, we now have both distributable reserves and, with the re-constituted concert party now cleared to hold more than 50% of the Group's shares, share buy-backs are possible without the need each time for a formal and expensive UK Takeover Panel approved whitewash.
In the circumstances therefore, the Board has decided not to resume regular dividend payments but to consider special dividends or share buy backs when funding permits.
Board composition
We are aware the current board composition is not ideal both in terms of the total number of directors and also where relevant the number of independent directors, which gives problems in:
· fully populating the various board committees;
· when it comes to the consideration of related party transactions; and
· more generally as the extent of the Group's operations expands.
The main reason we have yet to appoint new non-executive directors is the ongoing up to 75% pay cut taken by all board members, which has been in place since early 2020 and was instigated to help the Group fund its survival and development. These restrictions are expected to be partially eased in the second half of the current financial year as the Group's cash position improves. At that time, we expect to be in a position to strengthen the board and have already identified individuals we believe would add value.
Further information relating to the board is set out in the Directors Report and the Remuneration Committee Report in these financial statements.
Outlook
We have always been optimistic about the prospects for the Group's assets. The issue though for the past decade at least has been funding and the need to both safeguard existing assets via compliance with the demanding work programme commitments including the need to pay down the assessed historic costs, while at the same time seeking to take advantage of as many of the opportunities available to us as could then be funded.
The current BNG work programme commitments are now largely satisfied. Block 8 is expected to start contributing in the near future and significant income is expected from the Caspian Explorer in the coming months. Accordingly, we expect soon to enter a prolonged period where cash receipts far exceed mandated cash payments. In the event we complete the proposed sale of the BNG shallow structures for the proposed $83 million we would have large cash balances to invest or to return to shareholders via special dividends or share buy backs.
This, together with an expectation of the true commercial value of our assets emerging for all to see through increased production, further corporate transactions and / or reserve upgrades, plus the other opportunities we have in front of us, leads the Board to be now more confident of the Group's future success than at any time in the past decade.
Clive Carver
Chairman
15 July 2024
OPERATIONAL REVIEW
Oil production
Volumes
In 2023 a total of 665,114 barrels of oil were produced from the two shallow structures at the BNG Contract Area (2022: 792,284 barrels).
Of this production 576,368 barrels, representing approximately 87% of the total, were produced from the MJF structure (2022: approximately 767,284 barrels representing approximately 97% of the total) with 88,746 barrels representing approximately 13% of the total being produced from the South Yelemes structure (2022: approximately 25,000 barrels representing approximately 3% of the total).
Production in 2023 was adversely affected as for most of the year wells 141, 142 and 145 were shut in for workovers necessitated by increasing water content.
Current production from the shallow structures at the BNG Contract Area before any contribution from Well 803 is approximately 2,300 bopd.
Pricing
Oil produced in Kazakhstan and transported via the Russian pipeline network is not subject to sanctions. Nevertheless, in reality such oil continued to suffer significant discounts to the international price, which throughout 2023 meant it was uneconomic to sell any of the oil produced on the international markets.
In 2023 therefore 53% of oil produced was sold to the Kazakh domestic market (2022: 72%) with 47% sold to the Kazakh domestic mini refinery market (2022: 29%).
The average price achieved for oil sold in 2023 was approximately $32 per barrel (2022: $49.5 per barrel - which included several months of international sales before the imposition of the full impact of Russian sanction related "Urals discount").
On a positive note, the discount for oil produced in Kazakhstan and transported via the Russian pipeline network narrowed towards the end of 2023, to the point where international sales in 2024 seem far more likely.
Oil exploration
BNG Shallow structures
During the year workovers were undertaken at Wells 142 and 145 on the MJF structure.
At Well 142, which was the best performing of the original wells on the MJF structure before the water content rose to a level requiring a workover, a 2,300 meter side-track was drilled from a depth of approximately 1,860 meters with three intervals identified for testing. The first two intervals did not prove commercial. We are waiting on the outcome of the discussions to sell the MJF structure before testing the third interval.
The workover at Well 145 was not successful. The intention at Well 141 is to resume work to remove approximately 27 meters of stuck pipes, before drilling a horizontal side-track.
In February 2024 we spudded new Well 155 with a planned total depth of 2,400 meters. As noted above a 16 meter interval is currently under test with initial flow rates of between 900 and 1,000 bopd. Production levels at Well 155 have been reduced to approximately 700 bopd to optimise the life of the well. Accordingly, production from the MJF structure is currently approximately 2,050 bopd.
At the shallow South Yelemes structure we commenced the long planned use of horizontal drilling techniques at four Soviet era shallow wells. Work there has been completed on Wells 805 and 806. Production from the South Yelemes wells is currently approximately 250 bopd.
We are now drilling a new well on the South Yelemes structure being Well 815 with a planned depth of 1,900 meters targeting oil in the dolomites.
BNG Deep Structures
During 2023 we concluded that Deep Well A8 was not commercial and decided to abandon the well and since the period end we have made the same assessment at Deep Well 801.
At Deep Well A5, which flowed at rates in excess of 3,000 bopd when first drilled, work was undertaken in 2023 continuing in 2024 to attempt to remove a stuck pipe as a cheaper alternative to drilling a further side track. While a portion of the stuck pipe was removed the majority remains and a decision has been taken that, in due course, we will drill the new side track. In the meantime, the rig previously in use at Deep Well A5 has moved to drill Well 815 as noted above.
At Deep Well A6 no work was undertaken in the period under review or subsequently. We plan to use a chemical treatment to seek to get the well to flow at commercial rates and have identified the rig currently in use at Deep Well 803 to be used in the attempt.
At Deep Well A7 we plan to use the G70 rig we expect soon to acquire to resume drilling from a depth of approximately 2,150 meters where drilling was paused to allow other wells to be drilled. The Planned Total Depth of the well is 5,300 meters with an interval of interest identified at approximately 4,000 meters.
At Deep Well 802, which was spudded in 2022 and drilled to a depth of 3,800 meters, our work in 2023 to bring the well into commercial production was not successful and we are now looking for a partner with technical expertise to develop the well together.
In Q4 2023 we spudded Deep Well 803. As noted above the well had a planned total depth of 4,200 meters with a primary target at a depth of 3,950 meters and a secondary target at a depth of 4,200 meters. Oil has been detected over a 60 meter interval between 3,360 meters and 3,420 meters, above the expected targets and also above the main salt layer. A 15 meter interval is now being tested.
In June 2024 SciRes, an independent Kazakh consultancy, assessed C1 reserves in the immediate vicinity of wells A5, A6 & A7 at 49 mmbls. For further details please see the Licences & Work programmes and Reserves section of these financial statements.
Block 8
In 2023 two deep wells were drilled at Block 8. The first was drilled to a depth of 3,922 meters and the second was drilled to a depth of 3,408 meters. Both wells are now ready for testing once the Block 8 licence is renewed.
On renewal of the licence the two previously producing wells at Block 8, which before they were shut in produced at the rate of 110 bopd, would resume production.
West Shalva
In anticipation of the completion of the acquisition of the West Shalva Contract Area we plan to drill a 3,200 meter well, which is expected to spud in Q3 2024.
Clive Carver
Chairman
15 July 2024
FINANCIAL REVIEW
Revenue
Total revenue in 2023 fell by approximately 10 per cent to $36.7 million (Restated 2022: $40.9 million).
Oil prices
The impact of Russian sanctions made any international sales during 2023 uneconomic. By comparison, in the first four months of 2022 we sold 237,144 barrels on the international markets at an average price of $85 per barrel.
In 2023 the average price per barrel was approximately $32.5 compared to $49.5 in 2022.
Production volumes
Production in 2023 at 665,114 barrels was some 16% lower than in 2022 (792,284 barrels) principally as a consequence of wells 141 and 142 being out of production for much of the period and to date in 2024.
Income from oil sales
The net impact of lower prices and lower volumes was to reduce revenues from oil sales by approximately 45% to $21.6 million (2022: $39.2 million)
CTS
CTS LLP is the Group's wholly owned drilling company, which in 2023 undertook further work at the Block 8 Contract Area, which is in the process of being acquired with completion now expected later this year. Such work before the formal completion of the acquisition is recognised as third party revenue, as would income for drilling on other assets not then owned by the Group.
In 2023 the revenue from work at Block 8 was $4.1 million (Restated 2022: $1.6 million).
Prior Year Restatements
In preparing the financial statements for 2022, including the comparative numbers for 2021, the Directors were unable to obtain reliable information relating to drilling contracts held by its subsidiary CTS LLP in respect of the timing of the drilling costs incurred and their allocation between different contracts with EPC Munai LLP, an external party, and as well as contracts with another subsidiary of the Group, BNG LLP.
This information was necessary to determine revenues, cost of sales, advances received / receivable, provisions for losses on contracts, property plant & equipment, oil & gas assets, related tax balances and related party disclosures. As a result, the 2022 audit report included an audit qualification in this regard for the years ended 31 December 2021 and 2022, with revenue recognition not recorded in accordance with IFRS 15 under the input method.
Extensive work undertaken over the past 12 months has allowed the amounts spend by CTS to be properly allocated for 2023. As a result, the 2022 financial statements are subject to a prior year adjustment with the comparative numbers for the year ended 31 December 2022 being restated. The audit qualification in respect of the position at 2022 remains, and there is also a resultant impact on the 2023 revenue recognition and cost of sales.
The audit report for the year ended 31 December 2023, includes a qualification relating to these matters as was the case in the 2022 financial statements.
Further information relating to the prior year adjustment is set out in note 3.
The contracts with EPC Munai were all either completed or terminated during 2023 and therefore management do not believe there will be further ongoing issues in allocating the costs of CTS LLP.
Oil trading
Revenue from oil trading in 2023 was $10.3 million (2022: nil).
Under this heading we purchase crude oil and fund its refining, selling the resultant oil products to third parties.
Changes in Kazakh regulations, which came into effect at the start of 2023 and which require an element of oil production to qualify for an oil trading licence, allowed our entry into the market. Oil trading is only allowed on oil sold to the domestic market (53% in 2023) rather than for domestic mini-refinery sales (47% in 2023) or international sales (0% in 2023). To date we have adopted a relatively low risk approach to oil trading having formed a 70:30 partnership with an established trader with ourselves being the larger party and with our 30% partner providing the required funding.
Our entry into oil trading has proved extremely successful and we plan to continue to trade oil whether or not we sell the shallow MJF and South Yelemes structures. As our oil output from the BNG Contract Area increases and with Block 8 and West Shalva expected to come on stream we look forward to growing our oil trading income in the coming years.
Caspian Explorer
There was no revenue from the Caspian Explorer in 2023.
Gross profit
Gross profit fell by approximately 36 per cent to approximately $20.7 million principally as a result of the lower revenue from oil sales (Restated 2022: $32.2 million having in 2022 increased by 69%).
Selling expenses
Selling expenses fell by approximately 69% to $3.0 million (2022: $9.8 million having increased in 2022 by 29%) mainly as the result of lower export and customs duties, which are typically based on achieved oil prices with export sales attracting a much higher charge.
Administrative expenses
General and Administrative expenses were approximately $4.0 million lower at $5.8 million compared with $9.8 million in 2022, which included significant non-recurring local staff payments.
Other income
Following the write back of long standing but no longer required provisions we recorded a gain of $3.8 million.
EBITDA
EBITDA was $18.1 million (Restated 2022: $15.7 million.)
Operating profit
Despite the large decrease in gross profit the operating profit was $15.5 million (Restated 2022: $12.9 million) principally as the result of a $2.2 million contribution from oil trading, which commenced in 2023 together with the reversal of £3.8 million long standing provisions that are no longer required.
Profit for the year before tax
Profit before tax was $14.8 million (Restated 2022: $12.3 million).
Tax charge
The tax charge was $3.7 million (2022: $2.4 million). This tax is payable in Kazakhstan where historic losses have now been fully utilised.
Profit for the year after tax
The profit for the year after tax was $11.1 million (Restated 2022: $9.9 million).
Oil and gas assets
Unproven oil & gas assets
The carrying value of unproven oil and gas assets increased by approximately $7.4 million to approximately $52.0 million (Restated 2022: $44.6 million) as the result of additional work at the BNG deep structures.
Proven oil & gas assets
The value of proven oil & gas assets increased by approximately $6.5 million to approximately $60.6 million (2022: $54.1 million).
Other receivables
Other receivables due within 12 months increased from approximately $6.1 million to approximately $12.1 million. Of this, trade receivables increased by $3.1 million to $3.7 million (Restated 2022: $0.6 million); prepayments increased by $3.0 million to $4.3 million (Restated 2022: $1.3 million); recoverable VAT increased by $0.9 million to $2.9 million (Restated 2022: $2.0 million); with other receivables falling by $0.9 million to $1.3 million (restated 2022 $ 2.2 million).
Cash position
At the year-end we had cash balances of approximately $0.4 million (2022: $3.7 million).
Liabilities
Trade and other payables under 12 months (excluding historic costs and provisions)
Trade and other payables increased to $16.1 million (Restated 2022: $14.8 million).
The provisions for payments in less than 12 months were approximately $4.5 million (2022: $6.0 million), which are mainly social obligations.
BNG historic costs
We have continued to pay down the historic costs assessed against the BNG Contract Area. At 31 December 2023, of the original $32 million levied in 2019 approximately $16.9 million remains to be paid over the next six years, of which approximately $3.2 million is to be paid within 12 months.
Cashflows
During the period under review approximately $39.6 million was received from customers and approximately $33.9 million paid out to suppliers, creditors and staff with a further $4.9 million spent on unproven oil and gas assets and $7.3 million spent on property plant and equipment. A further $1.5 million was paid to related parties in connection with the Block 8 loan, and approximately $3.0 million was paid in dividends.
The above plus new loans of $8.0 million resulted in cash balances at the year-end decreasing from $3.7 million to $0.4 million.
Going Concern
As set out in the Chairman's statement and throughout these financial statements the financial strategy of the Group in recent years has been to fund compliance with work programme commitments and to expand the Group's activities without unduly diluting shareholders longer term interests.
This has inevitably stretched the short and longer term creditor position to levels at the period end and today which in a more established Group might appear excessive. However, the Board believes the expected significant cash inflows from oil production, offshore chartering and if appropriate asset sales means that the current position is set to reverse during the remainder of the current financial year to the point that the Group will significantly improve its cash position.
Nevertheless, with net current liabilities of approximately $14.3 million as at 31 December 2023, the assessment of going concern needs careful consideration. The Board has therefore assessed cash flow forecasts prepared for the period to 31 December 2025 and assessed the risks and uncertainties associated with the operations and funding position, including Block 8 and West Shalva.
These cash flows are dependent on a number of key factors including:
· The Group's cashflow is sensitive to oil price and volume sold. We have assumed all sales will be either domestic sales or sales to the domestic mini refineries. Should sales to domestic mini refineries cease and the surplus oil not be picked up on the domestic market additional funding would be required.
· The Group continues to forward sell its domestic production and receives advances from oil traders. With approximately $3.9 million advanced at the reporting date the continued availability of such arrangements is important to working capital. Whilst the Board anticipate such facilities remaining available given its trader relationships, should they be withdrawn or reduced more quickly than forecast cash flows allow then additional funding would be required.
· The Group has $4.0 million of tax liabilities and $4.3 million due on demand under social development programmes and $3.2 million BNG licence payments due within the next 12 months to the Kazakh government. The Board has forecasted the payment of the outstanding tax liabilities and the BNG licence payments but only a portion of the social obligations and development programmes due within the forecast period as the Board expects some social obligation and development programme payment deferrals to be approved. Should these deferrals not occur additional funding would be required.
· Should the charter for the Caspian Explorer be materially delayed from its July 2024 start date and / or payment not be made in accordance with the contract terms additional funding would be required.
These circumstances continue to indicate the existence of a material uncertainty which may cast significant doubt about the Group and the Company's ability to continue as a going concern and it therefore may be unable to realise its assets and discharge its liabilities in the normal course of business. The financial statements do not include the adjustments that would result if the Group and the Company was unable to continue as a going concern.
While none of the following can be relied upon until cash is received there are a number of expected events, which could provide significant additional working capital in the short term:
· operational expenditure savings at BNG where the mandated work programme obligations will end with Wells 155 and 803, both of which have been drilled and are now testing, together with new Well 815
· revenues of at least $10 million expected in H2 2024 from the Caspian Explorer contract
· commencement of repayment of the $3.1 million loan advanced to enable the 2023 work programme at Block 8 to be completed
· production commencing from Block 8 less the $5 per barrel royalty once the licence is renewed and the re registration formalities in the UAE are finalised
· if progressed, completion of the proposed $83 million sale of the MJF and South Yelemes structures would on its own eliminate any funding issues
Should it be necessary, the Board has the following actions to mitigate any short-term funding issues
· To seek additional funding from advance oil sales
· To sell all or part of one or more of the Group's assets - including either the BNG Contract Area where we have already received expressions of interest or the Caspian Explorer
· To seek additional short term funding from the Group's largest shareholder group
· To seek additional equity capital
Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group and the Company will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements.
Clive Carver
Chairman
15 July 2024
OUR OIL & GAS ASSETS
BNG Contract Area
The Group holds a 99% interest in the BNG Contract Area, having first taken a stake in 2008, as part of the acquisition of 58.41% of a portfolio of assets owned by Eragon Petroleum Limited. In 2017, we increased our stake to 99% upon the completion of the merger with Baverstock GmbH. Since 2008, more than $100 million has been spent at BNG.
The BNG Contract Area is located in the west of Kazakhstan 40 km southeast of Tengiz on the edge of the Mangistau Oblast, covering an area of 1,561 square km of which 1,376 square km has 3D seismic coverage acquired in 2009 and 2010. We became operators at BNG in 2011, since when we have identified and developed both shallow and deep structures.
Shallow structures
The shallow structures at the BNG Contract Area (MJF & South Yelemes) produced 665,114 barrels of oil in 2023 (2022: 792,284).
MJF structure
The first wells were drilled on the MJF structure in 2016, since when it has produced in aggregate in excess of 4 million barrels. We have embarked on a programme of redrilling the older wells using horizontal drilling techniques to increase production.
The productive Jurassic aged reservoir consists of stacked pay intervals with most ranging in thickness from two meters to 17 meters. The current mapped lateral extent of the MJF field is now approximately 13 km2. The producing wells range in depth from 2,192 meters to 2,450 meters.
In December 2018, we applied to move the MJF structure, which was part of the overall BNG licence, from an appraisal licence to a full production licence, under which the majority of the oil produced from the MJF wells may be sold by reference to world rather than domestic Kazakh prices. The full production licence became effective in July 2019 and runs to 2043, with the first revenues based on international prices received in August 2019.
Following the award of the MJF export licence the Kazakh regulatory authorities assessed historic costs of $32 million against the MJF structure, repayable quarterly over a 10-year period, of which approximately $17 million remained payable at 31 December 2023.
In 2023 we produced 576,368 barrels of oil from the MJF structure at an average of 1,579 bopd (2022: 767,284 barrels at an average of 2,102 bopd).
At the date of this report production from the MJF structure is approximately 2,050 bopd.
South Yelemes structure
The first wells were drilled on the South Yelemes structure during the Soviet era, with test production commencing in 1994. In 2023 the four Soviet era wells (54, 805, 806 & 807) produced approximately 88,746 barrels, (2022: approximately 25,000 barrels) at an average of 243 bopd. The structure has a full production licence to 2046 under which international sales are permitted.
Work has commenced to drill horizontally from each of the existing Soviet era wells at depths between approximately 2,200 and 2,300 meters targeting potential horizons in the Dolomites, with drilling on the first two wells completed. At the date of this report production from the South Yelemes structure is approximately 250 bopd.
Well 815 is a new well which is being drilled to a depth of 1,900 meters on the South Yelemes structure targeting oil in the Dolomites, using the rig previously used at Deep Well A5.
Deep structures
We have identified two deep structures at the BNG Contract Area. The first is the Airshagyl structure, which extends to 58 km2. The second is the Yelemes Deep structure, which extends over an area of 36 km2.
Airshagyl structure
Four deep wells have been drilled on the Airshagyl structure.
· Deep Well A5 was spudded in July 2013 and drilled to a total depth of 4,442 meters. Attempts to remove a stuck pipe have to date not proved successful and a new side track is planned
· Deep Well A6 was spudded in 2015 and drilled to a depth of 4,528 meters. A chemical treatment is planned.
· Deep Well A7 was spudded in December 2021, with a planned Total Depth of 5,300 meters but primarily targeting an interval at a depth of 4,000 meters. In March 2022 drilling at A7 was paused at a depth of 2,150 meters to allow the rig to be used to drill a horizontal well on the shallow South Yelemes structure.
· Deep Well A8 was spudded in 2018 with a planned Total Depth of 5,300 meters, initially targeting the same pre-salt carbonates that were successfully identified in Deep Well A5 at depths of 4,342 meters but with a prime target being the deeper carbonate of the Devonian to Mississippian ages towards the planned Total Depth of 5,300 meters. The well is now to be abandoned.
Yelemes Deep structure
· Deep Well 801 was drilled in 2014 / 2015 to a depth of 5,050 meters. The well has been assessed as non-commercial and has been marked for abandonment.
· Deep Well 802 was spudded in June 2022, with a planned Total Depth of 5,300 meters. To date the well has not flowed at commercial rates and we are seeking to conclude a joint venture agreement with an identified technical partner to continue work on this well.
· Deep Well 803 was spudded in December 2023 with a planned total depth of 4,500 meters. Oil was encountered over a 60 meter interval between depths of 3,360 and 3,420 meters and a 15 meter interval is being tested.
Deep well drilling issues
Sub-surface conditions at the two discovered deep structures at BNG present significant technical challenges in drilling and completing the wells. These are the extreme high temperature and pressure that exist below the salt layer. At the Airshagyl structure the salt layer is typically found at depths between 3,700 and 4,000 meters whereas at the Yelemes Deep structure the salt layer is typically found at depths between 3,000 and 3,500 meters.
The extreme pressure below the salt layer requires the use of high-density drilling fluid to maintain control of the well during drilling. The high-density drilling fluid's principal role is to help prevent dangerous blow-outs. The attributes of the high-density barite weighted drilling fluid, which allow the wells to be controlled during the drilling phase, act against us when we attempt to clear the well for production.
To the extent that drilling fluids, which include solid particles added to increase density, are not fully recovered they can form a barrier between the wellbore and the reservoir impeding the flow of hydrocarbons into the well.
Block 8
The Block 8 Contract Area is 2,823 sq km with three identified structures and is approximately 160 km from the BNG Contract Area.
The Block 8 licence was previously held by LG International the Korean conglomerate, who in 2006 started to acquire 3D seismic data over approximately 456 sq km. In recent years two deep wells have been drilled to depths of 4,203 meters and 3,449 meters respectively, from which oil has flowed at rates of up to 800 bopd but at the time they were shut in, as required as part of the licence renewal process, produced at the rate of 110 bopd.
Two other wells were drilled in 2022 and 2023 to depths of 3,922 and 3,408 meters respectively and on receipt of the new Block 8 licence will be tested.
West Shalva
The West Shalva contract area is rectangular in shape and extends over approximately 25 km². It is located in the oil producing Zhetybay Steppe Area in the Mangyshlak region of Western Kazakhstan approximately 90 km east of Actau and approximately 20 km north from the Zhetybay field, where an oil processing plant is located and oil enters the Actau / Atyrau main pipeline.
The West Shalva prospect is partially located in Block XXXVII-12 but straddles the boundary with adjacent blocks. The source rock for the West Shalva prospect is considered to be Triassic marine shale as is understood to be the case in the nearby Shalva and Zhalganoy fields.
The West Shalva prospect has potential reservoirs of Jurassic and Triassic age. The Jurassic - IX and Jurassic - XI and Triassic reservoirs are oil bearing in the nearby Shalva field and oil has been reported (but not tested) from core in the Triassic reservoir in the WSH-4 well. Based on interpretation of the available information the main reservoir targets are Jurassic IX and Jurassic -XI reservoirs, with secondary targets in the Triassic.
West Shalva was first identified as a potential oil producing location in the mid 1970's. In 1977 and based on 2D seismic data, Well no. 4 (Wsh-4) was drilled to the north and outside the structural closure of the West Shalva prospect to a depth of 3,500 meters with a prime potential oil bearing interval detected at a depth of 1,033 meters in the lower Triassic. After open hole testing lasting only a few minutes the well was deemed not to have found any commercial volumes of oil or gas despite oil being detected at three other intervals. The well was then abandoned without running a production string.
In 2008 a 3D seismic survey was undertaken on the contract area, which identified the West Shalva structure. In June 2022 oil was detected spilling to the surface.
West Shalva is an early stage oilfield but with strong indicators from both the adjacent Shalva field and from the available seismic information that it is likely to produce oil in decent quantities. Additionally, it is expected to be easier to drill than either BNG and Block 8 as the high pressure and high temperature encountered in those fields are not present at West Shalva. There is also no salt layer to penetrate and the field is closer to local refineries with a history of higher prices than the refineries nearer BNG and Block 8. In summary, West Shalva is expected to be a much easier field to work than either BNG or Block 8 and a good addition to the portfolio. As at Block 8 the acquisition has been structured to avoid any up-front cash payments.
3A Best
In January 2019, we acquired 100% of the 3A Best Group JSC, a Kazakh corporation owning an existing Contract Area of some 1,347 sq. km located near the Caspian port city of Aktau.
The Contract Area, which has been designated by the Kazakh authorities as a strategic national asset, surrounds and goes below the established shallow field at Dunga, which we believe to be producing at the rate of approximately 15,000 bopd.
No development work has been undertaken since 2019.
LICENCES & WORK PROGRAMMES AND RESERVES
LICENCES
BNG
BNG LLP Ltd holds three contracts for subsoil use. The first is the appraisal contract, covering the full extent of the BNG Contract Area (except the MJF and South Yelemes structures), originally issued in 2007 and successively extended until August 2024.
The second is the export contract covering just the MJF structure, which runs to 2043 and the third is the export contract covering the South Yelemes structure, which runs to 2046. Under the MJF and South Yelemes licences the majority of oil produced may be sold by reference to international rather than domestic prices.
The process to extend the existing Airshagyl and Yelemes Deep appraisal licence for a further two years before then upgrading to separate 25 year production licences is underway under a new streamlined process which is expected to be completed during Q3 2024.
Block 8
The Block 8 licence renewal is expected imminently.
