AUDITED ANNUAL RESULTS FOR THE YEAR ENDED 31/12/23

27 June 2024

Challenger Energy Group PLC

("Challenger Energy" or the "Company")

AUDITED ANNUAL RESULTS FOR THE YEAR ENDED 31 DECEMBER 2023

Challenger Energy (AIM: CEG), an Atlantic margin focused oil and gas company, is pleased to announce its audited Annual Results for the year ended 31 December 2023.

The 2023 Annual Report and Financial Statements will be posted to shareholders by 30 June 2023 along with the notice of the Company's Annual General Meeting to be held on 29 July 2024 at 11.00 a.m. British Summer Time at The Engine House, Alexandra Road, Castletown, Isle of Man IM9 1TG.

The 2023 Annual Report and Financial Statements are set out in full below and are also available on the Company's website https://www.cegplc.com/.

For further information, please contact:

Notes to Editors

Challenger Energy is an Atlantic-margin focused energy company, with production, development, appraisal, and exploration assets in the region. The Company's primary assets are located in Uruguay, where the Company holds high impact offshore exploration licences. Challenger Energy is quoted on the AIM market of the London Stock Exchange.

https://www.cegplc.com 

Chairman's Letter to the Shareholders

Dear Shareholders,

It is my pleasure to report to you as Chairman of your Company.

In my last report I commented on our strategic objectives for 2023: achieving value for our Uruguay AREA OFF-1 licence, and resetting our business in Trinidad and Tobago. I am pleased to be reporting that as of this Annual Report, both strands of our objectives have been achieved.

In Trinidad and Tobago, disposals of non-core assets have successfully completed, and the reset of 'efficiency and profit' around our core assets of Goudron and Inniss-Trinity continues. It is a credit to our team in Trinidad and Tobago that we continue to have safe and sustained operations in country, and I take this opportunity of thanking that team on behalf of shareholders and the Board of Directors. In 2023, we also exited our acreage position in Suriname, ensuring that all operational focus is on Trinidad and Tobago.

In Uruguay, we had a very clear objective of creating value for our shareholders by the farm-out of AREA OFF-1. We announced a successful farm-out to Chevron earlier this year, which came as a result of a well-run process. As reported, the transaction is yet to close, but we do expect to have completed all regulatory matters in the course of the coming months.

In Uruguay, we also secured the award of AREA OFF-3, and as was the case with AREA OFF-1, with a prudent work programme.

Overall, Uruguay acreage is still benefitting from the almost constant stream of good news coming from the African side of the Atlantic conjugate margin. We look forward to working closely and supportively with Chevron over the coming months and years to make AREA OFF-1 a highly successful venture. We are equally excited about our plans to enhance value at AREA OFF-3. Eytan, in his CEO report, expands on the detail behind the work undertaken and planned on both our Uruguayan licences.

In April 2024, we reported on the strategic investment by Charlestown Energy Partners in the Company, and I look forward to working with Robert Bose on the Board.

Finally, and as always, I thank the staff of Challenger Energy for their efforts last year, the Board for their guidance and insight and, of course, our shareholders for their continued support.

Iain McKendrick

Chairman

26 June 2024

Chief Executive Officer's Report to the

Shareholders

Dear fellow Shareholders,

This is my fourth report to you, the owners of the Company, in my capacity as Chief Executive Officer.

The last 18 months has been a period of excellent progress for Challenger Energy. During this period, we did what we said we would do and we delivered most of what we promised we would deliver. The highlight event being the farm-out of our AREA OFF-1 block in Uruguay to Chevron, a transaction which is transformational for our Company in that it will lead to an exciting program of value-adding activity over the coming 18 months, as well as ensuring that we are fully-funded for the foreseeable future. Therefore, as we look to the second half of 2024 and beyond, I believe that our Company is in the best position it has been in for many years. Details are provided in my commentary below.

Strategic Context

In last year's Annual Report, I reported on several key developments in Challenger Energy's business during the 2022 period.

In summary, these were (i) the Company and its business had been successfully "reset", both operationally and financially;

(ii) significant exploration discoveries had been made in the Namibian conjugate margin, analogous to the Company's licenced

acreage in Uruguay; and (iii) endeavours to increase production from our Trinidad assets had proved difficult.

As a result of these factors the Company responded during 2023 with a shift in strategy to place primary emphasis on our Uruguayan assets, and to deemphasise growth in Trinidad in favour of achieving cashflow breakeven from the core Trinidadian assets while divesting any assets non-core to this objective.