West Shalva
The licence at the West Shalva Contract Area is a six-year appraisal licence running until 2029.
3A Best
The licence renewal at 3A Best was delayed as the result of outstanding social payments due from the assets previous owners. As noted more fully in the Chairman's statement we continue to work with the Kazakh authorities to renew the 3A Best licence at the appropriate time.
WORK PROGRAMMES
BNG
The current work programme commitments end with Well 155, Deep Well 803 and new Well 815, for which we estimate the outstanding costs to be approximately $3 million.
Block 8
The extent of the work programme commitments under the new licence have yet to be determined.
West Shalva
On completion of the acquisition of West Shalva there will be an obligation to drill one well to a depth of approximately 2,600 meters.
RESERVES
BNG
Shallow structures
In 2011 Gaffney, Cline & Associates ("GCA") undertook a technical audit of the BNG licence area and subsequently Petroleum Geology Services ("PGS") undertook depth migration work, based on the 3D seismic work carried out in 2009 and 2010.
The work of GCA resulted in confirming total unrisked resources of 900 million barrels from 37 prospects and leads mapped from the 3D seismic work undertaken in 2009 and 2010. The report of GCA also confirmed risked resources of 202 million barrels as well as Most-Likely Contingent Resources of 13 million barrels on South Yelemes.
In September 2016 GCA assessed the reserves attributable to the BNG shallow structures (MJF & South Yelemes). Between then and the end of 2023, approximately 4.0 mmbls of oil were produced, which under financial reporting rules are deducted from the assessment of reserves as at 31 December 2023.
| BNG | As at 31 December 2023 | As at 31 December 2022 |
|
| mmbls | mmbls |
| Shallow P1 | 13.6 | 14.3 |
| Shallow P2 | 24.8 | 25.5 |
Despite the last external review of the Group's reserves being in 2016, the Board considers their assessment as set out in the above table to be valid. In the event the proposed sale of the MJF and South Yelemes structures does not complete the Board's intention is to revisit the external assessment of the BNG Contract Area's shallow reserves.
Deep structures
In conjunction with the licence extension in respect of the Airshagyl and Yelemes Deep structures and referred to above under licences, we are also making submissions for formal recognition under the former Soviet classification system used in Kazakhstan of reserves at both deep structures based on information gained from the four deep wells drilled to date at the Airshagyl structure and the three deep wells drilled to date on the Yelemes Deep structure.
In June 2024 reserves under the former Soviet classification system were independently assessed by SciRes, a Kazakh consultancy, based solely on the vicinity of the immediate drainage area around Deep Wells A5, A6 & A7 as being C1 49.0 million barrels & C2 as 28.9 million barrels.
At Yelemes Deep we first need to complete the testing at Deep Well 803 before a similar assessment can be finalised.
In due course, following the completion of the reserves estimate underway at the Yelemes Deep structures under the former Soviet classification system, we plan to seek a reserves update under the international Society of Petroleum Engineers (SPE) classification system, for all of the BNG Contract Area, which would also include the shallow MJF and South Yelemes shallow structures, provided they are then still part of the Group.
Block 8
An estimate of the reserves at Block 8 is planned following completion.
West Shalva
To date there are no certified reserves in respect of the West Shalva Contract Area. Again, we intend to commission an independent assessment of the West Shalva reserves after completing the planned 3,200 meter well.
3A Best
There are no certified reserves in respect of the 3A Best Contract Area.
QUALIFIED PERSON & GLOSSARY
Qualified Person
Mr. Assylbek Umbetov, a member of the Association of Petroleum Engineers, has reviewed and approved the technical disclosures in these financial statements.
Glossary
SPE - the Society of Petroleum Engineers
Bbl - barrels of oil
Bopd - barrels of oil per day mmbls - million barrels
Proven reserves
Proven reserves (P1) are those quantities of petroleum which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.
If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.
Probable reserves
Probable reserves are those additional reserves which analysis of geosciences and engineering data indicate are less likely to be recovered than proved reserves but more certain to be recovered than possible reserves. It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated proved plus probable reserves (2P).
In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate.
Possible reserves
Possible reserves are those additional reserves which analysis of geosciences and engineering data indicate are less likely to be recovered than probable reserves.
The total quantities ultimately recovered from the project have a low probability to exceed the sum of proved plus probable plus possible (3P), which is equivalent to the high estimate scenario. In this context, when probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate.
Contingent resources
Contingent resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies.
Contingent resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality.
Contingent resources are further categorised in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.
Prospective resources
Prospective resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations.
Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects.
CASPIAN EXPLORER
Introduction
The Caspian Explorer is a drilling vessel designed specifically for use in the shallow northern Caspian Sea where traditional deep water rigs cannot be used.
The principal ways of exploring in such shallow waters are either from a land base or using a specialist shallow drilling vessel such as the Caspian Explorer, which we believe to be the only one of its type operational in the Caspian Sea.
Land based options typically involve either the creation of man-made islands from which to drill as if onshore or less commonly drilling out from an onshore location. Both are typically expensive compared to the use of a specialist drilling platform such as the Caspian Explorer.
The Caspian Explorer was conceived of by a consortium of leading Korean companies including KNOC, Samsung and Daewoo Shipbuilding. The vessel was assembled in the Ersay shipyard in Kazakhstan between 2010 and 2011 for a construction cost believed to be approximately $170 million. The Caspian Explorer became operational in 2012 at a time of relatively low oil prices and reduced exploration activity in the northern Caspian Sea.
The total costs after fit-out are believed to have been approximately $200 million. We believe a replacement would today cost in the region of $300 million and take several years from a decision to commission it for such a new vessel to become operational.
Operational characteristics
The Caspian Explorer:
· operates principally between May and November as the Northern Caspian Sea is subject to winter ice
· operates in depths between 2.5 meters and 7.5 meters
· can drill to depths of 6,000 meters
· typically has a crew to operate the drilling vessel of 20
· has accommodation for approximately 100
· costs approximately $60,000 per month while moored in port
· is generally able to pass on other costs incurred while operational to the clients hiring the vessel
Safety contract
In June 2021 we announced the first charter for the Caspian Explorer since it has been a part of the Group. The charter was with the North Caspian Operating Company ("NCOC"), which is the principal operator in the region, comprising the Republic of Kazakhstan working through KazMunaiGas (KMG), and international oil companies including Shell, ExxonMobil, ENI, Total Energies and CNPC, the consortium operating the Kashagan field.
Daily rates for safety related work are much lower than for conventional commercial drilling contracts but the income from the charter covered the Caspian Explorer's costs for that year.
Drilling contract
In March 2023 we announced that the first commercial drilling contract for the Caspian Explorer under the Group's ownership had been signed.
An offshore well is scheduled to be drilled in the summer of 2024 to a planned depth of 2,500 meters. It will be drilled for the Isatay Operating Company LLP ("IOC"), a Kazakh registered explorer, in which Italy's ENI is a leading participant. The Caspian Explorer left the port of Aktau in July 2024 to commence drilling as planned with the drill programme expected to take approximately two months.
Daily rates have been agreed for both drilling days and days when no drilling occurs. On the basis of these rates and the Group's assessment of the likely total number of days required to complete the assignment the Group expects further revenue in 2024 of approximately $10 million.
The contract also provides for a second well in the event the first is deemed successful. In the event the option for the second well was exercised it would most likely be drilled in 2026 on terms similar to the first assignment and is again expected to produce revenue of in excess of $10 million.
We are finalising the preparatory work for the ENI led consortium charter, which we expect to start on time in July 2024.
Other charters
We believe the drilling contract due to commence in Q3 2024 will be the first of a number as exploration of the shallow northern Caspian Sea increases. Discussions continue with a number of parties interested in chartering the Caspian Explorer, either on normal commercial terms or where the involvement of the Caspian Explorer allows Caspian Sunrise to take an interest in the project.
Accounting valuation
The Caspian Explorer has been written down in previous financial statements so that its carrying value at 31 December 2023 is only $1.7 million (2022: $1.7 million).
Lapsed conditional sale
In June 2023 we announced the conditional sale of 50% of Prosperity Petroleum, the UAE registered holding company for the Caspian Explorer for $22.5 million. The sale did not complete as a result of the prospective buyer failing to make the agreed payments.
Other corporate interest
Given its unique nature other expressions of interest in acquiring the Caspian Explorer have been received at indicated sums vastly greater than its accounting valuation. While it is not the Group's intention to sell the drilling vessel we are, as set out more fully in the Chairman's statement, obliged to consider all meaningful offers.
KAZAKHSTAN
Introduction
The Republic of Kazakhstan is mostly in Central Asia, with a part in Eastern Europe. It borders Russia to the north and west, China to the east, Kyrgyzstan to the southeast, Uzbekistan to the south and Turkmenistan to the southwest, with a coastline along the Caspian Sea.
Kazakhstan is the ninth largest country by land area and the largest landlocked country. Its population is 20 million with one of the world's lowest population densities.
Kazakhstan dominates Central Asia economically accounting for 60 per cent of the regions GDP, primarily through its oil & gas industry and its vast mineral resources.
Natural resources
Kazakhstan has an enormous supply of accessible mineral and fossil fuel resources.
Petroleum
The United States International Trade Administration lists Kazakhstan as having the 12th largest proven reserves which they estimate at 30 billion barrels.
The major oil and gas fields and recoverable oil reserves are Tengiz (which is approximately 40 km from BNG), Karachaganak and Kashagan.
The Tengiz field was jointly developed in 1993 as a 40-year Tengizchevroil venture between Chevron Texaco Exxonmobil, KazMunayGas, and LukArco. The Karachaganak natural gas and gas condensate field was developed by BG, Agip, ChevronTexaco, and Lukoil.
Chinese oil companies are now also heavily involved in Kazakhstan's oil industry.
Minerals
The United States International Trade Administration also lists Kazakhstan as having the world's largest reserves of uranium and extensive coal, gold and manganese reserves.
THE KAZAKH OIL AND GAS LICENCING AND TAXATION ENVIRONMENT
Introduction
Oil & gas is a heavily regulated industry throughout the world, with strict rules on licencing and taxation. Set out below is a summary of the position in Kazakhstan.
Licensing
Exploration licences
The initial licence to develop a field is typically an exploration licence where the focus is on completing agreed work programmes. Exploration licences are typically two years in duration and it is usual for there to be several consecutive two-year exploration licence extensions agreed during the exploration phase.
Appraisal licences
In the event the project appears commercial, the exploration licence is typically upgraded to an appraisal licence.
Under an appraisal licence, oil produced incidentally while exploring and assessing may be sold but only at domestic prices. Taxation under an appraisal licence is limited with only modest deductions. Changes to the legislation in the last few years have reduced the length of appraisal licences from six to five years, with a concession of reduced social obligation payments.
Full production licences
To sell oil by reference to world prices requires that either the Contract Area as a whole or a particular structure has to be upgraded to a full production licence. Under a full production licence there is only limited scope to develop areas not already drilled. Additionally, a significant minority portion of production typically remains at domestic prices although the majority can be sold by reference to world prices.
Taxes
There are five different taxes that apply to Kazakh oil & gas producers. Each has its own basis of calculation with some being related to profits, others by reference to world oil prices and yet others by reference to the volume of oil sold. The overall impact is that as world prices increase so typically does the percentage taken by the Kazakh state.
STRATEGIC REPORT
Introduction
This strategic report comprises: the Group's objectives; the strategy; the business model; and a review of the Group's business using key performance indicators. The Chairman's statement, which together with the operational and financial reviews also form the main part of the strategic review, contain a review of the development and performance of the Group's business during the financial year, and the position of the Group's business at the end of that year. Additionally, a summary of the principal risks and uncertainties facing the business is set out immediately after the Directors' report.
Objectives
The Group's objective is to create shareholder value from the development of oil & gas and mining projects and associated activities.
The Group has a number of secondary objectives, including promoting the highest level of health and safety standards, developing our staff to their highest potential and being a good corporate citizen in our chosen countries of operations.
Strategy
The Group's long-term strategy is to increase shareholder value by building an attractive portfolio of oil & gas and mineral assets, initially in Central Asia, and in particular Kazakhstan where the board has the greatest experience.
The Group's principal asset is its 99% interest in BNG, a 100% interest in the Caspian Explorer, a shallow water drilling vessel designed for the northern parts of the Caspian Sea. The Group also owns a 100 per cent interest in the 3A Best Contract Area, which would require a licence renewal before having any commercial value.
The Group has also conditionally agreed to acquire:
· a 100% interest in the Block 8 Contract Area for a maximum consideration of $60 million, payable via royalties on future Block 8 oil production at the rate of $5 per barrel; and
· a 100% interest in the West Shalva Contract Area for a maximum consideration of $15 million, of which a maximum of $10 million is payable by the issue of Caspian Sunrise shares to be issued at 4p per share and up to a further $5 million in cash from future West Shalva production
Business model
The business model is straightforward. To take assets at any stage of the development cycle and to improve them to the point they contribute to the Group's profitability or that they may be sold on at a profit to provide funding for additional development.
Our BNG asset has been developed over the past 18 years with approaching $200 million spent on it of which approximately $120 million has been spent by the Group since 2008. We believe it is set to be a very substantial asset for many years to come. We have received a conditional offer of $83 million for the shallow structures and believe the deep structures have a far greater value.
We also believe Block 8 has the potential to at least match BNG. West Shalva adds a third oil & gas asset, but without the high temperature and pressures present at BNG and Block 8.
While we seek to grow our asset portfolio with appropriately timed acquisitions we are also prepared and able to sell assets when their value to others exceeds the value we can see. This was the case in 2015, when in poor market conditions, we sold our then second asset Galaz for a headline price of $100 million, which represented a profit of $15 million on our interest in the asset, and which provided $33 million to re-invest into BNG.
Further growth by acquisition
The Group will consider acquiring additional assets or related businesses where the Board believes they would increase shareholder value, including by providing funding or infrastructure to develop the Group's other assets.
The Directors believe the Group is exceptionally well placed through its strong local Kazakh presence to identify and buy undervalued oil & gas assets and mining and other assets on an opportunistic basis.
Climate Change
The Group's purpose is to supply energy in an environmentally conscious manner to the benefit of all stakeholders. As a natural resources exploration and production company, we recognise our environmental responsibilities to all our stakeholders and in particular to the local communities in which we operate.
However, other than a longer term general move away from fossil fuels once renewable alternatives are available in sufficient quantities and at comparable prices, the Board is not aware of any indications that the impact of climate change is likely to have a material impact on the Group's business over the short and medium terms. We believe the current need for oil will continue for many decades to come.
The Group's size means it is not required to report further on climate change.
Key performance indicators
The Non-Financial Key Performance Indicators are:
· Operational (wells drilled and not identified for abandonment at end of year) 2023: 20 (2022: 20)
· Aggregate production for 2023 was 665,114 barrels (2022: 792,284) a fall of approximately 16%
· Reserves at 31 December 2023 13.6 P1 mmbls & 24.8 P2 mmbls (2022: P1 14.3 mmbls & P2 25.5 mmbls)
The Financial Key Performance Indicators are:
· Revenue: down 10% at $36.7 million (Restated 2022: $40.9 million)
· EBITDA $18.1 million (Restated 2022: $15.7 million)
· Profit before tax $14.8 million (Restated 2022: $12.3 million)
· Profit after tax for the year $11.1 million (Restated 2022: $10.0 million)
· Cash at bank: $0.4 million (2022: $3.7 million)
· Total assets: $134.9 million (Restated 2022: $117.7 million)
· Exploration assets $52.0 million (Restated 2022: $44.6 million)
· Proved oil & gas assets $60.6 million (Restated 2022: $54.1 million)
Production at the date of this report
· Approximately 2.300 bopd excluding any production from Well 803. (30 June 2023: approximately 2,000 bopd)
Assets & Reserves
Further details of the Group's assets and reserves are set out in the Chairman's statement and throughout this Annual Report.
Financial
At current domestic and domestic mini refinery prices and with current levels of production the income from current production is sufficient to cover day-to-day Group operations and G&A costs.
The bulk of the payments for the Caspian Sunrise drilling contract for the consortium headed by ENI are expected to be received during the remainder of 2024.
Should the proposed conditional $83 million sale of the shallow structures at the BNG Contract Area complete we would expect the net proceeds to be received in Q4 2024. In the event any of the deep wells drilled start to produce oil in commercial quantities the associated revenues should transform the Group's cash flows.
Drilling wells at a rate faster than could be funded from oil sales, would require additional funding, as would any acquisitions to be funded by cash. Potential sources of such funding would include further advances from local oil traders for the sale of oil yet to be produced; industry funding in the form of partnerships with larger industry players; further support from existing shareholders; and equity funding from financial institutions. Additionally, funding may be available from selected asset sales.
Dividends
The Company's first dividend was declared in November 2022 and was followed by 3 further monthly dividends. In March 2023 the Company announced that future dividends would be declared on a quarterly rather than monthly basis. In July 2023 we announced the suspension of future dividend payments following sanctions related working capital pressure.
As set out more fully in the Chairman's statement the Board has decided against the resumption of regular dividend payments in favour of special dividends and / or share buy backs when funding permits.
S. 172 Statement
The Board is mindful of the duties of directors under S.172 of the Companies Act 2006.
Directors act in a way they consider, in good faith, to be most likely to promote the success of the Company for the benefit of its members. In doing so, they each have regard to a range of matters when making decisions for the long term success of the Company.
Our culture is that of treating everyone fairly and with respect and this extends to all our principal stakeholders. Through engaging formally and informally with our key stakeholders, we have been able to develop an understanding of their needs, assess their perspectives and monitor their impact on our strategic ambition.
As part of the Board's decision-making process, the Board and its committees consider the potential impact of decisions on relevant stakeholders whilst also having regard to a number of broader factors, including the impact of the Company's operations on the community and environment, responsible business practices and the likely consequences of decisions in the long term.
Our objective is to act in a way that meets the long term needs of all our main stakeholder groups. However, in so doing we pay particular regard to the longer term needs of shareholders. We engage with investors on our financial performance, strategy and business model. Our Annual General Meeting provides an opportunity for investors to meet and engage with members of the Board. The Board also continues to encourage senior management to engage with staff, suppliers, customers and the community in order to assist the Board in discharging its obligations.
Further details of how the Directors have had regard to the issues, factors and stakeholders considered relevant in complying with S 172 (1) (a)-(f), the methods used to engage with stakeholders and the effect on the Group's decisions during the year can be found throughout this report and in particular at page 29 (where the Group's strategy, objectives and business model are addressed), page 32 (in relation to employees) the ESG report on page 37 (in relation to social and environmental matters).
We seek to attract and retain staff by acting as a responsible employer. The health and safety of our employees is important to the Company and an area we have to regularly report on to the Kazakh regulatory authorities.
We continue to provide support to communities and governments through the provision of employment, the payment of taxes and supporting social and economic development in the surrounding areas, both through social investment and local procurement. We have contributed to a range of social programmes for well over a decade.
We have established long-term partnerships that complement our in-house expertise and have built a network of specialised partners within the industry and beyond.
Clive Carver
Chairman
15 July 2024
DIRECTORS' REPORT
The Directors present their annual report on the operations of the Company and the Group, together with the audited financial statements for the year ended 31 December 2023.
The Strategic Report forms part of the business review for this year.
Principal activities
The principal activities of the Group are
· the exploration and production of oil & gas
· onshore and offshore oil field services
· oil trading
Results and dividends
The consolidated statement of profit or loss is set out on page 56 and shows a $11.1 million profit for the year after tax (Restated 2022: US$10.0 million).
The Company declared its first monthly dividend of £1 million (approximately $1.13 million) in November 2022 and has subsequently declared a further 3 monthly dividends before suspending dividend payments in July 2023. As set out more fully in the Chairman's statement the Board has decided not to resume regular dividend payments but rather to look to declare special dividends and / or share buy backs when funding permits.
Review of the year
The review of the year and the Directors' strategy are set out in the Chairman's Statement, the Strategic Report and throughout these financial statements.
Events after the reporting period
Other than the operational and financial matters set out in these financial statements there have been no material events between 31 December 2023, and the date of this report, which are required to be brought to the attention of shareholders. Please refer to note 31 of these financial statements for further details.
Board changes
In July 2023 Edmund Limerick left the board after 13 year's service as a non-executive director. Otherwise, there have been no board changes during the year under review or subsequently.
Employees
Staff employed by the Group are based primarily in Kazakhstan.
The recruitment and retention of staff, especially at management level, is increasingly important as the Group continues to build its portfolio of oil & gas and mining assets. As well as providing employees with appropriate remuneration and other benefits together with a safe and enjoyable working environment, the Board recognises the importance of communicating with employees to motivate them and involve them fully in the business.
For the most part, this communication takes place at a local level and staff are kept informed of major developments through email updates. They also have access to the Group's website.
The Group has taken out full indemnity insurance on behalf of the Directors and officers.
Health, safety and environment
It is the Group's policy and practice to comply with health, safety and environmental regulations and the requirements of the countries in which it operates, to protect its employees, assets and the environment.
Environmental reporting
The Group is exempt from the Streamlined Energy and Carbon Reporting (SECR) requirements since its energy consumption is less than 40,000 kWh per annum in the UK.
Charitable and Political donations
During the year the Group made no charitable or political donations.
Directors and Directors' interests
The Directors of the Group and the Company who held office during the period under review and up to the date of these financial statements are as follows:
Directors' interests
| Director | Number of Ordinary Shares | |
|
| As at 31 December 2023 | As at 31 December 2022 |
| Clive Carver | 2,245,000 | 2,245,000 |
| Kuat Oraziman* | nil | nil |
| Aibek Oraziman* | 1,046,909,031 | 946,887,599 |
| Seokwoo Shin | nil | nil |
* taken together on 31 December 2023 the Oraziman Family, comprising Kuat Oraziman, Aibek Oraziman, Altynbek Bolatzhan and Bolatzhan Kerimbayev held 1,089,544,791 shares representing approximately 48.41% of the issued share capital. Together with Daulet Beisenov they formed a Concert Party then holding 1,091,189,529 shares representing 48.49%
Biographical details of the Directors are set out on the Company's website www.caspiansunrise.com.
Details of the Directors' individual remuneration, service contracts and interests in share options are shown in the Remuneration Committee Report.
Other shareholders over 3% at the date of this report
| Shareholder | Shares held | % |
| Dae Han New Pharm Co Limited | 224,830,964 | 9.97 |
| Midiel Engineering AG | 110,812,501 | 4.91 |
| Al Marri Family | 110,812,500 | 4.91 |
| Abai Kalmyrzayev | 79,058,642 | 3.51 |
Financial instruments
Details of the use of financial instruments by the Group and its subsidiary undertakings are contained in note 27 of the financial statements.
Statement of disclosure of information to auditor
The Directors have taken all the steps that they ought to have taken to make themselves aware of any information needed by the Group's auditor for the purposes of their audit and to establish that the auditors are aware of that information.
The Directors are not aware of any relevant audit information of which the auditor is unaware.
Auditors PKF Littlejohn LLP, who were appointed in the year, have indicated their willingness to continue in office and a resolution concerning their reappointment was passed at the Annual General Meeting held on 27 June 2024.
Directors' responsibilities statement
The Directors are responsible for preparing the annual report and the financial statements in accordance with applicable law and regulations.
Company law requires the Directors to prepare financial statements for each financial year. Under that law the Directors have elected to prepare the Group and Company financial statements in accordance with UK adopted international accounting standards.
Under Company law the Directors must not approve the financial statements unless they are satisfied that they give a true and fair view of the state of affairs of the Group and Company and of the profit or loss of the Group for that period.
The Directors are also required to prepare financial statements in accordance with the rules of the London Stock Exchange for companies trading securities on the London Stock Exchange AIM Market.
In preparing these financial statements, the Directors are required to:
· select suitable accounting policies and then apply them consistently;
· make judgements and accounting estimates that are reasonable and prudent;
· state whether they have been prepared in accordance with UK adopted international accounting standards subject to any material departures disclosed and explained in the financial statements; and
· prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Company and the Group will continue in business.
The Directors are responsible for keeping adequate accounting records that are sufficient to show and explain the Group's and the Company's transactions and disclose with reasonable accuracy at any time the financial position of the Group and the Company and enable them to ensure that the financial statements comply with the requirements of the Companies Act 2006.
They are also responsible for safeguarding the assets of the Group and the Company and hence for taking reasonable steps for the prevention and detection of fraud and other irregularities.
Website publication
The maintenance and integrity of the Group's website is the responsibility of the Directors.
The Directors are responsible for ensuring the annual report and the financial statements are made available on a website. www.caspiansunrise.com/investors/reports
Financial statements are published on the Group's website in accordance with legislation in the United Kingdom governing the preparation and dissemination of financial statements, which may vary from legislation in other jurisdictions.
The Directors' responsibility also extends to the ongoing integrity of the financial statements contained therein.
Responsibility statement
The Directors confirm that to the best of their knowledge
· the financial statements, prepared in accordance with the relevant financial reporting framework, give a true and fair view of the assets, financial position and profit or loss of the Company and the undertakings included in the consolidation taken as a whole
· the Strategic Report includes a fair review of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties
· the Annual Report and the financial statements taken as a whole, are fair balanced and understandable and provide the information necessary for shareholders to assess the Company's position, performance, business model and strategy.
Clive Carver
Chairman
15 July 2024
PRINCIPAL AND OTHER RISKS AND UNCERTAINTIES FACING THE BUSINESS
Introduction
Risk assessment and evaluation is an essential part of the Group's planning and an important aspect of the Group's internal control system.
Oil & gas exploration and production and mining are dangerous activities and as such are necessarily subject to an extremely rigorous health and safety regime. The Board aims to identify and evaluate the risks the Group faces or is likely to face in future both from its immediate activities and from the wider environment. This helps to inform and shape the Group's strategy and to quantify its tolerance to risk.
Operational success generally helps to mitigate financial risks. Increases in production as new wells or mines come on stream generates cash and improves the Group's financial position, which can then lead to further operational success.
As the Group develops, its approach to risk management and mitigation will be refined. In due course we plan to include a formal risk register including all the principal operational and non-operational risks to the business. Such a risk register would be reviewed and assessed at least once a year.