Uruguay

In a relatively short space of time, our interests in Uruguay have become the centrepiece of our business. It is the place where we expect to be able to realise the greatest incremental value over the coming years, and it is thus the place where we are now focusing much of our efforts.

Shareholders will recall that in 2020 we were awarded the licence for the AREA OFF-1 block, offshore Uruguay. At the time we saw Uruguay as being an underexplored frontier basin location with reasonable potential, although at that time Uruguay was not on the global sector radar, so when we were awarded the AREA OFF-1 licence Challenger Energy became Uruguay's sole licence holder. However, in geological terms Uruguay, we believe, is the "mirror" of Namibia's Orange Basin, and thus when very large new discoveries were made by supermajors in the Orange Basin in 2022, Uruguay become a global exploration "hotspot". In less than two years Uruguay's offshore went from being completely unlicenced to being 100% licenced, with every offshore block (other than Challenger Energy's) licenced to majors / NOC. Moreover, new entrants committed to significant work programs to secure their licences, in contrast to the modest work program we bid to secure AREA OFF-1.

In this context we decided to strategically prioritise Uruguay. We laid out a plan of action, and over the last 18 months we successfully executed on that plan, as follows:

(i)    We accelerated our technical work program on AREA OFF-1, thereby rapidly enhancing the value of the asset. Our work program was thorough and focused, including reprocessing of legacy 2D seismic data, advanced amplitude variation with offset (AVO) analysis, seabed geochemical and satellite seep studies and full reinterpretation and remapping of all data, leading to lead and then prospect definition and an initial volumetric assessment. The result was delineation and high grading of three primary prospects, in aggregate representing an inventory of approximately 2 billion barrels (Pmean) and up to 5 billion barrels in an upside case (P10). This served to establish AREA OFF-1 as a high-quality asset of global scale and materiality. Focused technical work continued throughout 2023, in support of maximising the potential for securing a farm-out. This also meant that by the end of 2023 our minimum work program commitment for the first four-year period of the AREA OFF-1 licence - initially meant to be completed by August 2026 - had been completed, more than two years ahead of schedule.

(ii)   To fully leverage the value of our acquired knowledge and understanding, the excellent working relationship established with the Uruguayan authorities and regulators, and the attractive conditions in that country for hydrocarbon industry activity, we decided to bid for a second licence. We were successful in this endeavour, and in June 2023 Challenger Energy was designated as the party to whom the AREA OFF-3 licence - the last available offshore acreage in Uruguay - would be awarded, on attractive terms. This award was subsequently finalised in March 2024, with the initial four-year exploration period for AREA OFF-3 commencing in June 2024. As a result of this award, our Company has emerged as the 3^rd largest net acreage holder in Uruguay, and the only junior E&P company with any position in the Uruguay offshore, holding two world class assets and a growing prospect inventory in what has fast become a highly desirable exploration "postcode".

(iii)  On the basis of our excellent technical results, in mid-2023 we launched a formal, adviser-led farm-out process for AREA OFF-1. The objective was to secure an industry heavyweight as a partner for the project, who could provide the further expertise and capital needed to rapidly take AREA OFF-1 forward to 3D seismic acquisition and ultimately exploration well drilling. Our target was to secure a farm-out by the end of 2023, and whilst ultimately the process took a few months longer than planned, in March 2024 we entered into a farm-out agreement with Chevron. Under the terms of that agreement, Chevron will assume a 60% operating interest in AREA OFF-1, will pay the Company US$12.5 million cash as an entry fee, will carry 100% of the costs of an agreed accelerated 3D seismic acquisition on the block (up to a total net cash value to the Company of US$15 million), and thereafter if the decision is made to proceed to drilling of an initial exploration well, carry 50% of the Company's share of costs associated with that well (up to a total net cash value to the Company of US$20 million). As at the date of this Annual Report, Chevron's entry into the project awaits approval from the Uruguayan regulatory authorities, a normal industry formality for any farm-out and one which we expect will be concluded in the coming months, well within the time needed to allow for Chevron's proposed 3D seismic acquisition to commence at the end of 2024/early 2025. We anticipate thereafter that we will see Chevron undertake significant activity on AREA OFF-1, and it is this activity which we believe will ultimately realise the considerable value we see in this asset.

In summary, the recap for 2023 insofar as our business in Uruguay is concerned is that we completed a high-quality and value-accretive technical work program for AREA OFF-1, we materially expanded our Uruguayan asset base through adding the AREA OFF-3 licence to the portfolio, and we secured a market-leading farm-out for AREA OFF-1.