The Group is subject to various risks relating to political, economic, legal, social, industry, business and financial conditions. The following risk factors, which are not exhaustive, are particularly relevant to the Group's business activities and are listed in the Board assessment in the order of greatest potential impact.
| Risk | Description | Mitigation |
| | | |
| Operating risk | Oil & gas exploration and production and mining are dangerous activities. The Group is exposed to risks such as well blowouts, fire, pollution, bad weather and equipment failure. | The Group seeks to adopt best in class industry operating standards and complies with rigorous health & safety regulations.
The Group also seeks to work with contractors who can demonstrate similar high standards of safety. |
| Exploration risk | Despite the success of the BNG shallow structures, there can be no assurance the Group's exploration activities in the BNG deep structures or anywhere else will be successful. | The Group seeks to reduce this risk by acquiring and evaluating 3D seismic information before committing to drill exploration and appraisal wells.
The Group also seeks to engage suitably skilled personnel either as employees or contractors to undertake detailed assessments of the areas under exploration. |
| Political Risk | Political division which leads to civil disorder is likely to have an adverse impact on the Group's operations.
| Widespread disorder in Kazakhstan had been absent since the Group's formation until the beginning of 2022, when the Group together with other operators was forced to suspend operations due to civil unrest.
The importance of the oil & gas and mining industries to the Kazakh economy makes a prolonged suspension of operations unlikely, as was the case in 2022. |
| Russian sanctions | The sanctions imposed on Russia may affect both the Group's ability to transport its oil and the price at which the oil may be sold.
It may also affect the Group's ability to source equipment and other consumables required to produce oil. | For international sales and like most oil produced in Kazakhstan for the international market the Company's oil is transported to international buyers via the Russian oil pipeline network.
While there are and were no UK or EU sanction on Kazakh oil transported through the Russian pipeline system in practice for much of the past two years such oil was subject to a hefty unofficial "Urals Oil" discount. This made selling the Group's oil on the international market uneconomic.
In recent months the discount on "Urals Oil" to international oil prices has narrowed to the point it is no longer an issue for volumes greater than those currently produced by the Group. However, for our levels of production and given our sales trading income we are not to date at the point where international sales are yet commercial.
We therefore currently sell all our oil either on the traditional domestic market or the relatively new domestic mini refinery market where taxes and other deductions are much lower. Equipment and consumables previously sourced from Russia are now found elsewhere, typically China, adding time and expense. |
| Permitting risks | Every stage of the Group's operations requires the approval of the industry regulators.
While the Group enjoys good working relationships with the Kazakh regulatory authorities there can be no assurances that the laws and regulations and their reinterpretation will not change in future periods and that, as a result, the Group's activities would be affected. | Regulatory delays are inevitable and common place.
Our experienced Kazakh workforce has both a thorough knowledge of the complex rules and a detailed practical understanding of the workings of each of the regulatory bodies with whom we need to deal. Accordingly, we believe we are well placed to minimise the financial impact of regulatory delays.
|
| Pricing risk | We operate in an industry where the international price is set by world markets and the domestic price is set by the Kazakh regulatory authorities. | We have no influence on the price at which we can sell our oil or any minerals produced from mining.
Greater storage and or financial hedging would provide some protection against adverse oil price movements but would be expensive and short lived. |
| Environmental risk | There would be serious consequences in the event of a polluting event.
| The Group seeks to maintain compliance with all applicable regulatory standards and practices.
Further information is set out in the Environmental, Social and Governance Report. |
| Climate change | That climate change might impact the prospects for the Group | The board does not believe in the short to medium term climate change will have a material impact on the Group's revenues or operations. In particular the board believes the demand for oil will continue for at least the next decade and that climate change is unlikely to materially impact the Group's ability to produce that oil. |
| Exchange rate risk
| Movements in exchange rates may result in actual losses or in the results reported in the Group financial statements.
| The Group's income is denominated in US$ and Kazakh Tenge its expenditure is denominated principally in US$, Kazakh Tenge and UK £. In the year under review and subsequently the Tenge broadly maintained its exchange rate against the US$.
Any decline in the Kazakh Tenge against the US$ affects the US$ reported income for domestic sales which transacted in Tenge. However, in such circumstances the Group generally benefits as international income is unaffected but approximately 50% of the Group's costs are incurred in Tenge reducing the US$ reported operating costs.
Given the relative strengths of the US$ and the Kazakh Tenge, the Group has decided not to seek to hedge this foreign currency exposure. |
| Loss of major shareholder support | In previous periods the Group has relied on the financial support of the Oraziman family, which currently holds 48.3% of the Company's shares. | The Group is now producing significant volumes of oil with additional income from oil services and oil trading and is on a day to day operating basis financially a self-supporting enterprise.
However, in the event further support was required it would clearly be in the interests of the Oraziman family as the major shareholding group to provide it. |
| Supplier risk | Continued operations depend on regular deliveries to site of consumables, such as water, food, heating oil and replacement parts for our drilling equipment. Delays in such deliveries to site could impact production volumes. The war in Ukraine has resulted in supplies no longer being sourced from Russia. Replacement supplies from China are taking much longer to arrive. | We have been operating the BNG Contract Area for more than a decade during which we have encountered numerous supply issues, all of which have been overcome.
Managing supplies has become one of the most important aspects of the business.
With the majority of supplies now coming from China, whose border is approximately 3,000 kilometers from the BNG Contract Area, lead times are now much greater. In addition, the working capital investment is also much greater as supplies need to be paid for much earlier than before.
|
ENVIRONMENTAL, SOCIAL AND GOVERNANCE (ESG) REPORT
This report covers our ESG approach and performance for the year ended 31 December 2023.
ENVIRONMENTAL
Introduction
Oil and gas exploration and production is a long-term activity requiring effective environmental stewardship. We have operated in Kazakhstan now for more than 18 years and have only been able to do so by complying with applicable environmental standards.
We recognise that society is transitioning towards a low-carbon future, and we support this goal. However, we believe that oil will continue to play an important role in the global economy for many decades to come, and new sources of oil supply will be required for a sustainable energy transition.
Climate change
Assessing the risks
We look to the Kazakh regulatory authorities to set the standards to which we work.
Compliance with the standards
We seek to comply with all relevant Kazakh environmental requirements, including environmental laws & regulations and industry guidelines.
Specific initiatives
· We seek to recycle gas produced as a by-product at BNG to power the Contract Area's day-to-day operations.
· We seek wherever possible to avoid flaring, which in any event is a regulated activity.
· Our workers at the BNG Contract Area are drawn from the local community, lessening the transportation carbon footprint.
· We make use of existing oil pipelines to move our oil.
Health and safety
Our daily operations prioritise health and safety and protecting the environment and we seek to comply with all applicable health and safety related regulations.
SOCIAL
Since the Group's formation in 2006, the social obligations payments made principally to the authorities in the regions in which the group operates have funded a range of projects for the benefit of the local communities concerned.
GOVERNANCE
Introduction
Overall responsibility over the Group's corporate governance, risk management, market disclosure and related obligations rests with the Board.
Recently, as noted elsewhere in these financial statements, the Group has struggled to operate the board committee system set out below because of the small size of the board. Accordingly, in recent times the board as a whole has considered many of the issues typically previously dealt with by board committees.
Committee composition
The Governance & Risk Committee now comprises Clive Carver and Aibek Oraziman with Clive Carver acting as chairman. The committee typically meets at least once a year to review the Group's governance procedures compared to accepted industry best practice.
At the appropriate time the Board plans to include a formal risk register including all the principal operational and non-operational risks to the business to be considered by the Governance & Risk Committee.
Share dealing policy
The Group has adopted and operates a share dealing code for Directors and employees in accordance with the AIM Rules.
Internal controls
The Board acknowledges responsibility for maintaining appropriate internal control systems and procedures to safeguard the shareholders' investments and assets, employees and the business of the Group. The Board also intends to periodically review the Group's financial controls and operating procedures.
Internal audit
The Board does not consider it appropriate for the current size of the Group to establish an internal audit function. However, this will be kept under review.
Bribery and corruption
The UK Bribery Act 2010 came into force on 1 July 2011.
The Company is committed to acting ethically, fairly and with integrity in all its endeavours and compliance with legislation is monitored. The principal terms of the UK Bribery Act have been translated into Russian and circulated to our Kazakh based staff. Consideration of the UK Bribery Act is a standing item at board meetings.
The Company's culture
Our culture might best be described as one where we strive for commercial success while treating others fairly and with respect. The Board firmly believes that sustained success will best be achieved by following this simple philosophy. Accordingly, in dealing with each of the Group's principal stakeholders, we encourage our staff to operate in an honest and respectful manner. We also believe in getting proper value for money spent and believe this goes hand in hand with being a low-cost operator.
Kazakhstan plays an important part in the Group's culture. It is where we operate; where almost all staff are based; it is the nationality of most staff and of the majority of shareholders.
The Group is committed to promoting a culture based on ethical values and behaviours across the business. Policies are in place covering key matters such as equality, protection of sensitive information, conflicts of interest, whistleblowing and health and safety as well as environmental concerns.
QCA Code
Caspian Sunrise, in line with most AIM companies, elected to apply the rules of the Quoted Companies Alliance (QCA) Corporate Governance Code ("QCA Code"), which is based around 10 broad principles.
| Principle 1
Establish a strategy and business model which promotes long term value for shareholders | Objective Caspian Sunrise's objective is to create shareholder value from the development of oil and gas projects and associated activities.
The Group has a number of secondary objectives, including promoting the highest level of health and safety standards, developing our staff to their highest potential and being a good corporate citizen in our chosen countries of operations.
Strategy The Group's long-term strategy is to build shareholder value by assembling an attractive portfolio of oil & gas and mineral exploration and production assets in Central Asia, and more particularly in Kazakhstan where the board has the greatest experience. The Group is also exploiting associated opportunities, such as oilfield services and commodity trading, where the board believes it can add significant value and contribute towards the success of the Group as a whole.
Our business model Our business model is to invest in and develop promising oil & gas, mineral and other projects. Success in the long term will be measured by a sustainable appreciation in the Group's profitability and the Company's share price.
Principal assets The Group's principal asset is its 99% interest in the BNG Contract Area, which is in the west of Kazakhstan, 40 kilometres southeast of Tengiz on the edge of the Mangistau Oblast.
The Group is in the process of acquiring Block 8, an oilfield with many of the characteristics of BNG and is 160 km away. The Group has also agreed to acquire the West Shalva Contract Area, an oilfield expected to be easier to develop than either BNG or Block 8 and nearer road and refinery infrastructure but without the deep prospects of BNG and Block 8.
The Group owns the Caspian Explorer, a purpose built drilling vessel designed to explore the shallow reaches of the Caspian Sea. The Caspian Explorer has a construction cost of approximately $200 million in 2012 and a replacement cost believed to be approximately $300 million today.
The Group also has a 100% interest in the 3A Best Contract Area, although the licence there has expired.
Further acquisitions are expected. |
| Principle 2
Seek to understand and meet shareholder needs and expectations
| Shareholder communications
The Company communicates with its shareholders via RNS announcements, its website, formal company meetings and periodic investor presentations. However, the need to avoid selectively releasing price sensitive information often limits our ability to provide the answers many investors seek.
The Company's management meets prospective institutional investors from time to time to assess the availability of large-scale institutional funding to advance the Group's plans.
Our shareholders A large proportion of the Company's shares are held by a relatively small group, namely: The Oraziman family (48.3%); Korean shareholders (9.97%); shareholders in Switzerland (4.91%); shareholders in the UAE (4.91)%; with the remaining (31.91)% being principally other Kazakh or UK based investors.
There is a contact form available for investors to use on the website: https://www.caspiansunrise.com/contact/contact-form/ |
| Principle 3
Take into account wider stakeholder and social responsibilities and their implications for long term success | Our stakeholders
In addition to our shareholders the Company regards its employees and their families, local and national government, suppliers and customers to be the core of the wider stakeholder group.
Employees Almost all staff employed by the Group are based in Kazakhstan. The Group draws most of its field workers from the Mangistau region where alternative employment opportunities are limited. At our head office in Almaty we employ further staff, some of whom hold highly skilled positions.
As well as providing employees with appropriate remuneration and other benefits together with a safe and enjoyable working environment, the Board recognises the importance of communication with employees to motivate them and involve them fully in the business. For the most part, this communication takes place at a local level, but staff are kept informed of major developments through email updates and staff meetings.
Local communities The Group has provided significant financial support to the Mangistau region for over a decade by way of social payments sometimes delivered in the form of medical or educational facilities for the local population.
Part of our work programme obligations are paid in the form of contributions to local social programmes. We are pleased to have assisted in the development of these projects and look forward to contributing to others in the coming years.
Kazakh Government agencies and regulators The Kazakh authorities are responsible for granting licences to explore for and produce oil. Licences are awarded subject to agreed work programmes being adhered to over the period of each licence renewal. This includes compliance with rules designed to preserve the environment.
Caspian Sunrise has an extremely high proportion of Kazakh nationals in our workforce and among our core shareholder group. The Board believes that this helps create a positive relationship with the Kazakh authorities and has assisted in the Group's day-to-day dealings with regulators.
External stakeholders Many additional jobs have been funded in the Company's suppliers, partners and professional advisers.
Feedback The Company considers feedback from its stakeholders in its decisions and actions. |
| Principle 4
Embed effective risk management, considering both opportunities and threats, throughout the organisation | Risk assessment
Oil & gas and mining exploration and production are dangerous activities and as such are necessarily subject to an extreme health and safety regime. Risk assessment and evaluation is an essential part of the Company's planning and an important aspect of the Company's internal control system.
It is planned to introduce a formal risk register, including all the principal operational and non-operational risks to the business. Such a risk register would be reviewed and assessed at least once a year by the Audit Committee.
A summary of the principal risks facing the Group are set out in the Principal Risks section on page 35 of these Financial Statements.
As stated elsewhere in these financial statements, the relatively small size of the board and the lack of independent non-executive directors makes the operation of the board committee systems envisaged under the QCA code very difficult to follow. The board intends to address this with the appointment of additional and independent non-executive directors |
| Principle 5
Maintain the board as a well-functioning, balanced team led by the chair | Board composition
The board currently comprises three executive directors and one non-executive director. All are male with two Kazakh nationals, one South Korean national and a national from the United Kingdom.
Executive directors At the executive level Kuat Oraziman, Chief Executive Officer, and Seokwoo Shin Chief Operating Officer run the Company's operations in Kazakhstan with Clive Carver, Chairman and Chief Financial Officer, taking the lead on financial and non-operational matters including all aspects related to the listing of the Company's shares on AIM, Corporate Governance compliance and Investor Relations.
Kuat Oraziman is a trained geologist and member of the Academy of Sciences. He has nearly 30 years oil and gas experience in Kazakhstan.
Seokwoo Shin worked for the Korean National Oil Corporation from 1987 until 2018 with spells in Korea, the United Kingdom, Russia and most recently Kazakhstan, where he was responsible for KNOC's Kazakh oil fields. He joined Caspian Sunrise in 2018.
Clive Carver is a fellow of the Institute of Chartered Accountants in England and Wales (FCA) and a Fellow of the Association of Corporate Treasurers (FCT). While working in the UK broking industry Clive gained more than 15 years' experience as a Qualified Executive under the AIM Rules having led the Corporate Finance departments of several of the larger and more active Nominated Adviser firms.
Non-executive director Aibek Oraziman, is the Company's largest shareholder with 46.4% of the Company's shares. He has more than 14 years oil and gas experience in Kazakhstan, including 3 years in the field at Aktobe working for a local oil company.
The board believes it possesses the skills required to build a successful and durable oil and gas business focused on Kazakhstan.
The board meets a minimum of four times each year supported by periodic telephone meetings. At such meetings the board receives a report from Kuat Oraziman on all matters operational and from Clive Carver on non-operational matters.
The board also has a list of standing items, including compliance with the UK Bribery Act, litigation, and existence of open and closed periods for director dealings, which are considered at each meeting.
The number of board meetings attended each year by the directors is set out in the Directors' report which forms part of the Annual Report and Financial Statements.
Board committees
While the Audit, Remuneration and Governance committees remain in place, but with only four directors and only one non-executive director much of the work typically undertaken in the board committees has been handled by the board as a whole.
We expect to make additional appointments to board as funding improves later in the year that would help move back to a more traditional board committee set up.
Departures from the Code
Executive Chairman The principal reason advanced by proponents of the Code that the Chairman be non-executive is to split the roles of Chairman and Chief Executive Officer as combining them puts too much control in one pair of hands. This is not the case with our Company where the Chief Executive Officer's family is the largest shareholding group, with some 48.3%.
Clive Carver was appointed Non-Executive Chairman of the Company in 2006 in the lead-up to the IPO the following year. In 2012 he was appointed Executive Chairman at the same time as Kuat Oraziman moved from Non-Executive Director to Chief Executive Officer.
Clive Carver has served as non-executive chairman of eight AIM listed companies. In addition, his 15 years as a Qualified Executive and head of active corporate finance departments make him a very suitable candidate to be Chairman, notwithstanding his executive status.
Non-Executive Directors' participation in Option Schemes In common with many AIM listed companies we actively encourage non-executive directors to participate in the Company's option schemes, although it is not currently the case. Proponents of the Code believe this affects the independence of the non-executive directors concerned.
We believe that independence is a matter of independence of mind, judgement, and integrity. We consider our non-executives' ability to act independently to be unaffected by the level of participation in the Company's option scheme.
|
| Principle 6
Ensure that between them the directors have the necessary up-to-date experience, skills, and capabilities.
| Experience
The experience of the directors and the operational board is set out in the response to Principle 5 above and in the Annual Report and Financial Statements.
Operational skills are maintained through an active day to day interaction with leading international consultancies and contractors engaged to assist in the development of the Company's assets.
Non-operational skills are maintained principally via the Company's interaction with its professional advisers plus the experience gained from sitting on the boards of other commercial enterprises.
As the Company develops and moves from predominantly an oil exploration company to a balanced production and exploration company with both oil & gas and mining projects, the board will periodically re-assess the adequacy of the skills on both the main board and the operational board. Where gaps are found, new appointments will be sought. |
| Principle 7
Evaluate board performance based on clear and relevant objectives, seeking continuous improvement | Performance
The Company currently does not evaluate board performance on a formal basis. However, it will in due course seek to formalise the assessment of both executive and non-executive board members.
The Company is aware of its need to facilitate succession planning and the board evaluation process will form part of this going forward. |
| Principle 8
Promote a corporate culture that is based on ethical values and behaviours.
| Culture
Our culture can best be described as one where we strive for commercial success while treating others fairly and with respect. The board firmly believes that sustained success will best be achieved by following this simple philosophy.
Accordingly, in dealing with each of the Company's principal stakeholders, we encourage our staff to operate in an honest and respectful manner.
Operating with integrity is clearly good business and forms an important part of the annual assessment of staff and in setting their pay for future periods. |
| Principle 9
Maintain governance structures and processes that are fit for purpose and support good decision-making by the board | Governance
The Company believes that its stated governance structures and processes are consistent with its current size and complexity, while acknowledging the size of the board as currently constituted makes adherence to such a governance regime difficult in practice.
The Board is aware that it must continue to review its practices as the Company evolves and grows and intends to make further appointments to the board as circumstances permit.
The executive members of the Board have overall responsibility for managing the day-to-day operations of the Company and the Board as a whole is responsible for implementing the Company's strategy.
The Audit Committee typically meets before each set of results (interim and final) are published and the Remuneration Committee typically meets at least once a year, when the Financial Statements for the Full year results are approved. All Committee members attend these meetings.
Our Report and Accounts contain reports from the Chairman of the Remuneration. and the Audit Committee.
The appropriateness of the Company's governance structures will be reviewed annually in light of further developments of accepted best practice and the development of the Company. |
| Principle 10
Communicate how the company is governed and is performing by maintaining a dialogue with shareholders and other relevant stakeholders | Communications
The Company reports formally to its shareholders and the market twice each year with the release of its interim and full year results.
The Annual Report and Financial Statements set out how the corporate governance of the Company has been applied in the period under review including the work undertaken by the Audit Committee and the Remuneration Committee.
The Annual Report and Financial Statements contain full details of the principal events of the relevant period together with an assessment of current trading and prospects. They are sent to shareholders and made available on the Company's website to anyone who wishes to review them.
The Board already discloses the result of general meetings by way of RNS announcements, disclosing the voting numbers. The Company's website also contains all the information prescribed for an AIM Company under Rule 26.
Further details of the Company's dialogue with its shareholders are set out under Principle 2 above.
Employee stakeholders are regularly updated with the development of the Company and its performance.
We are in almost constant communication with our Governmental and regulatory stakeholders via their involvement in our day-to-day operational activities. |
Board composition, skills and capabilities
From 1 January 2023 to 7 July 2023 the Board comprised three executive directors and two non-executive directors. From 8 July 2023 following the resignation of Edmund Limerick until 31 December 2023, the Board comprised three executive directors and one non-executive director, which remains the position at the date of this report.
Clive Carver, Executive Chairman and Chief Financial Officer
Clive is a fellow of the Institute of Chartered Accountants in England and Wales (FCA) and a Fellow of the Association of Corporate Treasurers (FCT). He is an experienced public company director having been chairman of a number of AIM companies in recent years.
Kuat Oraziman, Chief Executive Officer
Kuat Oraziman runs the Company's operations in Kazakhstan. Kuat Oraziman is a trained geologist and member of the Academy of Sciences. He has nearly 30 years oil and gas experience in Kazakhstan.
Seokwoo Shin, Chief Operating Officer
Seokwoo Shin was educated at Sungkyunkwan University in Korea. He worked for the Korean National Oil Corporation from 1987 until 2019 with spells in Korea, the United Kingdom, Russia and most recently Kazakhstan, where he was responsible for KNOC's Kazakh oil fields. He joined Caspian Sunrise in 2018 and on 4 March 2021 was appointed to the board as Chief Operating Officer.
Aibek Oraziman, Non-executive director
Aibek Oraziman was educated in Kazakhstan and in the United Kingdom. He has more than 14 years oil and gas experience in Kazakhstan, including 3 years in the field at Aktobe working for a local oil company. He was appointed to the Caspian Sunrise board on 21 August 2020.
The Board believes it possesses the skills required to build a successful and durable oil and gas business focused on Kazakhstan but recognises the need for the appointment of additional non-executive directors.
Board and committee meetings
Attendances of Directors at board and committee meetings convened in the year, and which they were eligible to attend in person or by telephone, are set out below:
| Director | Board meetings attended | Remuneration Committees attended | Audit Committee attended |
| Clive Carver | 5 of 5 | 1 of 1 | 2 of 2 |
| Kuat Oraziman | 5 of 5 | N/A | N/A |
| Edmund Limerick | 3 of 3 | 1 of 1 | 2 of 2 |
| Seokwoo Shin | 5 of 5 | N/A | N/A |
| Aibek Oraziman | 5 of 5 | 1 of 1 | 2 of 2 |
The Board has established the following committees:
Audit Committee
The Audit Committee which comprises Aibek Oraziman and Clive Carver, with Clive Carver as acting Chairman, determines and examines any matters relating to the financial affairs of the Group including the terms of engagement of the Group's auditors and, in consultation with the auditor, the scope of the audit.
The Audit Committee receives and reviews reports from the management and the external auditor of the Group relating to the annual and interim amounts and the accounting and internal control systems of the Group. In addition, it considers the financial performance, position and prospects of the Group and the Company and ensures they are properly monitored and reported on.
Remuneration Committee
The Remuneration Committee, which comprises Aibek Oraziman and Clive Carver, with Aibek Oraziman as Chairman, reviews the performance of the senior management, sets and reviews their remuneration and the terms of their service contracts and considers the Group's bonus and option schemes.
Board committee membership in 2023
| Director | Audit Committee | Remuneration Committee | Corporate Governance Committee | |||
| | Served from | Served to | Served from | Served to | Served from | Served to |
| Clive Carver | 1 January | 31 December | 1 January | 31 December | 1 January | 31 December |
| Kuat Oraziman | N/A | N/A | N/A | N/A | N/A | N/A |
| Edmund Limerick | 1 January | 7 July | 1 January | 7 July | 1 January | 7 July |
| Seokwoo Shin | N/A | N/A | N/A | N/A | N/A | N/A |
| Aibek Oraziman | 1 January | 31 December | 1 January | 31 December | 1 January | 31 December |
Clive Carver
Chairman
15 July 2024
REMUNERATION COMMITTEE REPORT
Remuneration Committee
Between 1 January 2023 and 7 July 2023, the Remuneration Committee comprises Edmund Limerick, Aibek Oraziman and Clive Carver and was chaired by Edmund Limerick. From 8 July 2023 the Remuneration Committee comprised Aibek Oraziman and Clive Carver, with Aibek Oraziman as Chairman.
Remuneration policy
The Remuneration Committee determines the contract term, basic salary, and other remuneration for the members of the Board and the senior management team.
The Group's and the Company's policy is to provide remuneration packages that will attract, retain and motivate its executive Directors and senior management. This consists of a basic salary, ancillary benefits and other performance-related remuneration appropriate to their individual responsibilities and having regard to the remuneration levels of comparable posts. However, starting in 2020 the Covid-19 impact on the Group's finances required the Directors to accept reductions of up to 75% of contracted salary which continues to be the case.
Agreement has been reached to begin to relax the salary reductions as the Group's funding position improves with the first relaxation expected in Q3 2024.
Service contracts
Details of the current Directors' service contracts are as follows:
| Executive |
| Date of service agreement / appointment letter | Date of last renewal of appointment |
| Clive Carver | | 20 March 2019 | 27 June 2024 |
| Kuat Oraziman | | 6 December 2019 | 30 June 2023 |
| Aibek Oraziman | | 21 August 2020 | 30 June 2023 |
| Seokwoo Shin | | 4 March 2021 | 30 June 2023 |
Notwithstanding their service agreements or letters of appointment the directors who served throughout the period under review have agreed until further notice to restrict their remuneration to approximately 25% of previous amounts without any accrual for the up to 75% sacrificed.
Basic salary and benefits
The basic salaries of the Directors who served during the financial year are established by reference to their responsibilities and individual performance.
| Directors
| Role
| 2023 Salary / fees US$ | Terminated benefits US$ | 2023 Benefits US$ | 2023 Total US$ | 2022 Total US$ | |
| Clive Carver | Chairman | 152,698 | - | 9,805 | 162,503 | 152,698 | |
| Kuat Oraziman | CEO | 145,484 | - | - | 145,484 | 156,753 | |
| Seokwoo Shin | COO | 55,000 | - | - | 55,000 | 54,000 | |
| Edmund Limerick # | Non-executive | 5,882 | 66,500 | - | 72,382 | 16,319 | |
| Aibek Oraziman | Non-executive | 10,000 | - | - | 10,000 | - | |
| Total |
| 369,064 | 66,500 | 9,805 | 445,369 | 379,770 | |
# Edmund Limerick resigned as a director effective from 7 July 2023.
There were no company pension contributions in respect of any director.
Bonus schemes
All Executive Directors are eligible for consideration of participation in the Company bonus scheme. However, as in previous years no bonuses are payable in respect of the year ended 31 December 2023 (2022: nil).
Long term incentives
Share options
The current interests as at approval of accounts of the current Directors in share options agreements are as follows:
| Directors | Granted | Exercise price (p) | Expiry Date |
| Clive Carver | 2,400,000 | 4 | 30 April 2025 |
| Clive Carver | 3,000,000 | 20 | 21 August 2024 |
| Kuat Oraziman | 3,000,000 | 20 | 21 August 2024 |
| Seokwoo Shin | 2,500,000 | 4 | 24 April 2034 |
The position as set out in the 2022 financial statements was as follows:
| Directors | Granted | Exercise price (p) | Grant date | Expiry Date | |||
| Clive Carver | 2,400,000 | 4.0 | 15 December 2013 | 14 December 2023 | |||
| Clive Carver | 3,000,000 | 20.0 | 22 August 2014 | 21 August 2024 | |||
| Kuat Oraziman | 3,000,000 | 20.0 | 22 August 2014 | 21 August 2024 | |||
| Edmund Limerick | 750,000 | 20.0 | 22 August 2014 | 21 August 2024 | |||
| Edmund Limerick | 1,000,000 | 20.0 | 6 June 2019 | 5 June 2029 | |||
| Edmund Limerick | 1,000,000 | 5.5 | 10 January 2022 | 9 January 2032 | |||
| Seokwoo Shin | 2,500,000 | 5.5 | 10 January 2022 | 9 January 2032 | |||
The exercise date of 2,400,000 options held by Clive Carver, which were not capable of exercise before the expiry date of 14 December 2023 as the Company was in an extended close period, have been extended until 30 April 2025.
There were no options exercised in 2023. To date in 2024, 4,500,000 options have been granted including on 24 April 2024, 2,500,000 options granted to Seokwoo Shin at an exercise price of 4.0p. At that time 2,500,000 options then held by Seokwoo Shin, exercisable before 9 January 2032 were cancelled.
The total number of options at the date of this report is 16,850,000 representing approximately 0.75% of the total number of issued shares.
Cash based incentives
In May 2019, we introduced cash based long term incentive arrangements for the senior management team since 2012, Kuat Oraziman and Clive Carver.
Under these arrangements, provided the share price growth exceeds pre-set targets starting at 17.23p, then for every $500 million increase in the Group's market capitalisation above $300 million, as adjusted to take account of dividends paid, both Kuat Oraziman and Clive Carver, would receive payments of $3 million each.
The principal hurdles under these arrangements are set out in the table below.
| Market cap threshold | Share price target | Pay-out rate (each) | Pay-out amount (each) |
| $' billion | Pence per share | % | $' million |
| | | | |
| 0.8 | 17.23 | 0.6 | 3.0 |
| 1.3 | 20.67 | 0.6 | 3.0 |
| 1.8 | 24.81 | 0.6 | 3.0 |
| 2.3 | 29.77 | 0.6 | 3.0 |
| 2.8 | 35.72 | 0.6 | 3.0 |
The scheme continues beyond the numbers in the table such that with the threshold for market capitalisation increasing at the rate of $0.5 billion and the corresponding share price threshold increasing from the earlier threshold by a constant factor of 1.2.
Each threshold must be sustained for at least 30 consecutive days for the awards to be triggered. There may be only one pay-out for each market capitalisation threshold crossed no matter how many times it is crossed.
Whilst the Incentive Scheme is in place neither of the recipients will be granted any further options.
On behalf of the Directors of Caspian Sunrise plc
Aibek Oraziman
Chairman of Remuneration Committee
15 July 2024
AUDIT COMMITTEE REPORT
The Audit Committee
The Audit Committee, which between 1 January and 7 July 2023 comprised Edmund Limerick, Clive Carver and Aibek Oraziman, with Edmund Limerick acting as Chairman, and from 8 July 2023 comprised Clive Carver and Aibek Oraziman with Clive Carver as Acting Chairman, determines and examines any matters relating to the financial affairs of the Group including the terms of engagement of the Group's auditors and, in consultation with the auditor, the scope of the audit.
Role and responsibilities
The Audit Committee is responsible for monitoring the integrity of the Company's financial statements, reviewing significant financial reporting issues, reviewing the effectiveness of the Group's internal control and risk management systems.
In addition, it considers the financial performance, position and prospects of the Group and the Company and ensures they are properly monitored and reported on. It oversees the relationship with the Auditor (including advising on their appointment, agreeing the scope of the audit and reviewing the audit findings).
Meetings
The committee met on two occasions during the year under review.
Internal audit
The Board and the Audit Committee do not consider it appropriate for the current size of the Group to establish an internal audit function. However, this will be kept under review.
Attendance at Audit Committee meetings
Please see the table in the preceding Corporate Governance Report for attendance by the members of the Audit Committee.
Group auditors
In October 2023 PKF Littlejohn LLP were appointed Group auditors, replacing BDO LLP.
On behalf of the Directors of Caspian Sunrise plc
Clive Carver
Acting Chairman of Audit Committee
15 July 2024
INDEPENDENT AUDITORS REPORT TO THE MEMBERS OF CASPIAN SUNRISE PLC
Qualified opinion on the Group financial statements and unmodified opinion on the Parent Company financial statements
We have audited the financial statements of Caspian Sunrise plc (the 'Parent Company') and its subsidiaries (the 'Group') for the year ended 31 December 2023 which comprise the Consolidated Statement of Profit or Loss, the Consolidated Statement of Comprehensive Income, the Consolidated and Parent Company Statements of Changes in Equity, the Consolidated and Parent Company Statements of Financial Position, the Consolidated and Parent Company Statements of Cash Flows and the notes to the financial statements, including a summary of significant accounting policies. The financial reporting framework that has been applied in their preparation is applicable law and UK adopted international accounting standards and as regards the Parent Company financial statements, as applied in accordance with the provisions of the Companies Act 2006.
In our opinion, except for the effects of the matter described in the Basis for qualified opinion section on the Group financial statements and unmodified opinion on the Parent Company financial statements section of our report:
· the financial statements give a true and fair view of the state of the Group's and of the Parent Company's affairs as at 31 December 2023 and of the Group's profit for the year then ended;
· the Group financial statements have been properly prepared in accordance with UK adopted international accounting standards;
· the Parent Company financial statements have been properly prepared in accordance with UK adopted international accounting standards and as applied in accordance with the provisions of the Companies Act 2006; and
· the financial statements have been prepared in accordance with the requirements of the Companies Act 2006.
Basis for qualified opinion on the Group financial statements and unmodified opinion on the Parent Company financial statements
In 2023, 2022 and 2021, the Group's subsidiary, CTS LLP, provided drilling services to both an external related party, EPC Munai LLP, and within the Group to fellow subsidiary BNG Ltd LLP.
For drilling services provided to external entities, costs should be recognised in cost of sales, which impacts the amount of revenue recognised under the input method as detailed in notes 1.5 and 1.6. Drilling costs provided to other entities in the Group may be capitalised, subject to compliance with relevant accounting standards as detailed in notes 1.9 and 1.10.
The prior year audit report, which was issued by the predecessor auditor, contained a qualified opinion in respect of the Directors being unable to obtain reliable information for CTS LLP in respect of the timing of the related direct costs being incurred, their allocation between different contracts with EPC Munai LLP, and whether the costs should have been allocated to cost of sales (which impacts external revenue recognised), or capitalised in the Group's Property Plant and Equipment or Unproven oil and gas assets. In addition, the Directors were unable to provide updated budgets for estimated costs to complete. This information is necessary to determine revenue, costs of sales, advances received/ receivable, provisions for losses on contracts, property, plant and equipment, unproven oil and gas assets, related tax balances and related party disclosures and as a result the predecessor auditor concluded that these balances may be materially higher or lower than those reported in the signed 2022 financial statements.
Following the issue of the 2022 financial statements, and as explained in note 3, management performed a detailed review of CTS LLP's books and records relating to its drilling contracts. As a result, a number of adjustments to previously reported balances were required, and restatements made to relevant line items in relation to the 2022 and 2021 financial years, as shown and explained further in note 3.
Following this review by management, included in the Group's revenue in 2023 is USD 4,126,000 (2022 restated: USD 1,590,000) of drilling revenue related to contracts with EPC Munai LLP and USD 4,735,000 (2022 restated: USD 1,834, 000) of related cost of sales.
We have reviewed the exercise performed by management relating to the adjustments to the 2022 and 2021 financial statements and, based on the information provided, have been unable to gain sufficient assurance surrounding the basis for cost allocation between the various contracts with EPC Munai LLP, or the timing of these costs being incurred, both of which drive the revenue recognition for each year. As a result, we are unable to conclude whether or not the impacted line items in the 2022 financial statements, as restated (see note 3) are materially misstated. We have therefore also been unable to obtain sufficient appropriate audit evidence over the accuracy of the Group's external drilling revenues or the completeness and validity of its cost of sales allocation for the 2023 financial year. Our opinion is therefore qualified in respect of these matters. The contracts with EPC Munai LLP were concluded before the 2023 year end and therefore we are satisfied based on work performed that the closing Group statement of financial position is materially correct.
We conducted our audit in accordance with International Standards on Auditing (UK) (ISAs (UK)) and applicable law. Our responsibilities under those standards are further described in the Auditor's responsibilities for the audit of the financial statements section of our report. We are independent of the company in accordance with the ethical requirements that are relevant to our audit of the financial statements in the UK, including the FRC's Ethical Standard as applied to listed entities, and we have fulfilled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our qualified opinion.
Material uncertainty in relation to going concern
We draw attention to note 1.1 in the financial statements concerning the Group's and the Parent Company's ability to continue as a going concern. Note 1.1 highlights that the Group has significant net current liabilities of approximately USD 14,300,000 as at the year end, and that the forecast cashflows are dependent on key factors including ,oil price and volume sold, continued availability of oil trader advances, deferral of financial obligations and the receipt of funds from the charter of the Caspian Explorer. As stated in note 1.1, these events or conditions, along with other matters as set out in note 1.1, indicate that a material uncertainty exists that may cast significant doubt on the Group's and the Parent Company's ability to continue as a going concern. Our opinion is not modified in respect of this matter.
In auditing the financial statements, we have concluded that the Directors' use of the going concern basis of accounting in the preparation of the financial statements is appropriate. Our evaluation of the Directors' assessment of the Group's and the Parent Company's ability to continue to adopt the going concern basis of accounting included:
· Obtaining the directors' going concern assessment and evaluating the appropriateness of this assessment;
· Obtaining cashflow forecasts for the period to 31 December 2025 used to support this assessment, ascertaining the key assumptions and inputs used in the preparation of the forecasts, and assessing the reasonableness of such assumptions and inputs. This included, where possible, agreeing the inputs to underlying supporting documentation, and sensitising key assumptions;
· Comparing oil prices to available market data and production levels to historic operating information;
· Comparing forecast income and expenses with recent historical financial information to consider the accuracy of management's forecasting;
· Agreeing cash balances to the opening working capital position and testing the mathematical accuracy of the forecasts;
· Considering external market factors affecting the Group and its future economic viability, such as oil prices and the ongoing lack of viability of international sales as a result of the sanctions imposed against Russia;
· Evaluating the completeness of forecast licence related expenditure included in the forecasts. We held discussions with the Directors and those charged with governance regarding the intention to seek a 2 year extension to the appraisal licence covering the Airshagyl an Yelemes Deep structures before then applying for separate 25 year production licences;
· Comparing the forecast cash payments in respect of the BNG production licence award against the USD 32,000,000 assessment received from the Government payable in instalments over 10 years. We ensured that the relevant instalments are included in the forecast;
· Assessing the reasonableness of cash inflows included in the forecasts including those relating to oil production and the Group's maiden offshore drilling chartering contract for the Caspian Explorer, including agreement to the underlying contract for the latter;
· Evaluating the possibility of obtaining cash through sale of key assets, and examined available documentation as well as publicly available announcements in respect of these matters;
· Assessing the validity of any mitigating actions identified by the Directors; and
· Reviewing the adequacy and completeness of the disclosures included within the financial statements in respect of going concern based on our understanding of the business and the Group's current financial position, and the uncertainties surrounding the going concern position.
Our responsibilities and the responsibilities of the Directors with respect to going concern are described in the relevant sections of this report.
Our application of materiality
We apply the concept of materiality in both planning and performing the audit and evaluating the effect of misstatements. Based on our professional judgement, we determined materiality for the financial statements as follows:
| | Group financial statements | Parent Company financial statements |
| Materiality | USD 1,960,000 | USD 1,170,000
|
| Basis for determining materiality | 1.5% of gross assets
| 3% of net assets, capped below group Performance materiality
|
| Rationale for the benchmark applied | We have determined an asset based measure is appropriate as the Group continues to focus on the development of its key oil and gas exploration and production activities, which require significant capital expenditure. | The Parent Company is a holding company; therefore, materiality was set on the net assets basis. |
Performance materiality
We set performance materiality at a level lower than materiality to reduce the probability that, in aggregate, uncorrected and undetected misstatements exceed the materiality for the financial statements as a whole.
| | Group financial statements | Parent Company financial statements |
| Performance materiality | USD 1,176,000
| USD 702,000
|
| Basis for determining materiality | 60% of materiality | 60% of materiality
|
| Rationale for the benchmark applied | Performance materiality for the current year was set based our assessment of the control environment including identified control deficiencies. | |
Our audit procedures were performed to materiality levels applicable to each component, which were lower than the Group materiality level and ranged from USD 290,000 to USD 1,170,000.
In the audit of each component, we further applied performance materiality levels of 60% of the component materiality to our testing to ensure that the risk of errors exceeding component materiality was appropriately mitigated.
We agreed with those charged with governance that we would report to them all audit differences identified during the course of our audit in excess of USD 98,000. We also agreed to report any other audit misstatements below that threshold that we believe warranted reporting on qualitative grounds.
Our approach to the audit
Our audit approach was developed by obtaining an understanding of the Group's and Parent Company's activities, the key subjective judgments made by the directors, for example in respect of the significant accounting estimates regarding the valuation of unproven oil and gas assets and the accounting treatment of CTS LLP drilling contracts, considering future events that are inherently uncertain, and the overall control environment. Based on this understanding we assessed those aspects of the Group's and Parent Company's transactions and balances which were most likely to give rise to a material misstatement and were most susceptible to irregularities including fraud or error. Specifically, we identified what we considered to be key audit matters and planned our audit approach accordingly.
The Group's operations principally comprise oil and gas exploration and production in Kazakhstan. We assessed there to be five significant components comprising BNG Ltd LLP, CTS LLP, KC Caspian Explorer LLP, Roxi Petroleum Kazakhstan LLP, and the Parent Company. These components, which were subject to full scope audit procedures, represent the principal business units.
A non-PKF member firm performed a full scope audit of BNG Ltd LLP, CTS LLP, KC Caspian Explorer LLP and Roxi Petroleum Kazakhstan LLP in Kazakhstan, under our direction and supervision as Group auditors. The audit of the Parent Company and the Group consolidation were performed in the United Kingdom by us.
The remaining components of the Group were considered non-significant and these components were subject to either specified audit procedures by the component auditor, to address risks assessed at the Group level or to gain comfort over material items, or analytical review procedures by the Group audit team. The Group audit team performed additional procedures in respect of certain significant risk areas that represented Key Audit Matters.
Our involvement with component auditors included the following:
• Detailed Group reporting instructions were sent to the component auditors, which included the significant areas to be covered by the audit.
• We reviewed the component auditor's working papers, both in Kazakhstan and remotely from the UK. In addition, we reviewed the Group reporting submissions received from the component audit teams and held regular calls with the component audit teams during the planning, fieldwork and completion phases of their audit to discuss significant findings from their audit.
• We performed additional procedures in respect of the significant risk areas where deemed necessary.
Key audit matters
Key audit matters are those matters that, in our professional judgment, were of most significance in our audit of the financial statements of the current period and include the most significant assessed risks of material misstatement (whether or not due to fraud) we identified, including those which had the greatest effect on the overall audit strategy, the allocation of resources in the audit; and directing the efforts of the engagement team. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters. In addition to the matter described in the Material uncertainty related to going concern section, and the matter disclosed in the Basis for qualified opinion section, we have determined the matters described below to be the key audit matters to be communicated in our report.
| Key Audit Matter - Valuation of unproven oil and gas assets [Note 12] The carrying value of Group's unproven oil and gas assets as at 31 December 2023 was USD 51,963,000. In accordance with IFRS 6 Exploration for and Evaluation of Mineral Resources, assets should be held at cost and an annual assessment of impairment indicators performed and, where such indicators exist, perform an impairment assessment in accordance with IAS 36 Impairment. Given the level of management estimates and judgement required in determining the recoverability of these assets, there is a risk that management may not adequately identify all impairment indicators. As such, there is a risk that the carrying value of these assets is impaired and that exploration and development costs capitalised during the year have not been capitalised in accordance with IFRS 6. As a result of the significant estimates and judgement required to be exercised by management, as well as the quantum of this balance, we consider this to be a key audit matter. How our scope addressed this matter Our work in this area included: · Reviewing the work of the component auditor's testing of additions in the year, as well as performing additional work in this area, such as vouching costs to supporting documentation to ensure that costs have been appropriately capitalised in accordance with IFRS 6 and the Group's accounting policies; · Obtaining confirmation that the Group has good title to the applicable exploration licences, and assessing compliance with terms of the licences through making enquiries of management and the legal consultant; · Obtaining management's review of indicators of impairment and considering the reasonableness of this assessment in accordance with the requirements of IFRS 6. · Performing an independent assessment as to whether any of the impairment indicators as per IFRS 6 have been met and if so, whether any impairment is necessary. · Inspecting cash flow forecasts to confirm that further drilling and exploration is planned for the licenced areas, as well as reviewing internal and external information available during the year and post-year end such as Board minutes and Regulatory News Service announcements for evidence of potential impairment; · Evaluation of the results of exploration activity in the year for indications that the licences would be abandoned or that the recoverable value would be below carrying value; and · Reviewing disclosures in the financial statements to ensure compliance with the requirements of IFRS.
Key observations We draw attention to the disclosure within Notes 12 Unproven oil and gas assets and 2.2.2 within the Critical Accounting Estimates and Judgements, which state that the Group's existing appraisal licence will expire in August 2024 and that the Group has in July 2024 submitted an application to extend the licence for a further 2 years. Should the application to extend the licence not be successful, this could result in impairment to valuation of the unproven oil and gas assets. |
| Key audit matter - Accounting treatment of CTS LLP drilling services [Notes 3 and 4; Accounting policies 1.5 and 2.1.2] The accounting treatment of contracts to provide drilling services held within entity CTS LLP with external related party EPC Munai LLP is dependent on the existence of reliable information in respect of the timing of the costs being incurred, their allocation between different contracts and whether costs should have been allocated to cost of sales or capitalised as property plant and equipment. As such, there is a risk that the accounting treatment is not in accordance with IFRS. How the scope of our audit responded to the key audit matter Our work in this area included: • Obtaining management's schedules relating to the analysis of the accounting treatment of the contracts on a contract-by-contract basis and providing challenge to, and corroborating, key inputs and assumptions being used, including: o vouching revenue amounts to underlying contracts; o testing a sample of costs to supporting documentation including confirmation of well number, on which the allocation to contract is based, to confirm accuracy of costs; o assessing the appropriateness of allocation between contracts, and o evaluating the reasonableness of allocation between cost of sales (external contracts) and capitalised assets (BNG contracts); • Considering the appropriateness of revenue recognition in accordance with the requirements of IFRS 15 Revenue from Contracts with Customers for each contract, including reference to the relevant sales agreements and the key terms and conditions within the contracts; • Performing testing in accordance with IAS 37 Provisions, Contingent Liabilities and Contingent Assets to determine whether any provisions for losses for onerous contracts should be recognised as at 31 December 2023; and • Reviewing the disclosures in the financial statements to ensure compliance with the requirements of IFRS.
Key observations As explained in the Basis for qualified opinion, we have been unable to conclude as to whether material misstatements are present in the opening balances, nor whether revenue and cost of sales related to external drilling contracts during 2023 are accurate. However, on the basis of the audit procedures performed, we are satisfied that given that all contracts with EPC Munai LLP were concluded before 31 December 2023, the closing statement of financial position is not materially misstated in respect of the CTS LLP drilling contracts. |
Other information
The other information comprises the information included in the annual report, other than the financial statements and our auditor's report thereon. The Directors are responsible for the other information contained within the annual report. Our opinion on the Group and Parent Company financial statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we do not express any form of assurance conclusion thereon. Our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial statements or our knowledge obtained in the course of the audit, or otherwise appears to be materially misstated. If we identify such material inconsistencies or apparent material misstatements, we are required to determine whether this gives rise to a material misstatement in the financial statements themselves. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact.
As described in the basis for qualified opinion section of our report, we have concluded that other information may be materially misstated.
Opinion on other matters prescribed by the Companies Act 2006
Except for the matter described in the Basis for qualified opinion on other matters prescribed by the Companies Act 2006 section of our report, in our opinion, based on the work undertaken in the course of the audit:
· the information given in the Directors' report for the financial year for which the financial statements are prepared is consistent with the financial statements; and
· the Directors' report have been prepared in accordance with applicable legal requirements.
Based on the responsibilities described below and our work performed during the course of the audit, we are required by the Companies Act 2006 and ISAs (UK) to report on certain opinions and matters as described below.
Matters on which we are required to report by exception
Notwithstanding our Basis for qualified opinion, in the light of the knowledge and understanding of the company and its environment obtained in the course of the audit, we have not identified material misstatements in the Directors' report.
Arising from the limitation of our work performed in the Basis of qualified opinion section:
· we were unable to determine whether adequate accounting records have been kept; and
· we have not received all the information and explanations we require for our audit.
We have nothing to report in respect of the following matters in relation to which the Companies Act 2006 requires us to report to you if, in our opinion:
· returns adequate for our audit have not been received from branches not visited by us; or
· certain disclosures of directors' remuneration specified by law are not made.
Responsibilities of Directors
As explained more fully in the Directors' responsibilities statement, the Directors are responsible for the preparation of the financial statements and for being satisfied that they give a true and fair view, and for such internal control as the Directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.
In preparing the financial statements, the Directors are responsible for assessing the company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the Directors either intend to liquidate the company or to cease operations, or have no realistic alternative but to do so.
Auditor's responsibilities for the audit of the financial statements
Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these financial statements.
Irregularities, including fraud, are instances of non-compliance with laws and regulations. We design procedures in line with our responsibilities, outlined above, to detect material misstatements in respect of irregularities, including fraud. The extent to which our procedures are capable of detecting irregularities, including fraud is detailed below:
· We obtained an understanding of the company and the sector in which it operates to identify laws and regulations that could reasonably be expected to have a direct effect on the financial statements. We obtained our understanding in this regard through:
o Discussing with management, those charged with governance and those responsible for legal and compliance procedures, to understand how the Group is complying with those legal and regulatory frameworks; and
o Conducting and applying industry research and application of cumulative audit knowledge.
· We determined the principal laws and regulations relevant to the company in this regard to be those arising from:
o UK-adopted international accounting standards;
o Companies Act 2006;
o AIM Rules and the Quoted Companies Alliance Corporate Governance Code;
o Relevant industry laws and regulations in Kazakhstan, including relevant environmental regulations associated with oil and gas exploration and production activities;
o UK and Kazakh taxation and employment laws; and
o Terms of compliance included in the Group's production and exploration licences.
· We designed our audit procedures to ensure the audit team considered whether there were any indications of non-compliance by the company with those laws and regulations. These procedures included, but were not limited to:
o Reviewing minutes of meetings of those charged with governance for any instances of non-compliance with laws and regulations;
o Reviewing of Regulatory News Service announcements;
o Directing the auditors of the significant components to ensure an assessment was performed on the extent of the components' compliance with the relevant local and regulatory environment and a review of correspondence with regulatory and tax authorities was performed for any instances of non-compliance with laws and regulations;
o Reviewing the terms of the licences to assess the extent to which the Group was in compliance with the conditions of the licence and considering management's assessment of the impact of instances of non-compliance where applicable; and
o Review of legal expenditure accounts to understand the nature of expenditure incurred.
· We also identified the risks of material misstatement of the financial statements due to fraud. We considered, in addition to the non-rebuttable presumption of a risk of fraud arising from management override of controls, that the areas most susceptible to fraud were revenue recognition, valuation of unproven oil and gas assets and the accounting treatment of CTS LLP drilling services, on the basis that there is potential for management bias as a result of judgement being exercised, and we addressed this by challenging the assumptions and judgements made by management when auditing these areas. See Key audit matters section above.
· As in all of our audits, we addressed the risk of fraud arising from management override of controls by performing audit procedures which included, but were not limited to: the testing of journals; reviewing accounting estimates for evidence of bias; and evaluating the business rationale of any significant transactions that are unusual or outside the normal course of business.
Because of the inherent limitations of an audit, there is a risk that we will not detect all irregularities, including those leading to a material misstatement in the financial statements or non-compliance with regulation. This risk increases the more that compliance with a law or regulation is removed from the events and transactions reflected in the financial statements, as we will be less likely to become aware of instances of non-compliance. The risk is also greater regarding irregularities occurring due to fraud rather than error, as fraud involves intentional concealment, forgery, collusion, omission or misrepresentation.
A further description of our responsibilities for the audit of the financial statements is located on the Financial Reporting Council's website at: www.frc.org.uk/auditorsresponsibilitieshttp://www.frc.org.uk/auditorsresponsibilitieshttp://www.frc.org.uk/auditors/audit-assurance/auditor-s-responsibilities-for-the-audit-of-the-fi/description-of-the-auditor's-responsibilities-forhttps://www.frc.org.uk/auditors/audit-assurance/standards-and-guidance/2010-ethical-standards-for-auditors-(1). This description forms part of our auditor's report.
Use of our report
This report is made solely to the company's members, as a body, in accordance with Chapter 3 of Part 16 of the Companies Act 2006. Our audit work has been undertaken so that we might state to the company's members those matters we are required to state to them in an auditor's report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone, other than the company and the company's members as a body, for our audit work, for this report, or for the opinions we have formed.
Imogen Massey (Senior Statutory Auditor) 15 Westferry Circus
For and on behalf of PKF Littlejohn LLP Canary Wharf
Statutory Auditor London E14 4HD
15 July 2024
| Consolidated Statement of Profit or Loss
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| Notes | Year ended 31 December 2023 | *Restated Year ended 31 December 2022 |
| US$'000 | US$'000 | ||
| Revenue | 4 | 36,651 | 40,893 |
| Cost of sales | | (15,926) | (8,718) |
| Gross profit | | 20,725 | 32,175 |
| Selling expense | | (2,993) | (9,751) |
| Administrative costs | | (6,031) | (9,767) |
| Other operating income | 5 | 3,774 | 211 |
| Operating profit | 5 | 15,475 | 12,868 |
| Finance cost | 8 | (920) | (585) |
| Finance income | 9 | 231 | 59 |
| Profit before taxation | | 14,786 | 12,342 |
| Tax charge | 10 | (3,681) | (2,371) |
| Profit after taxation from continuing operations | | 11,105 | 9,971 |
| Profit attributable to owners of the parent | | 10,590 | 9,837 |
| Profit attributable to non-controlling interest | | 515 | 134 |
| Profit for the year |
| 11,105 | 9,971 |
| | | | |
| Earnings per ordinary share | | | |
| Basic (US cents) | 11 | 0.47 | 0.44 |
| Diluted (US cents) | 11 | 0.47 | 0.44 |
*See note 3 for details of prior year restatement.
Consolidated Statement of Comprehensive Income
|
| Year ended 31 December 2023 | *Restated Year ended 31 December 2022 |
| US$'000 | US$'000 | |
| | | |
| Profit after taxation | 11,105 | 9,971 |
| Other comprehensive income, net of tax: | | |
| Items that may be subsequently reclassified to profit or loss: | | |
| Exchange differences on translating foreign operations | 676 | (4,407) |
| Total comprehensive income for the year | 11,781 | 5,564 |
| Total comprehensive profit attributable to: | | |
| Owners of parent | 11,266 | 5,430 |
| Non-controlling interest | 515 | 134 |
| Total comprehensive income for the year | 11,781 | 5,564 |
* See note 3 for details of prior year restatement.
Consolidated Statement of Changes in Equity
|
| Share capital US$'000 | Share premium US$'000 | Deferred shares
US$'000 | Cumulative translation reserve US$'000 | Other reserves US$'000 | Merger reserve US$'000 | Retained profit US$'000 | Total attributable to the owner of the Parent US$'000 | Non-controlling interests US$'000 | Total equity US$'000 |
| Total equity as at 1 January 2023 - as stated | 33,060 | - | - | (66,521) | (2,362) | 11,511 | 84,872 | 60,560 | (5,667) | 54,893 |
| Correction prior year error (note 3) | - | - | - | 7 | - | - | (97) | (90) | - | (90) |
| Total equity as at 1 January 2023 - restated | 33,060 | - | - | (66,514) | (2,362) | 11,511 | 84,775 | 60,470 | (5,667) | 54,803 |
| Profit for the year | - | - | - | - | - | - | 10,590 | 10,590 | 515 | 11,105 |
| Other comprehensive income for the year: | | | | | | | | | | |
| Exchange differences on translating foreign operations | - | - | - | 676 | - | - | - | 676 | - | 676 |
| Total comprehensive income/(loss) for the year | - | - | - | 676 | - | - | 10,590 | 11,266 | 515 | 11,781 |
| Transactions with owners in their capacity as owners: | | | | | | | | | |
|
| Dividends declared (note 19) | - | - | - | - | - | - | (2,377) | (2,377) | - | (2,377) |
| Shareholder advance at below market rate (note 23) | - | - | - | - | 2,102 | - | - | 2,102 | - | 2,102 |
| Liquidation of subsidiary** | - | - | - | - | 2,362 | - | (2,362) | - | - | - |
| Total transactions with owners | - | - | - | - | 4,464 | - | (4,739) | (275) | - | (275) |
| Total equity as at 31 December 2023 | 33,060 | - | - | (65,838) | 2,102 | 11,511 | 90,626 | 71,461 | (5,152) | 66,309 |
|
| Share capital US$'000 | Share premium US$'000 | Deferred shares
US$'000 | Cumulative translation reserve US$'000 | Other reserves US$'000 | Merger reserve US$'000 | Retained profit / (deficit) US$'000 | Total attributable to the owner of the Parent US$'000 | Non-controlling interests US$'000 | Total equity US$'000 |
| Total equity as at 1 January 2022 - as stated | 31,118 | 164,817 | 64,702 | (62,103) | (2,362) | 11,511 | (156,239) | 51,444 | (5,801) | 45,643 |
| Correction prior year error (note 3) | - | - | - | (4) | - | - | (171) | (175) | - | (175) |
| Total equity as at 1 January 2022 - restated | 31,118 | 164,817 | 64,702 | (62,107) | (2,362) | 11,511 | (156,410) | 51,269 | (5,801) | 45,468 |
| Profit for the year (restated) | - | - | - | - | - | - | 9,837 | 9,837 | 134 | 9,971 |
| Other comprehensive income for the year: | | | | | | | | | | |
| Exchange differences on translating foreign operations (restated) | - | - | - | (4,407) | - | - | - | (4,407) | - | (4,407) |
| Total comprehensive income/(loss) for the year (restated) | - | - | - | (4,407) | - | - | 9,837 | 5,430 | 134 | 5,564 |
| Transactions with owners in their capacity as owners: | | | | | | | | | | |
| Shares issue (note 18) | 1,942 | 4,273 | - | - | - | - | - | 6,215 | - | 6,215 |
| Cancellation of share premium and deferred shares (note 30) | - | (169,090) | (64,702) | - | - | - | 233,792 | - | - | - |
| Dividends declared (note 19) | - | - | - | - | - | - | (2,444) | (2,444) | - | (2,444) |
| Total transactions with owners | 1,942 | (164,817) | (64,702) | - | - | - | 231,348 | 3,771 | - | 3,771 |
| Total equity as at 31 December 2022 - restated | 33,060 | - | - | (66,514) | (2,362) | 11,511 | 84,775 | 60,470 | (5,667) | 54,803 |
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*See note 3 for details of prior year restatement.
**Galaz Energy BV was liquidated in 2022 and during 2023 the Directors decided to transfer a separate equity reserve associated with the entity to Retained profit for capital maintenance purposes. The balance arose on acquisition of non-controlling interest in 2010.
Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of the nominal value
Deferred shares The nominal value of the deferred shares issued
Cumulative translation reserve Gains/losses arising on retranslating the net assets of overseas operations into US Dollars, less amounts recycled on disposal of subsidiaries and joint ventures
Other reserves Capital contribution arising on discounted loans
Merger reserves The excess of the fair value of the issues share capital over the nominal value of these shares issued for acquisition of at least 90 percent equity holding in subsidiaries
Retained profit/(deficit) Cumulative losses recognised in the consolidated statement of profit or loss, adjustments on the acquisition of non-controlling interests and transfers in respect of share based payments
Non-controlling interest The interest of non-controlling parties in the net assets of the subsidiaries
The notes on pages 64 to 91 are an essential part of these financial statements
Parent Company Statement of Changes in Equity
|
| Share capital US$'000 | Share premium US$'000 | Deferred shares US$'000 | Merger reserve US$'000 | Retained profit / (deficit) US$'000 | Total attributable to the owner of the Parent US$'000 | |
| Total equity as at 1 January 2023 | 33,060 | - | - | 11,511 | 59,012 | 103,583 | |
| Total comprehensive loss for the year | - | - | - | - | (1,336) | (1,336) | |
| Transactions with owners in their capacity as owners: |
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|
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| | | |
| Dividends declared (note 19) | - | - | - | - | (2,377) | (2,377) | |
| Total transactions with owners | - | - | - | - | (2,377) | (2,377) | |
| Total equity as at 31 December 2023 | 33,060 | - | - | 11,511 | 55,299 | 99,870 | |
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| Share capital US$'000 | Share premium US$'000 | Deferred shares US$'000 | Merger reserve US$'000 | Retained profit / (deficit) US$'000 | Total attributable to the owner of the Parent US$'000 | |
| Total equity as at 1 January 2022 | 31,118 | 164,817 | 64,702 | 11,511 | (171,203) | 100,945 | |
| Total comprehensive loss for the year | - | - | - | - | (1,133) | (1,133) | |
| Transactions with owners in their capacity as owners: | | | | | | | |
| Shares issued in connection with the completed debt conversion (note 18) | 1,942 | 4,273 | - | - | - | 6,215 | |
| Cancellation share of premium and deferred shares (note 30) | - | (169,090) | (64,702) | - | 233,792 | - | |
| Dividends declared (note 19) | - | - | - | - | (2,444) | (2,444) | |
| Total transactions with owners | 1,942 | (164,817) | (64,702) | - | 231,348 | 3,771 | |
| Total equity as at 31 December 2022 | 33,060 | - | - | 11,511 | 59,012 | 103,583 | |
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Equity Description and purpose
Share capital The nominal value of shares issued
Share premium Amount subscribed for share capital in excess of nominal value
Deferred shares The nominal value of deferred shares issued
Merger reserves The excess of the fair value of the issues share capital over the nominal value of these shares issued for acquisition of at least 90 percent equity holding in subsidiaries
Retained profit/(deficit) Cumulative losses recognised in the profit or loss
The notes on pages 64 to 91 are an essential part of these financial statements
Consolidated Statement of Financial Position
| Company number 05966431 | Notes |
Group 2023 US$'000 | *Restated Group 2022 US$'000 |
| Assets | | | |
| Non-current assets | | | |
| Unproven oil and gas assets | 12 | 51,963 | 44,631 |
| Property, plant and equipment | 13 | 64,930 | 60,146 |
| Other receivables | 16 | 3,230 | 2,533 |
| Restricted use cash | | 706 | 694 |
| Total non-current assets | | 120,829 | 108,004 |
| Current assets | |
| |
| Inventories | 15 | 1,497 | 492 |
| Other receivables | 16 | 12,149 | 5,491 |
| Cash and cash equivalents | 17 | 447 | 3,682 |
| Total current assets | | 14,093 | 9,665 |
| Total assets | | 134,922 | 117,669 |
| Equity and liabilities | |
| |
| Capital and reserves attributable to equity holders of the parent | |
| |
| Share capital | 18 | 33,060 | 33,060 |
| Other reserves | | 2,102 | (2,362) |
| Merger reserve | | 11,511 | 11,511 |
| Retained profit / (deficit) | | 90,626 | 84,775 |
| Cumulative translation reserve | | (65,838) | (66,514) |
| Equity attributable to the owners of the Parent | | 71,461 | 60,470 |
| Non-controlling interests | 29 | (5,152) | (5,667) |
| Total equity | | 66,309 | 54,803 |
| Current liabilities |
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| Trade and other payables | 20 | 16,095 | 14,828 |
| Borrowing | 23 | 3,624 | 352 |
| Current tax liabilities | 20 | 989 | 1,651 |
| BNG historic costs payable | 22 | 3,178 | 3,178 |
| Current provisions | 24 | 4,481 | 5,977 |
| Total current liabilities | | 28,367 | 25,986 |
| Non-current liabilities | |
| |
| Borrowing | 23 | 3,070 | - |
| Deferred tax liabilities | 25 | 7,378 | 6,335 |
| BNG historic costs payable | 22 | 13,746 | 16,297 |
| Non-current provisions | 24 | 1,160 | 469 |
| Other payables | 21 | 14,892 | 13,779 |
| Total non-current liabilities | | 40,246 | 36,880 |
| Total liabilities |
| 68,613 | 62,866 |
| Total equity and liabilities |
| 134,922 | 117,669 |
*See note 3 for details of prior year restatement.
Approved by the Board and authorized for issue:
Clive Nathan Carver,
Chairman,
15 July 2024
Company number: 5966431
Parent Company Statement of Financial Position
| Company number 05966431 | Notes | ||
| Assets | | | |
| Non-current assets | | | |
| Investments in subsidiaries | 14 | 15,487 | 15,487 |
| Other receivables | 16 | 89,083 | 88,883 |
| Total non-current assets | | 104,570 | 104,370 |
| Current assets | |
| |
| Other receivables | 16 | 73 | 14 |
| Cash and cash equivalents | 17 | 48 | 2,405 |
| Total current assets | | 121 | 2,419 |
| Total assets | | 104,691 | 106,789 |
| Equity and liabilities | | | |
| Share capital | 18 | 33,060 | 33,060 |
| Merger reserve | | 11,511 | 11,511 |
| Retained profit / (deficit) | | 55,299 | 59,012 |
| Total equity | | 99,870 | 103,583 |
| Current liabilities |
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| Borrowing | 23 | 104 | - |
| Trade and other payables | 20 | 4,717 | 3,206 |
| Total current liabilities | | 4,821 | 3,206 |
| Total equity and liabilities |
| 104,691 | 106,789 |
Under s408 of the Companies Act 2006 the Company is exempt from the requirement to present its own statement of comprehensive income. The Company incurred loss after tax for the year ended 31 December 2023 in the amount of US$1,336,000 (2022: loss of US$ 1,133,000).
Approved by the Board and authorized for issue:
Clive Nathan Carver,
Chairman,
15 July 2024
Company number: 05966431
| Consolidated and Parent Company Statements of Cash Flows
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| | Notes | Group 2023 US$'000 | Group 2022 US$'000 | Company 2023 US$'000 | Company 2022 US$'000 |
| Cash flows from operating activities |
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| Cash received from customers | | 39,539 | 45,862 | - | - |
| Payments made to suppliers for goods and services | | (28,525) | (26,137) | (637) | (1,280) |
| Payments made to employees | | (5,353) | (1,373) | (413) | (186) |
| Net cash flow generated from/ (used in) operating activities | | 5,661 | 18,352 | (1,050) | (1,466) |
| Cash flows from investing activities | |
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| Purchase of property, plant and equipment | 13 | (7,283) | (502) | - | - |
| Additions to unproven oil and gas assets | 12 | (4,939) | (11,470) | - | - |
| Loan provided to the related party as part of the potential acquisition | 16, 28 | (1,545) | (1,523) | - | - |
| Other payment to the related party | 16, 28 | - | (800) | - | - |
| Transfers to restricted use cash | | (12) | (59) | - | - |
| Advances repaid by subsidiaries | 16 | - | - | 1,099 | 4,944 |
| Net cash flow (used in)/ generated from investing activities | | (13,779) | (14,354) | 1,099 | 4,944 |
| Cash flows from financing activities | |
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| Dividends paid | 19 | (3,026) | (1,097) | (2,605) | (1,097) |
| Bank loan received | 23 | 3,199 | - | - | - |
| Loans received from the related parties, net of payments | 16, 28 | 4,779 | 352 | 200 | 20 |
| Bank interest paid | | (69) | | | |
| Net cash flow generated from/ (used in) financing activities | | 4,883 | (745) | (2,405) | (1,077) |
| Net increase/ (decrease) in cash and cash equivalents | | (3,235) | 3,253 | (2,357) | 2,401 |
| Cash and cash equivalents at the beginning of the year | | 3,682 | 429 | 2,405 | 4 |
| Cash and cash equivalents at the end of the year | 17 | 447 | 3,682 | 48 | 2,405 |
Changes in liabilities arising from financing activities are disclosed in note 23 and no non-cash additions to unproven oil and gas assets and property, plant equipment are included in notes 12 and 13 respectively.
Notes to the Financial Statements
General information
Caspian Sunrise plc ("the Company") is a public limited company incorporated and domiciled in England and Wales. The address of its registered office is 5 New Street Square, London, EC4A 3TW.
The principal activities of the Company and its subsidiaries (the "Group") are the exploration for and the production of crude oil.
1 Principal accounting policies
The principal accounting policies applied in the preparation of these consolidated financial statements ("Group financial statements") and the Company's standalone financial statements ("Company financial statements") are set out below.
1.1 Basis of preparation
The Group and Company financial statements have been prepared in accordance with UK-adopted international accounting standards ("IFRS") in conformity with the requirements of the Companies Act 2006.
The Group and Company financial statements are presented in US dollars ("US$") , which is the Group's and Company's presentational currency, rounded to the nearest thousand unless otherwise stated.
The preparation of financial statements in conformity with IFRS requires Directors to make judgements, estimates and assumptions that affect the application of policies and reported amounts in the financial statements. The areas involving a higher degree of judgement or complexity, or areas where assumptions or estimates are significant to the financial statements are disclosed in note 2.
Going concern
As set out in the Chairman's statement and throughout these financial statements the financial strategy of the Group in recent years has been to fund compliance with work programme commitments and to expand the Group's activities without unduly diluting shareholders' longer term interests.
This has inevitably stretched the short and longer term creditor position to levels at the period end and today which in a more established Group might appear excessive. However, the Board believes the expected significant cash inflows from oil production, offshore chartering and, if appropriate, asset sales, means that the current arguably extreme position is set to rapidly reverse during the remainder of the current, FY24, financial year to the point that the Group will have a significant cash surplus.
Nevertheless, with net current liabilities of approximately $14.3 million as at 31 December 2023 the assessment of going concern needs careful consideration. The Board has therefore assessed cash flow forecasts prepared for the period to 31 December 2025 and assessed the risks and uncertainties associated with the operations and funding position, including Block 8 and West Shalva.
These cash flows are dependent on a number of key factors including:
· The Group's cashflow is sensitive to oil price and volume sold. Given the large discounts encountered since the start of the war in Ukraine we have assumed all sales will be either domestic sales or sales to the domestic mini refineries. Should sales to mini refineries cease and the surplus oil not be picked up on the domestic market additional funding would be required.
· The Group continues to forward sell its domestic production and receives advances from oil traders with approximately $2.1 million advanced at the reporting date. The continued availability of such arrangements is important to working capital. Whilst the Board anticipate such facilities remaining available given its trader relationships, should they be withdrawn or reduced more quickly than forecast cash flows allow then additional funding would be required.
· The Group has $4.0 million of tax liabilities and $4.3 million due on demand under social development programmes and $3.2 million BNG licence payments due within the next 12 months to the Kazakh government. Whilst the Board has forecasted the payment of BNG licence payments, there are no payments planned for social development programmes within the forecast period as the Board expects additional payment deferrals to be approved. Should the deferrals not occur additional funding would be required.
· Should the charter for the Caspian Explorer be materially delayed from its July 2024 start date and / or payment not be made in accordance with the contract terms additional funding would be required.
These circumstances continue to indicate the existence of a material uncertainty which may cast significant doubt about the Group and the Company's ability to continue as a going concern and as a result may be unable to realise its assets and discharge its liabilities in the normal course of business. The financial statements do not include the adjustments that would result if the Group and the Company was unable to continue as a going concern.
While none of the following can be relied upon until cash is received there are a number of expected events, which could provide significant additional working capital in the short term:
· operational expenditure savings at BNG where the mandated work programme obligations will end with Wells 155 and 803, both of which are nearing completion.
· expected revenues of at least $10 million expected in Q3 2024 from the Caspian Explorer contract
· repayment of the $3.3 million loan advanced to enable the 2023 work programme at Block 8 to be completed
· production commencing from Block 8 less the $5 per barrel royalty once the licence is renewed and the re registration formalities in the UAE are finalised
· completion of the proposed $83 million sale of the MJF and South Yelemes structures would on its own eliminate any funding issues, should this be pursued by the Company.
Should it be necessary, the Board has the following options available to mitigate any short-term funding issues:
· To seek additional funding from advance oil sales
· To sell all or part of one or more of the Group's assets - including either the BNG Contract Area where we have already received expressions of interest or the Caspian Explorer
· Seek additional short term funding from the Group's largest shareholder group
· To seek additional equity capital.
Notwithstanding the material uncertainty described above, after making enquiries and assessing the progress against the forecast, projections and the status of the mitigating actions referred to above, the Directors have a reasonable expectation that the Group and the Company will continue in operation and meet its commitments as they fall due over the going concern period. Accordingly, the Directors continue to adopt the going concern basis in preparing the financial statements.
1.2 New and amended standards and interpretations
There were no new standards, amendments or interpretations effective for the first time for periods beginning on or after 1 January 2023 that had a material effect on the Group and Company financial statements.
At the date of approval of these financial statements, there were no new standards or amendments to IFRS which have not been applied in these financial statements which were in issue but not yet effective and are expected to have a material impact on the consolidated and company financial statements.
1.3 Basis of consolidation
Subsidiary undertakings are entities that are directly or indirectly controlled by the Group. Control is achieved when the Group is exposed, or has rights, to variable returns from its involvement with the investee and has the ability to affect those returns through its power over the investee.
Generally, there is a presumption that a majority of voting rights results in control. To support this presumption and when the Group has less than a majority of the voting or similar rights of an investee, the Directors considers all relevant facts and circumstances in assessing whether the Group has power over an investee, including:
· The contractual arrangement with the other vote holders of the investee;
· Rights arising from other contractual arrangements; and
· The Group's voting rights and potential voting rights.
The Directors reassess whether or not the Group controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases. Assets, liabilities, income and expenses of a subsidiary acquired or disposed of during the period are included in the consolidated financial statements from the date the Group gains control until the date the Group ceases to control the subsidiary.
Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used in line with those used by other members of the Group.
All intragroup assets and liabilities, equity, income, expenses, and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.
Non-controlling interests in subsidiaries are identified separately from equity attributable to the owner of the Company. On acquisition of subsidiaries, non-controlling interests are measured at their proportionate share of the fair value of the acquiree's identifiable net assets. Profit or loss and each component of other comprehensive income are attributed to the owners of the Company and to the non-controlling interests.
1.4 Foreign currency translation
Functional and presentational currencies
The functional currency for each entity in the Group is the currency of the primary economic environment in which the entity operates. The functional currency of the Company is the US Dollar. Other entities in the Group have the US Dollar or Kazakh Tenge ("KZT") as their functional currencies.
The Group and Company financial statements are presented in US Dollars, which is the Group's and Company's presentational currency.
Transactions and balances in foreign currencies
In preparing the financial statements of the individual entities, transactions in currencies other than the entity's functional currency ("foreign currencies") are recorded at the rates of exchange prevailing at the dates of the transactions. At each reporting date, monetary items denominated in foreign currencies are retranslated at the rates prevailing at the reporting date. Non-monetary items carried at fair value that are denominated in foreign currencies are retranslated at the rates prevailing at the date when the fair value was determined. Non-monetary items, including the parent's share capital, that are measured in terms of historical cost in a foreign currency are not retranslated. Exchange differences are recognised in profit or loss in the period in which they arise.
Consolidation
For the purpose of consolidation all assets and liabilities of Group entities with a functional currency that is not US Dollars are translated at the rate prevailing at the reporting date. The profit or loss is translated at the exchange rate approximating to those ruling when the transaction took place. Exchange difference arising on retranslating the opening net assets from the opening rate and results of operations from the average rate are recognised directly in other comprehensive income (the "cumulative translation reserve"). On disposal of a foreign operator, related cumulative foreign exchange gains and losses are reclassified to profit and loss and are recognized as part of the gain or loss on disposal.
Exchange rates
For reference, the year end exchange rate from sterling to US$ was 1.27 (2022: 1.21) and the average rate during the year was 1.27 (1.24). The year-end exchange rate from KZT to US$ was 454.56 (2022: 462.65) and the average rate during the year was 456.24 (2022: 460.48).
1.5 Revenue
Revenue from contracts with customers is recognised when or as the Group satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service.
Revenue is measured at the fair value of the consideration received, excluding value added tax ("VAT") and other sales taxes or duty.
Sale of crude oil and oil products
The transfer of control of oil and oil products sold by the Group usually coincides with title passing to the customer. The Group satisfies its performance obligations at a point in time.
Under the terms of domestic oil sales arrangements, the performance obligation is satisfied when the local refinery provides the seller and the customer with the act of acceptance of crude oil or oil products of the quantity and quality according to the agreement between the parties.
Under the terms of export sales arrangements, the performance obligation is satisfied when the Ocean Bill of Lading is issued by the transport company following loading of the crude oil of specified quantity and quality on the tanker.
Payments in advance by oil traders are recorded initially as deferred revenue, reflecting the nature of the transaction. Subsequently, the deferred revenue is reduced and revenue is recorded, as sales are made under the Group's revenue recognition policy with the performance obligation satisfied.
Drilling services
The Group has applied the input method of revenue recognition in accounting for revenue on unit rate/lump sum contracts, under which revenue is recognised over time according to the stage of completion reached in the contract by measuring the proportion of costs incurred for work performed relative to the total estimated costs. For contracts that are at an early stage of the drilling process, total costs to complete may not be estimated reliably, in which case the cost recovery method is used whereby revenue is only recognised for the costs that are recoverable.
Drilling services contain distinct goods and services, but these are not considered distinct in the context of the contract and are therefore combined into a single performance obligation. At contract inception management consider all applicable factors to determine whether the contract contains a single performance obligation or multiple performance obligations.
A change to an existing contract for a project of the Group is a modification, which could change the scope of the contract, the price of the contract, or both. The Group uses two methods to account for a contract modification: (1) as a separate contract when the modification promises distinct goods or services and the price reflects the stand alone selling price; or (2) as a cumulative catch-up adjustment when the modification does not add distinct goods or services and is part of the same performance obligation.
Failure to comply with this accounting policy in the years ended 31 December 2022 and 31 December 2021 resulted in a misstatement in the previously reported Group financial statements which have corrected in these financial statements as detailed in note 3.
1.6 Cost of sales
For structures or contract areas with full production licences oil sales are recognised as revenue and the associated costs as costs of sales. For sale of oil products, cost of sales includes the cost of refining crude oil.
Direct costs to fulfil drilling contracts, including employee costs of field staff, are recognised in cost of sales as incurred. When it is probable that the total contract costs will exceed total contract revenue, the contract becomes onerous, and an onerous contract provision is created in accordance with the Group's accounting policy 1.10. Changes in the onerous contract provision are recognised within other operating costs.
1.7 Current tax
Current tax is based on taxable profit for the year. Taxable profit differs from profit as reported in the profit or loss because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using tax rates that have been enacted or substantively enacted by the reporting date.
In case of the uncertainty of the tax treatment, the Group assess, whether it is probable or not, that the tax treatment will be accepted, and to determine the value, the Group use the most likely amount or the expected value in determining taxable profit, tax bases, unused tax losses, unused tax credits and tax rates.
Withholding tax payable in Kazakhstan
According to requirements of the Tax Code of Kazakhstan, withholding taxes payable for non-residents should be withheld from the total amount of interest income of non-residents and paid to the government when interest is paid (in cash) to non-residents. The companies should pay taxes from non-residents' interest income derived from sources in the Republic of Kazakhstan on behalf of these non-residents.
1.8 Deferred tax
Deferred tax is provided on temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for taxation purposes. The following temporary differences are not provided for: the initial recognition of assets or liabilities that affect neither accounting nor taxable profit other than in a business combination, and differences relating to investments in subsidiaries to the extent that they will probably not reverse in the foreseeable future.
The amount of deferred tax provided is based on the expected manner of realisation or settlement of the carrying amount of assets and liabilities, using tax rates enacted or substantively enacted at the reporting date.
Deferred tax liabilities are generally recognised for all taxable temporary differences. A deferred tax asset is recorded only to the extent that it is probable that taxable profit will be available, against which the deductible temporary differences can be utilised.
1.9 Unproven oil and gas assets
The Group applies the full cost method of accounting for exploration and unproven oil and gas asset costs, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources' ("IFRS 6"). Under the full cost method of accounting, costs of exploring for and evaluating oil and gas properties are accumulated and capitalised by reference to appropriate cost pools. Such cost pools are based on license areas. The Group currently has two cost pools.
Exploration and evaluation costs include costs of license acquisition, technical services and studies, seismic acquisition, exploration drilling and testing, but do not include costs incurred prior to having obtained the legal rights to explore an area, which are recognised directly in profit or loss as they are incurred.
Plant and equipment assets acquired for use in exploration and evaluation activities are classified as property, plant and equipment. However, to the extent that such asset is consumed in developing an unproven oil and gas asset, the amount reflecting that consumption is recorded as part of the cost of the unproven oil and gas asset.
The amounts included within unproven oil and gas assets include the fair value that was paid for the acquisition of partnerships holding subsoil use in Kazakhstan. These licenses have been capitalised to the Group's full cost pool in respect of each license area.
Exploration and unproven oil and gas assets related to each exploration license or prospect are not amortised but are carried forward until the technical feasibility and commercial feasibility of extracting a mineral resource are demonstrated, at which point an impairment review is carried out and assets are transferred to proven oil and gas properties.
Exploration and unproven oil and gas assets are reviewed for impairment if events or changes in circumstances indicate that the carrying amount may not be recoverable as at the reporting date. In accordance with IFRS 6, the Directors firstly consider the following facts and circumstances in their assessment of whether the Group's exploration and evaluation assets may be impaired, whether:
§ the period for which the Group has the right to explore in a specific area has expired during the period or will expire in the near future, and is not expected to be renewed;
§ substantive expenditure on further exploration for and evaluation of mineral resources in a specific area is neither budgeted nor planned;
§ exploration for and evaluation of hydrocarbons in a specific area have not led to the discovery of commercially viable quantities of hydrocarbons and the Group has decided to discontinue such activities in the specific area; and
§ sufficient data exists to indicate that although a development in a specific area is likely to proceed, the carrying amount of the exploration and evaluation assets is unlikely to be recovered in full from successful development or by sale.
If any such facts or circumstances are noted, the Directors perform an impairment test in accordance with the provisions of IAS 36 'Impairment of assets'. The aggregate carrying value is compared against the expected recoverable amount of the cash generating unit, being the relevant cost pool. The recoverable amount is the higher of value in use and the fair value less costs to sell.
1.10 Property, plant and equipment
Property, plant and equipment ("PPE") consists of proven oil and gas properties and other assets.
Proven oil and gas assets
Once an exploration project reaches the stage of commercial production and production permits are received, the carrying values of the relevant exploration and evaluation asset are assessed for impairment and transferred to proven oil and gas properties and included within property plant and equipment. The costs transferred comprise direct costs associated with the relevant wells and infrastructure, together with an allocation of the wider unallocated exploration costs in the cost pool such as original acquisition costs for the field.
Proven oil and gas properties are subsequently accounted for in accordance with provisions of the cost model and are depleted on unit of production basis based on commercial reserves of the pool to which they relate.
As part of the Kazakh licencing regime, upon award of a production contract in respect of the BNG licence area, an obligation to make a payment to the licencing authority is triggered, which is settled over a 10 year period in equal quarterly instalments. Such payments are considered to form a cost of the licence and are capitalised to proven oil and gas assets and subsequently depreciated on a units of production basis in accordance with the Group's depreciation policy. In circumstances where the amount assessed by the authorities is contested, the Group records a provision discounted using a Kazakh government bond yield with a term approximating the payment profile and the discount is unwound over the payment term and charged to finance costs. Payments made are charged against the provision.
Other PPE assets
All other PPE assets, including the Caspian Explorer, are stated at cost less accumulated depreciation and impairment. The assets are depreciated a straight-line basis, at rates calculated to write off the cost less the estimated residual value of each asset over its expected useful economic life. The residual value is the estimated amount that would currently be obtained from disposal of the asset if the asset were already of the age and in the condition expected at the end of its useful life. Expected useful economic life and residual values are reviewed annually. The annual rates of depreciation are as follows:
- motor vehicles 4-5 years
- other over 2-4 years
Impairment of PPE
At each reporting date, the Directors review the carrying values of the Group's PPE 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 is estimated in order to determine the extent of the impairment loss, if any. Where the asset does not generate cash flows that are independent from other assets, the Directors estimate the recoverable amount of the smallest cash-generating unit ("CGU") to which the asset belongs. The recoverable amount is the higher of fair value less costs to sell and value in use.
Fair value less costs to sell is determined by discounting the post-tax cash flows expected to be generated by the CGU, net of associated selling costs, and takes into account assumptions market participants would use in estimating fair value including future capital expenditure and development cost for extraction of the field reserves.
In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-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.
If the recoverable amount of an asset (or CGU) is estimated to be less than its carrying amount, the carrying amount of the asset (or CGU) is reduced to its recoverable amount. An impairment loss is recognised in profit or loss immediately.
Where an impairment loss subsequently reverses, the carrying amount of the asset (or CGU) is increased to the revised estimate of its recoverable amount, but so that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (or CGU) in prior years. A reversal of an impairment loss is recognised in profit or loss immediately.
Workovers/Overhauls and maintenance
From time to time a workover or overhaul or maintenance of existing proven oil and gas properties is required, which normally falls into one of two distinct categories. The type of workover dictates the accounting policy and recognition of the related costs:
Capitalisable costs - cost will be capitalised where the performance of an asset is improved, where an asset being overhauled is being changed from its initial use, the assets' useful life is being extended, or the asset is being modified to assist the production of new reserves.
Non-capitalisable costs - expense type workover costs are costs incurred as maintenance type expenditure, which would be considered day-to-day servicing of the asset. These types of expenditures are recognised within cost of sales in the statement of comprehensive income as incurred. Expense workovers generally include work that is maintenance in nature and generally will not increase production capability through accessing new reserves, production from a new zone or significantly extend the life or change the nature of the well from its original production profile.
1.11 Abandonment provision
Provision is made for the present value of the future cost of the decommissioning of oil wells and related facilities. This provision is recognised when the asset is installed. The estimated costs, based on engineering cost levels prevailing at the reporting date, are computed on the basis of the latest assumptions as to the scope and method of decommissioning. The corresponding amount is capitalised as a part of the oil and gas asset and, when in production is amortised on a unit-of-production basis as part of the depreciation, depletion and amortisation charge. Any adjustment arising from the reassessment of estimated cost of decommissioning is capitalised, while the charge arising from the unwinding of the discount applied to the decommissioning provision is treated as a component of the interest charge.
1.12 Investment in subsidiaries
In Company financial statements, investments in subsidiaries undertakings are shown at cost less allowance for impairment. Investments in subsidiaries are reviewed annually for impairment indicators and, if required, are subject to impairment reviews as detailed in note 1.9.
1.13 Inventories
Inventories are initially recognised at cost, and subsequently at the lower of cost and net realisable value. Cost comprises all costs of purchase and other costs incurred in bringing the inventories to their present location and condition.
1.14 Deferred and accrued revenue
Deferred revenue is a liability that arises when a customer pays consideration before the respective goods (crude oil or oil products) or services (drilling) are transferred to the customer.
Accrued revenue is an asset that arises when the Group performs its contract obligations by transferring goods or services to a customer before the consideration is paid or before payment is due. A right to payment that is unconditional is a financial asset and is recognised as a trade receivable. Accrued revenue is assessed annually for impairment in the accordance with the same accounting policy as applied to trade receivables (note 1.15).
1.15 Financial instruments
Financial instruments, or their component parts, are classified on initial recognition as a financial asset, a financial liability or an equity instrument in accordance with the substance of the contractual agreement.
Financial assets and financial liabilities are recognised when the Company or Group becomes a party to the contractual provisions of the financial instrument.
Financial assets are derecognised when the contractual rights to the cash flows from the asset expire, or when it transfers the financial asset and substantially all the risks and rewards of ownership of the asset to another party. Financial liabilities are derecognised when the Group's obligations are discharged, cancelled or have expired.
Financial assets
Financial assets are classified at initial recognition into one of the categories listed below, depending upon the business model for managing the financial assets and the nature of the contractual cash flow characteristics of the financial asset.
Amortised cost
Financial assets held at amortised cost comprise cash and cash equivalents, trade and other receivables and amounts advanced to subsidiaries and loans to related parties.
These assets are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They arise principally through the provision of goods and services to customers (e.g., trade receivables), but also incorporate other types of financial assets where the objective is to hold their assets in order to collect contractual cash flows and the contractual cash flows are solely payments of the principal and interest. They are initially recognised at fair value plus transaction costs that are directly attributable to their acquisition or issue and are subsequently carried at amortised cost using the effective interest rate method, less provision for impairment.
Impairment provisions for trade and other receivables are recognised based on the simplified approach within IFRS 9 'Financial Instruments' ("IFRS 9") using the lifetime expected credit losses ("ECL") method. During this process the probability of the non-payment of the receivables is assessed. This probability is then multiplied by the amount of the expected loss arising from default to determine the lifetime ECL for the receivables. For trade and other receivables, which are reported net, such provisions are recorded in a separate provision account with the loss being recognised within administrative expenses in the statement of comprehensive income. On confirmation that the trade or other receivable will not be collectable, the gross carrying value of the asset is written off against the associated provision.
Financial liabilities
Financial liabilities include trade and other payables, borrowings and other payables. All financial liabilities are recognised initially at fair value, net of transaction costs incurred, and are subsequently stated at amortised cost, using the effective interest method.
If a loan is renegotiated on substantially different terms, this is treated as an extinguishment of the original financial liability and the recognition of a new financial liability with a gain or loss recognised in profit or loss. When the Company extinguishes a financial liability in return for equity, the shares issued are recognised at their fair value with any difference to the carrying value of the financial liability recognised in profit or loss.
Share capital
Ordinary and deferred shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are shown in equity as a deduction from the proceeds.
1.16 Restricted use cash
Restricted use cash represents cash set aside by the Group for the purpose of creating an abandonment fund to cover the future cost of the decommissioning of oil and gas wells and related facilities and in accordance with local legal rulings. The cash is held in a segregated bank account and under the Subsoil Use Contracts the Group must place 1% of the capital expenditure incurred in the year into an escrow deposit account, unless agreed otherwise with the Ministry of Energy. At the end of the contract this cash will be used to return the field to the condition that it was in before exploration started.
1.17 Cash and cash equivalents
Cash and cash equivalents are defined as cash on hand and demand deposits with maturity of 3 months or less. Restricted use cash is presented separately.
1.18 Other provisions
A provision is recognised when the Group has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability.
An onerous contract is a contract in which the unavoidable costs of meeting the obligations under the contract exceed the economic benefits expected to be received under it. The amount recognised will be the best estimate of the expenditure required to settle the present obligation at the reporting date.
1.19 Share-based payments
The Group has used shares and share options as consideration for services received from employees.
Equity-settled share-based payments to employees and others providing similar services are measured at fair value at the date of grant. The fair value determined at the grant date of such an equity-settled share-based instrument is expensed on a straight-line basis over the vesting period, based on the Group's estimate of the shares that will eventually vest.
Equity-settled share-based payment transactions with other parties are measured at the fair value of the goods or services received, except where the fair value cannot be estimated reliably, in which case they are measured at the fair value of the equity instruments granted, measured at the date the entity obtains the goods or the counterparty renders the service. The fair value determined at the grant date of such an equity-settled share-based instrument is expensed since the shares vest immediately. Where the services are related to the issue of shares, the fair values of these services are offset against share premium where permitted.
Fair value is measured using the Black-Scholes model. The expected life used in the model has been adjusted based on the Management's best estimate, for the effects of non-transferability, exercise restrictions and behavioural considerations.
1.20 Warrants
Warrants are separated from the host contract as their risks and characteristics are not closely related to those of the host contracts. Where the exercise price of the warrants is in a different currency to the functional currency of the Company, at each reporting date the warrants are valued at fair value with changes in fair values recognised through profit or loss as they arise. The fair values of the warrants are calculated using the Black-Scholes model. Where the warrant exercise price is in the same currency as the functional currency of the issuer and involve the issuance of a fixed number of shares the warrants are recorded in equity.
1.21 Merger reserve
Merger reserve represents the excess of the fair value of the issued share capital over the nominal value of these shares issued for acquisition of investments in subsidiaries where the Company has secured at least 90% equity holding in accordance with section 612 of the Companies Act 2006. The Company allocates merger reserve to the retained earnings/deficit account on disposal of the investment the reserve relates to or if this investment is written down for impairment.
1.22 Segmental reporting
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker, who is responsible for allocating resources and assessing performance of the operating segments and making strategic decisions, has been identified as the Board of Directors. The Group has four operating segments being oil exploration and production; onshore drilling services in Kazakhstan provided by CTS LLP, offshore drilling services provided using the Caspian Explorer, and the expenses corporate allocated, and therefore there are four reporting segments. The Group has several cost pools divided based on the different contractual territory of its assets.
2 Critical accounting estimates and judgements
In the process of applying the Group's accounting policies, which are described in note 2, the Directors are required to make judgements, estimates and assumptions which affect reported income, expenses, assets, liabilities and disclosure of contingent assets and liabilities. The estimates and associated assumptions are based on historical experience, expectations of future events and other factors that are believed to be reasonable under the circumstances. Actual results in the future could differ from such estimates. The estimates and underlying assumptions are reviewed on an on-going basis. Revisions to accounting estimates are recognised in the period in which the revision is made.
2.1 Key sources of estimation uncertainty
2.1.2 Revenue recognition on onshore drilling contracts with third parties
The determination of anticipated costs for completing a drilling contract is based on estimates that can be affected by a variety of factors such as potential variances in scheduling and cost of materials along with the availability and cost of qualified labour and subcontractors, productivity, and possible claims from subcontractors.
The determination of anticipated revenues includes the contractually agreed revenue and may also involve estimates of future revenues from claims and unapproved variations, if such additional revenues can be reliably estimated and it is considered probable that they will be recovered.
A variation results from a change to the scope of the work to be performed compared to the original contract signed. An example of such contract variation could be a change in the specifications or design of the project, whereby costs related to such variation might be incurred prior to the client's formal contract amendment signature. A claim represents an amount expected to be collected from the client or a third party as reimbursement for costs incurred that are not part of the original contract.
As risks and uncertainties are different for each project, the sources of variations between anticipated costs and actual costs incurred will also vary for each project. The determination of estimates is based on internal policies as well as historical experience.
For the year ended 31 December 2023, the Group recognised revenue of US$4,126,000 (2022 (restated): US$1,648,000) relating to onshore drilling contracts provided to third parties. As at 31 December 2023, the Group does not have any ongoing onshore external drilling service contracts, however this was a key uncertainty when correcting for the prior period error (note 3), where the Directors used their best judgement to determine what the expected costs to complete would have been as at 31 December 2022 and 31 December 2021, further details are included in note 3.
2.1.3 Decommissioning obligation
Provision has been made in the accounts for future decommissioning costs to plug and abandon wells as set out in note 24. The costs of provisions have been added to the cost of the oil and gas asset or the exploration asset depending on the well's stage of development.
The decommissioning liability is stated in the accounts at discounted present value and accreted up to the final expected liability by way of an annual finance charge. The Group has potential decommissioning obligations in respect of its interests in Kazakhstan.
The extent to which a provision is required in respect of these potential obligations depends, inter alia, on the legal requirements at the time of decommissioning, the cost and timing of any necessary decommissioning works which are estimated to be in 2043, the discount rate to be applied to such costs (2023: 11%) and the expected inflation rate in Kazakhstan (2023: 9.8%). Actual costs incurred in future periods may substantially differ from the amounts of provisions. In addition, future changes in environmental laws and regulations, estimates of deposit useful lives and discount rates may affect the carrying value of this provision.
2.1.4 Estimation of credit losses of receivables from subsidiaries
The Directors have used judgement to determine to the expected credit loss provision against amounts due from subsidiaries in the Company financial statements, which involves estimates of the ability of the subsidiaries to repay these loans, which itself is based on the estimates of the minimum realisable value of the Group's assets, which are primarily the production and exploration assets and the Caspian Explorer. The Directors have estimated an expected credit loss provision of US$20.7m is required as at the year-end (2022: US$20.7m). The estimate of the recoverable amounts of receivables due from subsidiaries is primarily linked to the Group's exploration and proven oil and gas assets having net realisable values of at least their carrying values. Sections 2.2.1 and 2.2.2 below detail the significant judgements with respect to impairment indicators of these assets.
2.1.5 Indemnity receivables in relation to the 3A Best acquisition
Under the terms of the Sale and Purchase Agreement ("SPA") for 3A Best, the three vendors provided indemnities that obligations related to the period prior to acquisition would be reimbursed. Judgement has been applied in assessing the recoverability of the indemnity receivables, which included assessment of the terms of the SPA, confirmations received from the vendors and assessments of the ability to meet such payments. The Directors, while still seeking full recovery, have made a provision for 67% of the amounts due on the expected credit losses as at 31 December 2023 (2022: 67%) leaving a balance of US$ 1,275,000 (2022: US$ 1,275,000) in other receivables (note 16).
2.1.6 Uncertain tax position
The Directors are required to exercise judgment in interpreting continually-changing regulations with regards to the Group's tax position and the extent to which tax treatments historically adopted by the Group will be accepted or rejected by the relevant tax authority. The Directors believe that adequate provisions have been made for all income tax obligations in the current year.
2.1.7 Recoverability of VAT (note 16)
The Group holds VAT receivables of $2.9 million (2022: $2.0 million) as detailed in note 16 which are anticipated to be primarily recovered through offset of future VAT payable in accordance with Kazakh legislation. Management have assessed the recoverability of the asset based on forecast levels of VAT payables which demonstrate that the balance will be recovered within 1 year (2022: 1 years). This required estimates regarding future production, oil prices and expenditure.
2.1.8 Hydrocarbon reserve and resource estimate
The Group estimates and reports hydrocarbon reserves in line with the principles contained in the SPE Petroleum Resources Management Reporting System (PRMS) framework. As the economic assumptions used may change and as additional geological information is obtained during the operation of a field, estimates of recoverable reserves may change. The volume of proved and probable oil reserves is an estimate that affects the unit of production depreciation of producing oil and gas property, and a downward revision of the estimate is an impairment indicator. Proved and probable reserves and contingent resources are estimated using standard recognised evaluation techniques, disclosed in note 12.
2.2 Judgements
The following are the critical judgements, apart from those involving estimations (which are disclosed in 2.1 above), 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.
2.2.1 Impairment of proven oil and gas assets
The proven oil and gas assets, representing the MJF and South Yelemes shallow structures, have been assessed for indicators of impairment as at 31 December 2023. These indicators included a range of:
- economic factors, such changes in oil prices and cost inflation;
- operational results, such as production difficulties; and
- conservative financial forecasts, based on sales only to the domestic and domestic mini refinery markets at net prices of $25 and $32 per barrel respectively with aggregate production volumes based at 1,900 bopd.
Having assessed these indicators, the Directors have concluded that no impairment indicators exist (2022: none) and thus no impairment review is required.
2.2.2 Carrying value of exploration and evaluation costs
Under the full cost method of accounting for exploration and evaluation costs, such costs are capitalised as intangible assets by reference to appropriate cost pools and are assessed for impairment on a concession basis based on the impairment indicators detailed in accounting policy note 1.9.
As at 31 December 2023, the Directors assessed the exploration and evaluation assets and determined that no indicators of impairment exist with respect to the BNG cost pool (2022: none). The Directors note that the Group's current appraisal licences expire in August 2024. The application for a two year extension of the existing licence has been made and the relevant Kazakh regulatory committee is expected to respond before the end of July 2024. . Based on the fact that the Group has met its spending commitments under the licences and has a successful track record of successfully renewing licences in the BNG contract area, the Directors expect the licences to be renewed for two years and then converted into production licences.
The Directors also considered whether the factors that gave rise to the original impairment of the 3A Best licence no longer exist and thus a reversal of the impairment is appropriate. The Directors are working with the Kazakh authorities to renew the licence at 3A Best, however as no substantive progress has been made, the asset remains fully impaired.
2.2.3 Recoverability of investments in subsidiaries
The recoverability of investments in subsidiaries is driven primarily by the same judgements and uncertainties as the recoverability of the carrying value of the proven and unproven oil and gas assets which are discussed above. The Directors have concluded that no additional impairment provision is required in the current financial year (2022: US$ nil).
3 Correction of prior year errors
As disclosed in the consolidated financial statements for the year-ended 31 December 2022, the Directors have identified an error in how the Group's accounting policy for revenue recognition for drilling services was applied in one of the Company's subsidiaries - CTS LLP ("CTS").
CTS provided services to two customers during the years ended 31 December 2023, 31 December 2022 and 31 December 2021: EPC Munai LLP - a related party, and BNG LLP, being the subsidiary of the Group.
At the date of approval of the prior year's financial statements, the Directors made a number of estimates to correct for the error. As part of the preparation of Group financial statements for the year ended 31 December 2023, a thorough review of CTS's books and records was carried out and as a result, a number of adjustments to the previously reported balances is required. Specifically, the allocation of costs between individual contracts was reviewed and corrected to ensure that contract costs were complete and accurate and thus the revenue for each contract could be recognised under the input method in accordance with IFRS 15. For contracts that completed by 31 December 2023, the Directors used actual contract costs incurred to estimate the stage of completion at each year-end, but were careful to exclude the impact of any subsequent contract modifications. Where contract costs exceeded revenue from the contract, an onerous contract provision was created, which totalled US$ 225,000 as at 31 December 2021 and was fully utilised by 31 December 2022.
For contracts that were performed for BNG LLP changes to the cost allocation and corresponding revenue recognition between contracts also affected the amounts that were capitalised as exploration assets or production assets. In addition, it was identified that an additional depreciation of drilling equipment should have been charged to either profit or loss in relation in relation to work on production assets in BNG LLP or EPC Munai LLP contracts; or capitalised as exploration asset in BNG LLP in the prior years.
All the required adjustments constitute a prior period error in accordance with IAS 8 Accounting Policies, Changes in Accounting Estimates and Errors. The error has been corrected by restating each of the affected financial statement line items for the prior periods as follows:
Impact on Group statements of financial position
The Directors do not consider the impact of the prior year errors to be material to the consolidated statement of financial position as at 31 December 2021. Therefore, no opening statement of consolidated financial position has presented in the consolidated statement of financial position.
Impact on Group statements of comprehensive income
4 Segment reporting and revenue analysis
Operating segments
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision maker. The chief operating decision maker, who is responsible for allocating resources and assessing the performance of the operating segments and making strategic decisions, has been identified as the Board of Directors.
The Group operated in four (2022: three) operating segments during 2023 and 2022: Exploration for and production of crude oil; onshore drilling services (CTS LLP); offshore drilling services (Caspian Explorer); and oil trading, which a new segment for 2023. All four segments operate and generate revenues in Kazakhstan.
BNG Ltd. LLP (BNG) currently accounts for 100% (2022: 100%) of the exploration and production revenues. Total revenue from crude oil sales generated by BNG in 2023 was US$ 21,615,000 (2022: US$ 39,245,000), net operating income for the year from the exploration and production of crude oil was US$13,400,000 (2022: US$15,526,000). Segmental assets have increased by US$ 15,877,000 during 2023 primarily due to additions to BNG's production and exploration assets of US$ 7,663,000 and US$ 5,801,000 respectively, which are further detailed in the Operational Review.
KC Caspian Explorer LLP (KCCE), representing the offshore drilling services operating segment, historically providing drilling and related services in the shallow northern Caspian Sea. In 2021 the KCCE provided NCOC, Kashagan oil field operator, with safety related services. In 2022 KCCE had no revenue. In 2023, as part of the preparation for a major drilling contract in 2024, KCCE carried technical studies that were recharged to the client of US$ 641,000.
In 2023 Caspian Technical Services LLP (CTS LLP) continued to provided onshore drilling and repair services primarily to BNG. Revenue for onshore drilling and repair services provided on assets not owned by the Group was US$ 4,126,000 during the year (restated 2022: US$ 1,648,000).
Revenue
The Group's revenues are principally derived from the sale of oil in Kazakhstan. In September 2019 following the award of a full production licence, oil produced from the MJF structure at BNG started being sold on the export market.
Under the terms of sales on the local market, the performance obligation is the supply of oil and the performance obligation is satisfied at a point in time, being the delivery of oil to the refinery. Control passes to the customer at this point with title and risk transferred.
Under the terms of sales on the local market, to local mini refineries the performance obligation is the supply of oil and the performance obligation is satisfied at a point in time, being the collection of oil at the wellhead. Control passes to the customer at this point with title and risk transferred.
Under the terms of export sales control over the oil delivered is with the Group until the customer confirms it has been shipped onto the tanker. When advances are received from oil traders for delivery of future production at specified prices, deferred revenue is recorded and the liability reduced as oil is delivered. Where advances are made for future production and the financing component of such transactions is material, a finance charge is recorded based on the market rate of interest.
In 2023 and 2022 KCCE earned no drilling revenue though as part of the preparation for a major drilling contract in 2024, KCCE carried technical studies that were recharged to the client of US$ 641,000.
In 2023 CTS LLP continued to provide onshore drilling and repair services for Group and for EPC Munai LLP, a related party.
Oil trading consist of purchasing crude oil, funding its refining and selling the resultant oil products produced to third parties.
Below is the summary of the results of the segments during 2023 and 2022:
| 2023 | Oil and gas assets $000 | Drilling services CTS $000 | Drilling services by Caspian Explorer $000 | Oil Trading $000 | Corporate allocation $000 | Total $000 |
| External revenues | 21,615 | 4,126 | 644 | 10,266 | - | 36,651 |
| Cost of sales | (5,088) | (5,007) | (491) | (5,340) | - | (15,926) |
| Gross profit/(loss) | 16,527 | (881) | 153 | 4,926 | - | 20,725 |
| Administrative costs | (2,080) | (1,275) | (1,006) | (710) | (960) | (6,031) |
| Selling expense | (1,046) | (1) | - | (1,946) | - | (2,993) |
| Other operating income | - | - | - | - | 3,775 | 3,774 |
| Segment operating profit/(loss) | 13,401 | (2,157) | (853) | 2,270 | 2,815 | 15,476 |
| Finance income | 62 | - | - | - | 169 | 231 |
| Finance costs | (920) | - | - | - | | (920) |
| Profit/(loss) before income tax | 12,543 | (2,157) | (853) | 2,270 | 2,984 | 14,787 |
| Total assets | 117,571 | 8,187 | 3,289 | 2,468 | 3,406 | 134,920 |
| Total liabilities | 53,714 | 5,073 | 673 | 5,834 | 3,318 | 68,612 |
| 2022 | Oil and gas assets $000 (restated) | Drilling services CTS $000 (restated) | Drilling services by Caspian Explorer $000 | Oil Trading $000 | Corporate allocation $000 | Total $000 (restated) |
| External revenues (restated) | 39,245 | 1,648 | - | - | - | 40,893 |
| Cost of sales (restated) | (6,554) | (2,164) | - | - | - | (8,718) |
| Gross profit (restated) | 32,691 | (516) | - | - | - | 32,175 |
| G&A | (7,421) | (367) | (633) | - | (1,346) | (9,767) |
| Selling expense | (9,751) | - | - | - | - | (9,751) |
| Other operating income (restated) | - | 211 | - | - | - | 211 |
| Segment operating profit/(loss) | 15,519 | (672) | (633) | - | (1,346) | 12,868 |
| Finance income | 50 | - | 9 | - | - | 59 |
| Finance costs | (549) | - | - | - | (36) | (585) |
| Profit / (loss) before income tax (restated) | 15,020 | (672) | (624) | - | (1,382) | 12,342 |
| Total assets (restated) | 101,393 | 7,878 | 2,997 | - | 5,401 | 117,669 |
| Total liabilities(restated) | 56,148 | 2,981 | 6 | - | 3,731 | 62,866 |
Revenue arising from the sale of crude oil in BNG included the following sales to customers contributing to more than 10% of the total revenue of the Group:
| | Group 2023 US$'000 | Group 2022 US$'000 |
| Customer A | - | 4,748 |
| Customer B | 2,003 | 8,104 |
| Customer C | 8,068 | - |
| Customer D | - | 21,171 |
| | 10,071 | 34,023 |
5 Operating profit
| Group operating profit for the year has been arrived after charging / (crediting): | ||
| | Group 2023 US$'000 | Group 2022 US$'000 (restated) |
| Staff costs (note 7) | 3,000 | 6,477 |
| Depreciation of property, plant and equipment (note 13) | 2,594 | 2,816 |
| Cost of inventories recognised within cost of sales | 6,925 | 2,528 |
| Auditor remuneration (note 6) | 327 | 239 |
| Loss allowance on trade receivables | 629 | - |
| Other operating (income) | (3,774) | (211) |
| Net foreign exchange losses | 65 | 178 |
Other operating income for the year ended 31 December 2023 represents a release of the social development programme provision in relation to the Group's obligations under the 3A Best licence of US$ 1,505,000 disclosed in note 12 and write-off of other payables of US$ 2,269,000 in relation to a past transaction.
Other operating income for the year ended 31 December 2022 represents a release of an onerous contract provision in relation to the drilling services performed for EPC Munai LLP, a related party (note 28).
6 Group Auditor's remuneration
Fees payable by the Group to the Company's auditors, PKF Littlejohn LLP (2022: BDO LLP) and its member firms in respect of the year:
| | Group 2023 US$'000 | Group 2022 US$'000 |
| Fees payable to the Company's auditor and its associates for the audit of the Company and Group financial statements: | | |
| PKF Littlejohn LLP | 162 | - |
| BDO LLP | 104* | 180 |
| | 266 | 180 |
| Other services provided by BDO LLP - tax compliance services | 10 | 11 |
| | 276 | 191 |
*additional fees in respect of the audit of the 2022 Group financial statements.
Fees payable by the Group to Grant Thornton and its associates in respect of the year:
| | Group 2023 US$'000 | Group 2022 US$'000 |
| Auditing of accounts of subsidiaries of the Company | 70 | 48 |
| | 70 | 48 |
7 Staff costs
| Staff costs during the year | Group 2023 US$'000 | Group 2022 US$'000 | Company 2023 US$'000 | Company 2022 US$'000 |
| Wages and salaries | 2,675 | 5,842* | 364 | 262 |
| Social security costs | 227 | 524 | - | - |
| Pension costs | 98 | 111 | - | - |
| | 3,000 | 6,477 | 364 | 262 |
In addition, payroll expenses of US$1,494,000 were capitalised into unproven oil and gas assets in 2023 (2022: US$1,230,000) and the amounts included within cost of sales were US$703,000 (2022: US$ $409,000).
* During 2022 the Group declared payment of US $ 4,878,000 of bonus to the employees of the Group who were the key personnel in achieving
high production and selling results at the major asset, BNG, during 2020-2022.
| Average monthly number of employees (including executive Directors) | Group 2023 | Group 2022 | Company 2022 | Company 2022 |
| Technical | 17 | 18 | - | - |
| Field operations | 233 | 233 | - | - |
| Finance | 13 | 8 | 1 | 1 |
| Administrative and support | 33 | 25 | 3 | 3 |
| | 296 | 284 | 4 | 4 |
| |
|
|
|
|
8 Finance cost
|
| Group 2023 US$'000 | Group 2022 US$'000 |
| Interest on borrowings (note 23) | 399 | 11 |
| Unwinding of discount on BNG licence payment payable | 471 | 550 |
| Unwinding of discount on provisions (note 24) | 50 | 24 |
| | 920 | 585 |
9 Finance income
|
| Group 2023 US$'000 | Group 2022 US$'000 |
| Interest on loans to related parties | 169 | - |
| Bank interest | 62 | 59 |
| | 231 | 59 |
10 Taxation
| Analysis of charge for the year | Group 2023 US$'000 | Group 2022 US$'000 |
| Current tax charge | 3,681 | 2,371 |
| Deferred tax charge | - | - |
| | 3,681 | 2,371 |
|
| Group 2023 US$'000 | Group 2022 US$'000 (restated) |
| Profit before tax | 14,786 | 12,342 |
|
Tax on the above at the standard rate of corporate income tax in the UK 25% (2022: 19%) | 3,697 | 2,345 |
| Effects of: | | |
| Differences in tax rates | (2,802) | (962) |
| Non-deductible expenses | 889 | 103 |
| Withholding tax on interest expense | 909 | 711 |
| Unrecognised tax losses carried forward (note 25) | 988 | 174 |
| | 3,682 | 2,371 |
11 Earnings per share
Earnings per share ("EPS") is calculated by dividing the profit attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the year including shares to be issued.
|
| Group 2023 US$'000 | Group 2022 US$'000 (restated) |
| Profit for the year from continuing operations, attributable to the parent | 10,590 | 9,837 |
| EPS - Basic | Group 2023 | Group 2022 |
| Weighted average no of shares | 2,250,501,559 | 2,221,391,258 |
| Basic Earnings per share (US cents) | 0.47 | 0.44 |
| EPS - Diluted | Group 2023 | Group 2022 |
| Weighted average no of shares | 2,250,501,559 | 2,221,391,258 |
| Dilutive effect of dilutive potential ordinary shares due to share options (note 26) | 2,197,802 | - |
| Weighted average no of shares for the purpose of Diluted EPS | 2,252,699,361 | 2,221,391,258 |
| Diluted Earnings per share (US cents) | 0.47 | 0.44 |
Other than share options there are no instruments that are potentially dilutive.
12 Unproven oil and gas assets
| COST | Group US$'000 |
| Cost at 1 January 2022 (restated) | 69,106 |
| Additions (restated) | 11,214 |
| Transfer from Property, plant and equipment (note 13) | 4,810 |
| Transfer to Property, plant and equipment (note 13)* | (14,025) |
| Foreign exchange difference | (6,077) |
| Cost at 31 December 2022 (restated) | 65,028 |
| Additions | 5,801 |
| Foreign exchange difference | 1,894 |
| Cost at 31 December 2023 | 72,723 |
| ACCUMULATED IMPAIRMENT | Group US$'000 (restated) |
| Accumulated impairment at 1 January 2022 (restated) | 21,895 |
| Foreign exchange difference (restated) | (1,498) |
| Accumulated impairment at 31 December 2022 (restated) | 20,397 |
| Foreign exchange difference | 363 |
| Accumulated impairment at 31 December 2023 | 20,760 |
| | |
| NET BOOK VALUE | |
| Net book value at 1 January 2022 (restated) | 47,211 |
| Net book value at 31 December 2022 (restated) | 44,631 |
| Net book value at 31 December 2023 | 51,963 |
Unproven oil and gas assets represent license acquisition costs and subsequent exploration expenditure in respect of the licenses held by Kazakh group entities. The carrying values of those assets at 31 December 2023 were 100% represented by BNG Ltd LLP (2022: 100% by BNG Ltd. LLP).
The additions balance for the year ended 31 December 2023 included the following non-cash transactions:
(i) Capitalised depreciation charge of property, plant and equipment of US$ 608,000 (2022: US$ 418,000);
(ii) Capitalisation of changes in estimate of the asset retirement obligation of US$ 254,000 (2022: US$ nil) (note 24);
The Directors have carried out an impairment review of these assets on a cost pool level as detailed in note 1.9. As at 31 December 2023, the balance of accumulated impairment was US$ 20,678,000 (2022: US$ 20,678,000).
* In 2021 BNG applied for the production license on its South Yelemes shallow structure. The Ministry of Energy of Kazakhstan extended the term in accordance with the additional agreement No. 1 dated June 24, 2023, until 23 June 2044. The related capitalised assets of US$ 14,025,000 were moved to Proven Oil and Gas assets during the year ended 31 December 2022.
The exploration licence for the Group's assets are due to expire in August 2024. The Group has applied to the Ministry for a two year extension in with a response expected before the end of July 2024. Based on the fact that the Group has met its spending commitments under the licences and has a successful track record of successfully renewing licences in the BNG contract area, the Directors expect the licences to renewed for two years before applying for production licences.
13 Property, plant and equipment
Following the commencement of commercial production in July 2019 the Group reclassified part of BNG assets from unproven oil and gas assets to proven oil and gas assets.
|
Group | Proven | Motor | Other | Total |
| oil and gas assets | Vehicles | |||
| US$'000 | US$'000 | US$'000 | US$'000 | |
| Cost at 1 January 2022 (restated) | 44,938 | 2,126 | 15,945 | 63,009 |
| Additions (restated) | 669 | 176 | 3 | 848 |
| Disposals | (110) | - | - | (110) |
| Transfer to Unproven oil and gas assets * (note 12) | - | - | (4,810) | (4,810) |
| Transfer from Unproven oil and gas assets | 14,025 | - | - | 14,025 |
| Foreign exchange difference (restated) | (425) | (111) | (2,668) | (3,204) |
| Cost at 31 December 2022 (restated) | 59,097 | 2,191 | 8,470 | 69,758 |
| Additions | 7,646 | - | 16 | 7,662 |
| Foreign exchange difference | 648 | 39 | 70 | 757 |
| Cost at 31 December 2023 | 67,391 | 2,230 | 8,556 | 78,177 |
| Depreciation at 1 January 2022 (restated) | 2,771 | 569 | 3,216 | 6,556 |
| Charge for the year (restated) | 2,079 | 61 | 676 | 2,816 |
| Disposals | (19) | - | - | (19) |
| Foreign exchange difference (restated) | 189 | 11 | 59 | 259 |
| Depreciation at 31 December 2022 (restated) | 5,020 | 641 | 3,951 | 9,612 |
| Charge for the year | 1,722 | 7 | 865 | 2,594 |
| Foreign exchange difference | 89 | 511 | 441 | 1,041 |
| Depreciation at 31 December 2023 | 6,831 | 1,159 | 5,257 | 13,247 |
| Net book value at: | | | | |
| 1 January 2022 (restated) | 42,167 | 1,557 | 12,729 | 56,453 |
| 31 December 2022 (restated) | 54,077 | 1,550 | 4,519 | 60,146 |
| 31 December 2023 | 60,560 | 1,071 | 3,299 | 64,930 |
*During the year ended 31 December 2022, a balance of US$ 4,810,000, representing work in progress on the Group's exploration wells was transferred to Unproven oil and gas assets.
For the year ended 31 December 2023, the additions balance included capitalisation of changes in estimate of the asset retirement obligation of US$ 380,000 (2022: US$ 103,000) (note 24).
Drilling equipment with net book value of US$4,144,000 has been pledged as security against bank borrowing (note 23).
The Directors considered whether there are indicators that the carrying value of the Group's property, plant and equipment are impaired and concluded that there are none (note 2.2.1).
14 Investments in subsidiaries
|
|
| Company US$'000 |
| Cost | | |
| At 1 January 2022, 31 December 2022 and 31 December 2023 |
| 225,441 |
| Accumulated impairment |
|
|
| At 1 January 2022, 31 December 2022 and 31 December 2023 |
| 209,954 |
| Net book value | | |
| At 1 January 2022, 31 December 2022 and 31 December 2023 | | 15,487 |
The Directors review the investments for the recoverability on a regular basis, together with the associated cash flows of each company, and assess their impairment. Based on this assessment if the Company considers that the carrying value of the investments may not be fully recoverable as the subsidiaries may not generate sufficient future profits and accordingly, then these amounts may be impaired. The Company recorded no impairment in relation to the investments in 2023 (2022: nil).
| Direct investments |
| ||||
| Name of undertaking | Country of incorporation | Effective holding of ordinary shares and proportion of voting rights held at 31 December 2023 and 2023 | Registered address | Nature of business | |
| Eragon Petroleum Limited | United Kingdom | 100% | 5 New Street Square | Holding Company | |
| Eragon Petroleum FZE | Dubai | 100% |
CN-135789, Jebel Ali, Dubai, UAE | Management Company | |
| Prosperity Petroleum LTD | Dubai | 100% |
CN-135789, Jebel Ali, Dubai, UAE | Management Company | |
| Roxi Petroleum Kazakhstan LLP | Kazakhstan | 100% |
152/140 Karasay Batyr Str., Almaty, Kazakhstan | Management Company | |
| Beibars BV | Netherlands | 100% | Koninginneweg 31, 1217 KR Hilversu, Netherlands | Holding Company | |
Indirect investments:
| Name of undertaking | Country of incorporation | Effective holding of ordinary shares and proportion of voting rights held at 31 December 2023 and 2022 | Registered address
| Nature of business
|
| BNG Energy BV | Netherlands | 100% | Utrechtseweg 79 | Holding Company |
|
BNG Ltd LLP | Kazakhstan | 99% | 152/140 Karasay Batyr Str., Almaty, Kazakhstan | Oil Production & Exploration Company |
|
3A-Best Group JSC | Kazakhstan | 100% |
152/140 Karasay Batyr Str., Almaty, Kazakhstan | Exploration Company |
|
CTS LLP | Kazakhstan | 100% |
152/140 Karasay Batyr Str., Almaty, Kazakhstan | Drilling & Service Company |
|
Sur Nedr LLP | Kazakhstan | 100% |
152/140 Karasay Batyr Str., Almaty, Kazakhstan | Drilling & Service Company |
|
SK-NS Aktau LLP | Kazakhstan | 100% |
152/140 Karasay Batyr Str., Almaty, Kazakhstan
| Drilling & Service Company |
| KC Caspian LLP | Kazakhstan | 100% | 152/140 Karasay Batyr Str., Almaty, Kazakhstan
| Drilling Vessel owner |
| Roxi Trading LLP | Kazakhstan | 70% | 38 Dostyk Ave., Medueskiy District, Almaty, 050000, Kazakhstan | Oil Production Company |
| Beibars Munai LLP* | Kazakhstan | 60% | 152/140 Karasay Batyr Str., Almaty, Kazakhstan | Exploration Company |
Beibars Munai LLP is a subsidiary as the Group is considered to have control over the financial and operating policies of this entity. Its results have been consolidated within the Group.
15 Inventories
| | Group | Group |
| | 2023 | 2022 |
| | US$'000 | US$'000 |
| Materials and supplies | 603 | 492 |
| Crude oil and oil products | 894 | - |
| | 1,497 | 492 |
During the year, no inventories were written down or impaired (2022: US$ nil).
16 Trade and other receivables
|
| Group | Group | Company | Company |
|
| 2023 | 2022 | 2023 | 2022 |
|
| US$ '000 | US$ '000 (restated) | US$ '000 | US$'000 |
| Amounts falling due after one year: | | |
| |
| Prepayments made | 93 | 9 | - | - |
| VAT receivable | - | - | - | 62 |
| Loans to the related party | 3,137 | 1,523 | 3,137 | 1,523 |
| Other receivable from related parties | - | 1,001 | - | - |
| Intercompany receivables | - | - | 85,946 | 87,298 |
| | 3,230 | 2,533 | 89,083 | 88,883 |
| Amounts falling due within one year: |
|
|
|
|
| Trade receivables | 3,703 | 629 | - | - |
| Prepayments made | 4,277 | 1,256 | 8 | 14 |
| VAT receivable | 2,893 | 2,023 | 65 | - |
| Other receivables | 1,275 | 2,212 | - | - |
| | 12,148 | 6,120 | 73 | 14 |
The VAT receivables relate to purchases made by operating companies in Kazakhstan and will be recovered through VAT payable resulting from sales to the local market.
Amounts due from related parties
The amounts due from related parties are detailed below:
Loans to related parties
On 25 September 2022, the Independent Directors approved a 7% interest-bearing loan to a maximum value of $5 million to Altynbek Bolatzhan, a member of the Oraziman family, in connection with the party acquisition of EPC Munai LLP ("Block 8"). At 31 December 2023, US$ 3,070,000 (2022: US$ 1,356,000) of that loan had been drawn down, including US$ 1,545,000 advanced during the year ended 31 December 2023. The loan is to be repaid whether or not the acquisition of Block 8 completes.
In addition, following the loan restructuring with related parties in 2022, an amount of US$ 67,000 remains outstanding from Kuat Oraziman (2022: US$ 167,000).
The total interest income for the year was US$ 169,000 (2022: US$ nil).
Trade receivables
The trade receivables balance includes US$ 3,703,000 (2022: US$ nil) due from Block 8 for the provision of drilling services by the Group on the Block 8 licence area. The balance remains outstanding as of the date of this report due to the ongoing acquisition of Block 8.
Other receivables from related parties
As at 31 December 2022, other receivables from related parties included US$ 1,001,000 due from Akku Investments which was repaid during the year ended 31 December 2023.
Other receivables
The other receivables balance includes US$ 1,275,000 (2022: US$ 1,275,000) which represent the amounts reimbursable by the vendors of 3A Best under the indemnities provided on acquisition of the exploration asset. The gross amount due is US$ 3,826,000 which was impaired during 2020 by US$2,551,000 or 2/3 of the originally recognised amount due to the uncertainty of recovering 100% of the amounts due in future periods.
Prepayments made
The balance consists primarily of advance payments made to subcontractors. During 2022 BNG Ltd. LLP impaired the advance payment made to Sinopec in 2019. Sinopec, the Chinese drilling contractor, was engaged to drill Deep Well A8. However, BNG did not accept the drilling works and did not pay any amount beyond the prepaid amount. At the date of this report, the parties have yet to come to a final agreement. Accordingly, the prepayment has fully impaired.
Intercompany loans
Intercompany receivables are interest free. An expected credit loss provision of US$ 20,700,000 (2022: US$ 20,700,000) has been recognised with the respect of the amounts due from subsidiaries based on the recoverable amount calculated with reference to factors such as the status of underlying licenses, reserves, financial models and future risks and uncertainties.
Expected credit losses
Financial assets shown gross of ECL are detailed below:
| | Group | Group | Company | Company |
| | 2023 | 2022 | 2023 | 2022 |
|
| US$'000 | US$'000 | US$'000 | US$'000 |
| Trade receivable | 3,703 | 629 | - | - |
| Intercompany receivables | - | - | 106,646 | 107,998 |
| Loans to related parties | 3,137 | 1,523 | 3,137 | 1,523 |
| Other receivables | 3,826 | 4,763 | - | - |
|
| 10,666 | 6,915 | 109,783 | 109,521 |
The movements in ECL provision are detailed below:
| | Group | Group | Company | Company |
| | 2023 | 2022 | 2023 | 2022 |
|
| US$'000 | US$'000 | US$'000 | US$'000 |
| At 1 January | 2,551 | 2,551 | 20,700 | 20,700 |
| Change in estimate recognised in profit or loss | 629 | - | - | - |
| As at 31 December | 3,180 | 2,551 | 20,700 | 20,700 |
As at 31 December 2023, an ECL loss provision of US$ 629,000 was recognised in relation to a trade debtor that is over a year old. The Directors note that non-payment is rare and would typically only provide for trade debtors over a year old. The ECL provision as at 31 December 2022 relates to the 3A Best receivable discussed above.
17 Cash and cash equivalents
| | Group | Group | Company | Company |
| | 2023 | 2022 | 2023 | 2022 |
| | US$'000 | US$'000 | US$'000 | US$'000 |
| Cash at bank and in hand | 447 | 3,682 | 48 | 2,405 |
| Restricted use cash | 706 | 694 | - | - |
Cash at bank and in hand are held in US Dollars, Sterling and Kazakh Tenge currency accounts to enable the Group to trade and settle its debts in the currency in which they occur and in order to mitigate the Group's exposure to short-term foreign exchange fluctuations. All cash is held in floating rate accounts.
Restricted use cash represents cash set aside by the Group for the purpose of creating an abandonment fund to cover the future cost of the decommissioning of oil and gas wells and related facilities and in accordance with local legal rulings. The cash is held in a segregated bank account and under the Subsoil Use Contracts the Group must place 1% of the capital expenditure incurred in the year into an escrow deposit account, unless agreed otherwise with the Ministry of Energy. At the end of the contract this cash will be used by the Group to return the field to the condition that it was in before exploration started.
18 Called up share capital
Group and Company
| | Number of ordinary shares |
US$'000 | Number of deferred shares |
US$'000 |
| Balance at 1 January 2022 | 2,110,772,114 | 31,118 | 373,317,105 | 64,702 |
| Debt to equity conversion | 139,729,445 | 1,942 | (373,317,105) | (64,702) |
| Balance at 31 December 2022 and 31 December 2023 | 2,250,501,559 | 33,060 | - | - |
The Company has one class of ordinary shares of 1 penny each which entitle the holders to receive dividends as declared from time to time to vote at meetings of the Company. All ordinary shares rank equally with regard to the Company's residual net assets. There are no restrictions on the transfer of shares and all ordinary shares are fully paid.
During 2022 the Company cancelled the deferred shares account (note 30).
On 9 March 2022 following the approval by independent shareholders of the Company, US$6,215,000 of related party debt was converted to equity with the issue of 139,729,445 shares at a price of 3.2p per share, comprising:
(1) 100,021,431 shares issued to offset the loans payable by the Group to Akku Investments LLP
(2) 39,708,014 shares issued to repay loans and salary debts to Kuat Oraziman totalling US$1,766,212.
On 9 March 2022 the Company completed the debt conversion first announced in 2021. Accordingly, 139,729,446 Debt Conversion shares were issued to convert US$ 6,215,000 loans payable to Oraziman family and related entities (note 23).
19 Dividends
Year ended 31 December 2023
The Company declared dividends in January and February 2023, totalling US$ 2,377,000 or 0.11 US cents per share. No final dividend in respect of the year is proposed. As at 31 December 2023, the dividends due to the Oraziman family totalling US$ 698,000 have not been paid. Dividends totalling US$ 421,000 were paid by a Group entity on behalf of the Company (2022: US$ nil).
Year ended 31 December 2022
On 4 November 2022 the Company announced its first interim dividend to shareholders of in total £1,000,000 (equivalent of US$ 1,222,000), which was paid in December 2022. Additionally, in December 2022 the Company declared a second dividend of US $ 1,222,000 which was paid in January 2023. Total declared in 2022 dividends were US$ 2,444,000 (0.10 US cents per share).
In the Company's accounts at 31 December 2022 the dividends payable were US $1,347,000, of which around 10% were unpaid. The November 2022 dividends held due to dispute over share ownership. In 2023 the outstanding at 31 December 2022 dividends were paid.
20 Trade and other payables
|
| Group | Group | Company | Company |
|
| 2023 | 2022 | 2023 | 2022 |
|
| US$'000 | US$'000 (restated) | US$'000 | US$'000 |
| Trade payables | 4,689 | 1,817 | 150 | 21 |
| Taxation and social security | 3,224 | 1,725 | 20 | 20 |
| Accruals | 252 | 4,031 | 83 | 106 |
| Other payables | 2,101 | 2,385 | 83 | 18 |
| Intercompany payables | - | - | 3,683 | 1,693 |
| Dividends payable to related parties | 698 | 1,347 | 698 | 1,347 |
| Deferred revenue | 5,131 | 3,523 | - | - |
| | 16,095 | 14,828 | 4,717 | 3,206 |
At 31 December 2023 and 31 December 2022, the Group had received significant prepayments from the customers in respect of oil sales, oil trading and on drilling contracts which are recognised within deferred revenue. The amount of the advances received from oil trades with respect to oil sales as at 31 December 2023 were US$ 2,836,000 (2022: US$ 2,192,000). The amount received by CTS LLP at 31 December 2023 was US$ nil (2022: US$ 704,000) and the amount received by the oil trading business was US$ 2,295,000 (2022: US$ nil).
21 Withholding tax payable
| | Group | Group |
| | 2023 | 2022 |
| | US$'000 | US$'000 |
| Withholding tax payable in Kazakhstan | 14,892 | 13,779 |
|
| 14,892 | 13,779 |
Taxation payable relate to withholding tax accrued on the interest expense at the BNG subsidiary level.
22 BNG historic cost liability
|
|
|
| Group | Group |
|
|
|
| 2023 | 2022 |
|
|
|
| US$'000 | US$'000 |
| Current |
| | 3,178 | 3,178 |
| Non-current |
| | 13,746 | 16,297 |
| |
|
| 16,924 | 19,475 |
The subsoil use contract held by BNG Ltd for the MJF field stipulates that it must make a payment to the Kazakhstan Government upon award of a production contract after commercial feasibility. The Kazakhstan Government has assessed the amount payable as a total of US$32.5m. The sum is payable on a quarterly basis from 1 July 2019 in equal instalments with the final payment due to be paid on 1 April 2029. The future payments have been discounted to their net present value. This discounted value has been capitalised as Property, plant and equipment and will be amortised over the expected life of field of 10 years. As at 31 December 2023, the undiscounted outstanding amount payable is US$17.9m (2022: US$21.1m).
23 Borrowings
|
| Group | Group | Company | Company |
|
| 2023 | 2022 | 2023 | 2022 |
|
| US$'000 | US$'000 | US$'000 | US$'000 |
| Bank credit facility | 3,211 | - | - | - |
| Loans from related parties | 3,483 | 352 | 104 | - |
| | 6,694 | 352 | 104 | - |
| Analysed between current and non-current: |
| |
| |
| Current | 3,624 | 352 | 104 | - |
| Non-current | 3,070 | - | - | - |
|
| 6,694 | 352 | 104 | - |
Bank credit facility
In August 2023, the Group took out a bank credit facility, valid until August 2026, which allows the Group to borrow US$ at an annual interest rate of of 8.3% per annum. Any amounts drawn are repayable within 6 months unless redrawn. The loan is secured against the Group's drilling equipment. As at 31 December 2023, US$3,211,000 remains outstanding (2022: US$ nil).
Loans from related parties
The Group and Company had interest-free short-term loans with the following related parties:
|
| Group | Group | Company | Company |
|
| 2023 | 2022 | 2023 | 2022 |
|
| US$'000 | US$'000 | US$'000 | US$'000 |
| Aibek Oraziman | 285 | - | - | - |
| Vertom International N.V. (a company controlled by Kuat Oraziman) | 129 | 352 | 104 | - |
| | 414 | 352 | 104 | - |
During 2023, one of the Groups subsidiaries entered into interest-free long-term borrowing agreements with Akku Investments LLP, a company controlled by the Oraziman family and shareholders of the Company totalling US$ 4,845,000. The loans are due for repayment in 2026. The fair value of the loans, denominated in KZT, was estimated using market discount rate of 19.5% to be US$ 2,743,000. The difference between the fair value of the loans and their nominal amounts of US$ 2,102,000 was recognised as a capital contribution in equity.
Analysis of movements
The table below details changes in the Group's liabilities arising from financing activities, which consist entirely of borrowings.
|
| | Financing cash flows | Non-cash changes |
| |||
|
| 1 January 2023 US$'000 | Drawdowns US$'000 | Repayments US$'000 | Interest charge US$'000 | Foreign exchange US$'000 | Other US$'000 | 31 December 2023 US$'000 |
| Bank loan | - | 5,820 | (2,689) | 69 | 12 | - | 3,212 |
| Loans from related parties | 352 | 5,343 | (465) | 330 | 17 | (2,095) | 3,482 |
| Total for 2023 | 352 | 11,163 | (3,154) | 399 | 29 | (2,095) | 6,694 |
|
| | Financing cash flows | Non-cash changes |
| |||
|
| 1 January 2022 US$'000 | Drawdowns US$'000 | Repayments US$'000 | Interest charge US$'000 | Foreign exchange US$'000 | Other US$'000 | 31 December 2022 US$'000 |
| Loans from related parties | 6,425 | 352 | (633) | 11 | 412 | (6,215) | 352 |
| Total for 2022 | 6,425 | 352 | (633) | 11 | 412 | (6,215) | 352 |
Other movement in 2022 represents debt for equity swap, detailed in note 18.
The table below details changes in the Company's liabilities arising from financing activities, which consist entirely of borrowings.
|
| | Financing cash flows | Non-cash changes |
| ||
|
| 1 January 2023 US$'000 | Drawdowns US$'000 | Repayments US$'000 | Interest charge US$'000 | Foreign exchange US$'000 | 31 December 2023 US$'000 |
| Loans from related parties | - | 100 | - | 4 | - | 104 |
|
| - | 100 | - | 4 | - | 104 |
|
| | Financing cash flows | Non-cash changes |
| |||
|
| 1 January 2022 US$'000 | Drawdowns US$'000 | Repayments US$'000 | Interest charge US$'000 | Foreign exchange US$'000 | Other US$'000 | 31 December 2022 US$'000 |
| Loans from related parties | 2,382 | 20 | - | 11 | - | (2,413) | - |
|
| 2,382 | 20 | - | 11 | - | (2,413) | - |
Other movement in 2022 represents part of the debt for equity swap, detailed in note 18.
24 Provisions
|
|
|
| Group | Group |
|
|
|
| 2023 | 2022 |
|
|
|
| US$'000 | US$'000 |
| Abandonment provision |
| | 1,286 | 593 |
| Social development programme |
| | 4,355 | 5,853 |
| |
|
| 5,641 | 6,446 |
| Analysed between current and non-current: |
| |
| |
| Current |
| | 4,481 | 5,977 |
| Non-current |
| | 1,160 | 469 |
|
|
|
| 5,641 | 6,446 |
The movement in provisions is detailed below:
|
|
| Social development programme | Abandonment provision | Total |
|
|
| US$'000 | US$'000 | US$'000 |
| At 1 January 2023 |
| 5,853 | 593 | 6,446 |
| Change in estimate |
| (1,504) | 633 | (871) |
| Provision utilised |
| (98) | - | (98) |
| Unwinding of discount |
| - | 50 | 50 |
| Foreign exchange differences |
| 104 | 10 | 114 |
| At 31 December 2023 |
| 4,355 | 1,286 | 5,641 |
| Analysed between current and non-current: |
| |
| |
| Current |
| 4,355 | 126 | 4,481 |
| Non-current |
| - | 1,160 | 1,160 |
|
|
| 4,355 | 1,286 | 5,641 |
Amounts in relation to Subsoil Use Contracts are included in the table above and relate to the licence areas disclosed below:
a) BNG Ltd LLP
BNG Ltd LLP a subsidiary, signed a contract #2392 dated 7 June 2007 with the Ministry of Energy and Mineral Resources of the Republic of Kazakhstan for exploration at Airshagyl deposit, located in Mangistau region. According to the latest Amendments BNG is required to pay around US$ 231,650 annually in respect of social programs in the Mangistau region for the period from 7 June 2018 to 7 June 2024. Also, it is required to pay 1% of investments under the contract on production during the period based on the results of the previous year. For the exploration period extended to June 2024, the amount of the commitments under the work program according to the contract on exploration is US$ 28 million dollars. BNG is also required to invest in the training of Kazakh personnel of an amount of not less than 1% of annual amount of investments. Another requirement of the Company is to accumulate funds for the site restoration by transferring annually 1% of annual exploration costs to a special deposit in accordance with the Contract on exploration. As at 31 December 2023 BNG was in compliance with all the requirements listed above.
On 11 July 2019, BNG Ltd LLP signed a production contract with the Ministry of Energy of the Republic of Kazakhstan at the North-West Yelemes structure. The Contract is valid for 25 years till 2043. On 23 December 2021, BNG signed the production contract at South Yelemes structure for an initial period of 6 months. The terms were extended in accordance with the additional agreement No. 1 dated 24 June 2023, and valid until June 23, 2044. No additional social obligations were added for the 2019 and 2022 contract extensions and upgrades.
b) 3A-Best Group JSC
As at 31 December 2020 3A-Best had the following debts related to its sub soil use contract (SSUC): US$2,500,000 of social development payment and approximately US$ 1,000,000 of debts related to the previous years' work programme obligations. According to the Addendum #8 to the Contract signed by the Company on 20 January 2020 3A-Best has agreed the following schedule of payments related to the social development and the work program related to previous SSUC extension(s):
· To make payments of US$580,000 quarterly for the 6 quarters ending in June 2021;
· To drill 2 shallow wells with the total depth of 5,750 meters during the period January-June 2020;
· To make investments of approximately US$2,350,000 during the period January-June 2020.
The Company did not meet all the above in full but made some payments while seeking a solution to the situation. In 2021 the Group received a notification from the Ministry of Energy of Kazakhstan that as the Subsoil Use contract was not extended in July 2020 the contract was deemed to have expired on that date. The Board is working with the Kazakh authorities to renew the licence at 3A Best, following which the Board will assess 3A Best's position in the Group. As at 31 December 2023, the Board is satisfied that this provision can be released and with a corresponding gain of US$ 1,505,000 recognised as other operating income in profit or loss.
The Group and Company has no contingent liabilities (2022: none).
25 Deferred tax
Deferred tax liabilities comprise:
| |
| Group 2023 | Group 2022 |
|
| US$'000 | US$'000 | |
| Deferred tax on exploration and evaluation assets acquired | | 7,377 | 6,335 |
| | | 7,377 | 6,335 |
The Group recognises deferred taxation on fair value uplifts to its oil and gas projects arising on acquisition. These liabilities reverse as the fair value uplifts are depleted or impaired.
The movement on deferred tax liabilities was as follows:
|
| Group 2023 | Group 2022 |
|
| US$'000 | US$'000 |
| At beginning of the year | 6,335 | 6,463 |
| Foreign exchange | 1,042 | (128) |
| | 7,377 | 6,335 |
As at 31 December 2023 the Group has accumulated deductible tax expenditure related to BNG of approximately US$48 million (31 December 2022: US$62 million) available to carry forward and offset against future profits. This represents an unrecognised deferred tax asset of approximately US$10 million (31 December 2022: US$12 million). Given the uncertainties regarding such deductions and the developing nature of the relevant tax system no deferred tax asset is recorded.
26 Share option scheme and LTIP scheme
During the year the Company had in issue equity-settled share-based instruments issued to its Directors and certain employees.
On 10 January 2022 Shin Seokwoo, Chief Operating Officer was granted 2,500,000 options exercisable at 5.5p and Edmund Limerick, non-executive director was granted 1,000,000 options exercisable at 5.5p per share. The options granted vested immediately and are exercisable until 9 January 2032. The fair value of the options was calculated using the Black Scholes option pricing model and was found to be immaterial.
No options were granted during the year ended 31 December 2023. The movements in the number of share options and their weighted average exercise price is detailed below:
|
| 2023 | 2023 | 2022 | 2022 |
|
| Number of options | Average exercise price (pence) | Number of options | Average exercise price (pence) |
| 1 January | 14,850,000 | 13.9 | 11,350,000 | 16.5 |
| Granted in the year | - | - | 3,500,000 | 5.5 |
| 31 December | 14,850,000 | 13.9 | 14,850,000 | 13.9 |
| | | | | |
| Exercisable at 31 December | 14,850,000 | 13.9 | 14,850,000 | 13.9 |
The range of exercise prices of share options outstanding at 31 December 2023 and 31 December 2022 is 4p - 20p (2022: 4p - 20p). The weighted average remaining contractual life of share options outstanding at the end of 2023 is 3.1 years (2022: 4.1 years).
Long Term Incentive Plan (LTIP) scheme:
On 5 June 2019 the Company made awards under a long term incentive plan. Clive Carver, Chairman, and Kuat Oraziman, Chief Executive Officer, are entitled to receive cash payments to be triggered by the Company's attainment of both pre-set market capitalisation and share price targets as follows:
| Market cap threshold | Share price target | Pay-out rate (each) | Pay-out amount (each) |
| $ billion | Pence per share | % | $' million |
| | | | |
| 0.8 | 17.23 | 0.6 | 3.0 |
| 1.3 | 20.67 | 0.6 | 3.0 |
| 1.8 | 24.81 | 0.6 | 3.0 |
| 2.3 | 29.77 | 0.6 | 3.0 |
| 2.8 | 35.72 | 0.6 | 3.0 |
The scheme continues beyond the numbers in the table such that with the threshold for market capitalisation increasing at the rate of $0.5 billion and the corresponding share price threshold increasing from the earlier threshold by a constant factor of 1.2. Each threshold must be sustained for at least 30 consecutive days for the awards to be triggered. Payments shall be made only when the Company has free cash either in the form of distributable reserves or as a result of a non-interest bearing subordinated shareholder loan or an equity placing at a price not below the relevant share price threshold.
There may be only one pay-out for each market capitalisation threshold crossed no matter how many times it is crossed.
The Directors have determined that at inception and as at 31 December 2022 and 2023, the fair value of the cash settled share based payment award is immaterial based on analysis of the thresholds, historical volatility rates and the applicable share price and market capitalisation in the period.
For the year ended 31 December 2023, no charge has been recognised in profit or loss in respect of the share options and LTIP (2022: US$ nil) on the basis that the conditions are unlikely to be met.
27 Financial instrument risk exposure and management
In common with all other businesses, the Group and Company are exposed to risks that arise from its use of financial instruments. This note describes the Group and Company's objectives, policies and processes for managing those risks and the methods used to measure them. Further quantitative information in respect of these risks is presented throughout these financial statements.
The significant accounting policies regarding financial instruments are disclosed in note 1.
There have been no substantive changes in the Group or Company's exposure to financial instrument risks, its objectives, policies and processes for managing those risks or the methods used to measure them from previous years unless otherwise stated in this note.
(a) Categories of financial instruments
The principal financial instruments used by the Group and Company, from which financial instrument risk arises, are as follows:
|
Financial assets | Group 2023 US$'000 | Group 2022 US$'000 | Company 2023 US$'000 | Company 2022 US$'000 | ||
| |
| |||||
| Intercompany receivables | - | - | 85,946 | 87,298 | ||
| Loan to related parties | 3,137 | 1,523 | 3,137 | 1,523 | ||
| Other receivables from related parties | - | 1,001 | - | - | ||
| Other receivables | 1,275 | 2,212 | - | - | ||
| Restricted use cash | 706 | 694 | - | - | ||
| Cash and cash equivalents | 447 | 3,682 | 48 | 2,405 | ||
| | 5,565 | 9,112 | 89,131 | 91,226 | ||
|
| ||||||
| Financial liabilities | Group 2023 US$'000 | Group 2022 US$'000 | Company 2023 US$'000 | Company 2022 US$'000 | ||
| |
| |
|
| ||
| Trade and other payables | 4,689 | 1,817 | 150 | 21 | ||
| Accruals | 252 | 4,031 | 83 | 106 | ||
| Intercompany payables | - | - | 3,683 | 1,693 | ||
| Borrowings | 6,694 | 352 | 104 | - | ||
| BNG historic costs payable | 16,924 | 19,475 | - | - | ||
|
| 28,559 | 25,675 | 4,020 | 1,821 | ||
All financial assets and liabilities of the Group and Company are carried at amortised cost.
(b) Risk management
The principal financial instruments used by the Group and Company, from which financial instrument risk arises, are as follows:
· other receivables;
· cash at bank;
· trade and other payables; and
· borrowings.
General objectives, policies and processes
The Board has overall responsibility for the determination of the Group and Company's risk management objectives and policies. Whilst retaining ultimate responsibility for these objectives and policies, it has delegated the authority for designing and operating processes that ensure the effective implementation of the objectives and policies to the Group and Company's finance function. The Board receives regular reports from the finance function through which it reviews the effectiveness of the processes put in place and the appropriateness of the objectives and policies it sets.
The overall objective of the Board is to set policies that seek to reduce risk as far as possible without unduly affecting the Group and Company's competitiveness and flexibility. Further details regarding these policies are set out below:
Credit risk
The maximum exposure to credit risk is represented by the carrying amount of each financial asset in the balance sheet, which at the year-end amounted to US$ 5.6 million (2022: US$ 9.1 million). Credit risk with respect to Group receivables and advances is mitigated by active and continuous monitoring of the credit quality of its counterparties through internal reviews and assessment.
The Company is exposed to credit risk on its receivables from its subsidiaries. The subsidiaries are exploration and development companies with no current commercial exploitation sales and therefore, whilst the receivables are due on demand, they are not expected to be paid until there is a successful outcome on a development project resulting in commercial exploitation sales being generated by a subsidiary. In application of IFRS 9 the Company has calculated the expected credit loss from these receivables (Note 16).
The carrying amount of financial assets recorded in the Group and Company financial statements, which is net of any impairment losses, represents the Group's and Company's maximum exposure to credit risk.
Credit risk with cash and cash equivalents is reduced by placing funds with banks with high credit ratings.
Capital
The Company and Group define capital as share capital, other reserves, retained profit and borrowings. In managing its capital, the Group's primary objective is to provide a return for its equity shareholders through capital growth. The Group will seek to maintain a gearing ratio that balances risks and returns at an acceptable level and also to maintain a sufficient funding base to enable the Group to meet its working capital and strategic investment needs. In making decisions to adjust its capital structure to achieve these aims, either through new share issues or the issue of debt, the Group considers not only its short-term position but also its long-term operational and strategic objectives.
The Group's gearing ratio as at 31 December 2023 was 9% (2022: 1%).
There have been no other significant changes to the Group's Management objectives, policies and processes in the year.
Liquidity risk
Liquidity risk arises from the Group and Company's Management of working capital and the amount of funding committed to its exploration programme. It is the risk that the Group or Company will encounter difficulty in meeting its financial obligations as they fall due.
The Group and Company's policy is to ensure that it will always have sufficient cash to allow it to meet its liabilities when they become due. To achieve this aim, it seeks to raise funding through equity finance, debt finance and farm-outs sufficient to meet the next phase of exploration and where relevant development expenditure.
The Board receives cash flow projections on a periodic basis as well as information regarding cash balances. The Board will not commit to material expenditure in respect of its ongoing exploration programmes prior to being satisfied that sufficient funding is available to the Group to finance the planned programmes.
For maturity dates of financial liabilities as at 31 December 2023 and 2022 see the table below. The amounts are contractual payments and may not tie to the carrying value:
|
| On Demand | Less than 3 months | 3-12 months | 1- 5 years | Total |
| Group 2023 US$'000 | 386 | 5,754 | 5,783 | 19,479 | 32,402 |
| Group 2022 US$'000 | 352 | 6,661 | 2,439 | 17,886 | 27,338 |
| Company 2023 US$'000 | 3,683 | 232 | - | - | 3,915 |
| Company 2022 US$'000 | 1,693 | 128 | - | - | 1,821 |
Interest rate risk
The majority of the Group's borrowings are at fixed rate. As a result the Group is not exposed to significant interest rate risk.
Currency risk
Currency risk is the risk that that the fair value or future cash flows of a financial instrument will fluctuate because of changes in foreign exchange rates. Currency risk arises on financial instruments that are denominated in a different currency to the entity's functional currency in which they are measured.
The Group and Company's policy is, where possible, to allow group entities to settle liabilities denominated in their functional currency (primarily US$ and Kazakh Tenge) in that currency. Where the Group or Company entities have liabilities denominated in a currency other than their functional currency (and have insufficient reserves of that currency to settle them) cash already denominated in that currency will, where possible, be transferred from elsewhere within the Group.
The Group and Company's currency risk exposure arises primarily from the following currencies:
|
| Group 2023 | Company 2023 |
|
| US$'000 | US$'000 |
| Assets | | |
| USD | 66 | - |
| | 66 | - |
| Liabilities | | |
| USD | 3,211 | - |
| GBP | 848 | 848 |
| | 4,059 | 848 |
A 30% strengthening of USD would decrease the Group profit for the year by US$ 944,000 (2022: US$ nil) and increase a loss for the year of US$ 112 million recognised in other comprehensive income due to retranslation of intercompany loans, with a total decrease in equity of US$ 114 million (2022: US$ 38 million) A 30% weakening of USD would have an equal but opposite effect.
The 30% sensitivity is the sensitivity rate used when reporting foreign currency risk internally to key management personnel and represents Directors' assessment of the reasonably possible change in foreign exchange rates. The sensitivity analysis includes only outstanding foreign currency denominated monetary items and adjusts their translation at the year-end. The sensitivity analysis includes long term intercompany loans to foreign operations within the Group where the denomination of the loan is in a currency other than the currency of the lender or the borrower where changes in the foreign exchange rate are recognised in other comprehensive income.
28 Related party transactions
The Company has no ultimate controlling party. Related party transactions are detailed below and have been carried out at arms-length.
28.1 Key management remuneration
| | Group 2023 US$'000 | Group 2022 US$'000 |
| Short-term employee benefits | 436 | 380 |
| | 436 | 380 |
The Directors are the key management personnel of the Company and the Group. Details of Directors' emoluments and interests in shares are shown in the Remuneration Committee Report. The highest paid director had emoluments totalling US$153,000 (2022: US$157,000).
Kuat Oraziman and Aibek Oraziman are directors of the Company and members of the Oraziman family, which collectively is deemed a related party to the Group. Apart from remuneration, there were no other transactions with other members of the key management personnel.
28.2 Block 8 Acquisition agreement
In September 2022, the Company entered into an option agreement with Mr. Altynbek Bolatzhan, an Oraziman family member, for the Company to acquire EPC Munai LLP ("Block 8"). The maximum consideration for the asset is $60 million, payable in cash from future production from Block 8, at the rate of $5 per barrel of oil produced. The Company exercised its option to acquire Block 8 during the year ended 31 December 2023. The completion of the acquisition is subject to, inter alia, Block 8 renewing its licences and gaining regulatory approvals, which as at the date of approving these financial statements have not been received and therefore the acquisition has not been completed.
28.3 Loan agreements and other payables and receivables.
The Company and Group has payable to and receivable from members of the Oraziman family and legal entities controlled by them. The details of loan and other receivables are included in note 16 and details of loans and other payables are included in note 20. Dividends due to related parties are disclosed in note 19.
28.4 Sales of services
CTS LLP, the Group's onshore drilling subsidiary, undertakes repair and drilling work at Block 8 (EPC LLP), which as detailed above is owned by a related party and the Group is in the process of acquiring. Summary of contracts are detailed below.
P1 Drilling
In 2021, CTS LLP entered into a contract to drill a side-track at Well P1. The value of the contract was fixed at KTZ 450 million (US$ 976,000). The contract was completed during 2021 and 2022 with total costs to complete of US$ 1,535,000.
P3 Drilling and AKD Drilling
In 2022 CTS LLP, entered into additional contracts with EPC Munai to drill a further 2 deep wells on Block 8's Skolkara structure.
Well P3
The first is Well Р-3, with a contract value of US$ 6,484,000. At 31 December 2022 only the preparatory works had been completed, which Directors estimate to be approximately 7% of the total work. At 31 December 2022, $470,000 had been paid to CTS LLP for the drilling work.
During 2023 work at the well has been put on hold to allow other projects to proceed and was eventually terminated when EPC's licence over the contract area expired. Over the contract life, CTS LLP billed US$ 500,000 against costs incurred of US $558,000.
Well AKD
The second is Well AKD where the original contract value was US$ 4.3 million. At 31 December 2022 the well had reached a depth of 2,187 meters, representing approximately 20% of the total work. At 31 December 2022 $1,652,000 had been paid to CTS LLP for the drilling works.
Similarly to the P3 Drilling contact, during 2023 the contact was put on hold and eventually terminated when EPC's licence over the contract area expired. Over the contract life, CTS LLP billed US$ 2,648,000 against costs incurred of US $2,966,000.
Toresai Drilling
In October 2023, CTS LLP entered into a contract to drill a well at Toresai, however it was also terminated when EPC's licence over the contract area expired. CTS LLP billed US$ 2,214,000 against costs incurred of US $2,480,000.
The impact on the Group financial statements, is summarised below.
| | Group 2023 US$'000 | Group 2022 US$'000 (restated) |
| Revenue | 4,126 | 1,590 |
| Cost of sales | (4,735) | (1,834) |
| Other income | - | 211 |
| Net loss | (609) | (33) |
| Amounts due from related parties | 3,703 | - |
| Contract liabilities, due to related parties | - | (1,021) |
29 Non-controlling interest
| |
| Group 2023 | Group 2022 |
|
| US$'000 | US$'000 | |
| Balance at the beginning of the year | | (5,667) | (5,801) |
| Share of profit / (loss) for the year | | 515 | 134 |
| | | (5,152) | (5,667) |
Non-controlling interest represents minority share in BNG Ltd LLP and Beibars Munai LLP held by related party.
30 Capital reduction made in 2022
In order to start paying dividends, the Company required distributable reserves. Accordingly, on 22 April 2022, the Company's shareholders granted their approval for a capital reduction. On 22 June 2022, the UK High Court confirmed the capital reduction. Consequently, the Company cancelled its share premium and deferred shares accounts, resulting in positive retained earnings from that date as follows:
Share premium account reduced by US$169,089,000.
Deferred shares account reduced by US$64,702,000.
Retained earnings (loss) account increased in total by US$233,791,000.
31 Events after the reporting period
In April 2024, the Group entered into a binding agreement to acquire 100% of issued share capital of CS Energy LLP which holds licences to the West Shalva contract area for a maximum consideration of US$ 15 million. The acquisition is conditional on, inter alia, on the approval of Company's shareholders and regulatory approvals. The shareholder approval was granted 25 April 2024. CS Energy LLP is controlled by a Altynbek Bolatzhan, a member of the Oraziman family and thus a related party.
On 24 April 2024, the Company issued 4,476,923 new ordinary shares at 3.25 pence each in settlement of certain outstanding fees owed to an adviser.
On 24 April 2024 the Company also granted replacement awards in total 4,500,000 new options, including 2,500,000 4p options to Seokwoo Shin, a director of the Company, with the additional 2,000,000 options being issued non board staff. 2,500,000 5.5p options previously awarded to Seokwoo Shin have been cancelled, resulting in the net new options totalling 2,000,000.
Additionally, the exercise date for 2,400,000 4p options held by Clive Carver has been extended until 30 April 2025.
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