However, before moving on to considering the rest of our business, I think it is worth making a brief, specific comment on the value and impact of this last item - the farm-out agreement with Chevron. As already noted, entry into this agreement was undoubtedly the highlight of the last 18 months for Challenger Energy, and represented the culmination of a huge amount of technical and commercial work, by many people over more than a year. It is thus an outcome we are extremely proud of, and is important for two reasons.

Firstly, the farm-out metrics achieved in this transaction are in our view, excellent. All CEOs will have you know that their Company is undervalued, but in this case, if properly analysed, the embedded value to our Company in the AREA OFF-1 farm-out arrangement is many multiples of our current share price - something I believe the equity market is yet to appreciate.

Secondly, over and above the mere numbers, the AREA OFF-1 farm-out is genuinely transformational for Challenger Energy's future, in that (i) our strategy and technical work has been validated by one of the world's leading energy companies - the resulting intangible benefit in terms of our industry "credentials" is immeasurable, (ii) going forward, operation of the AREA OFF-1 project will be in the hands of an operator and partner who has made a clear commitment to accelerating 3D seismic acquisition (and hopefully thereafter, exploration well drilling), and (iii) we will retain a material stake of 40% in the AREA OFF-1 licence, which will give us enormous flexibility when it comes time to consider how we participate in any future success case.

Trinidad and Tobago

By the end of 2022 we had come to the conclusion that achieving a material increase in production from our Trinidadian onshore asset portfolio was not commercially viable, due to the age of the fields and the technical characteristics of the relevant reservoirs. We thus shifted our objective from production growth to achieving financial breakeven from core assets, and streamlining our operations by divesting any assets considered non-core to this objective.

Thus, in early 2023, we sold the small and geographically removed South Erin asset, and in late 2023 we completed the sale of the non-producing Cory Moruga appraisal asset. In both cases the sales not only realised cash, but also relieved the group of significant liabilities, work program commitments, and administrative burden and cost associated with management of those assets.

At the same time, we concentrated our operational efforts on our two primary producing assets - the Goudron and Inniss-Trinity fields in south-east Trinidad. There, the focus was very clear: maintain constant production, eliminate excess cost, realise operating efficiencies from our people and equipment, and achieve cashflow breakeven.

In terms of results, 2023 production from these two fields was generally constant (on a like-for-like basis almost identical to 2022 production), and total operating expenses and G&A were reduced considerably (33%) as compared to 2022. However, realised oil prices across 2023 were lower than across 2022, so many of the operational gains we made were offset by lower revenue, such that whilst we were successful in operating on a cashflow breakeven basis, we did record a (relatively small) net operating loss (as compared to a small positive operating cash surplus in 2022). This financial performance also necessitated us reconsidering the carrying value of the Trinidadian licences on our balance sheet, and at the end of 2023 we decided to write down both the goodwill and asset values associated with these licences.

Through 2023 we also spent a substantial amount of time and effort on trying to develop options to expand our Trinidad business into a more sizeable and profitable production operation, either through organic growth or through adding new acreage to our portfolio. However, despite our best efforts, we did not make any progress of note on this important task.

In summary therefore, insofar as our business in Trinidad is concerned, I can report that 2023 was a mixed year. We largely met our core objectives of achieving cashflow breakeven operations and selling non-core assets. But, we did not turn a profit, and we did not "crack the code" as to how, in the longer term, we can transform the Trinidad business into a profitable production base of greater scale. We will continue our efforts to make progress on this front in the coming year.

Other Assets

In relation to the Company's licences in The Bahamas, throughout the course of 2023 we continued to pursue a renewal of the licences into a third exploration period. In parallel we continued to explore various alternative strategies seeking to monetise those assets. The process has been frustratingly slow, but we expect to make better progress in the coming 12 months.

During 2023 we also undertook a detailed "economic basement to surface" technical review of the Weg Naar Zee project in Suriname, and concluded that the project did not offer the prospect of long-term commerciality (especially as compared to the better return potential we saw available from other assets in our portfolio). We thus made the decision to exit from the Suriname project, a process which was fully completed by the end of 2023.

Financial Performance

For the 2023 period under review, we recorded a loss of $13.4 million, although this includes the impact of various non-cash items, including non-cash losses arising from accounting impairments associated with the Trinidadian assets of approximately $12.9 million. Therefore, a more relevant metric to evaluate our financial performance during the period would, in my view, be a consideration of our "burn" - that is, cash used in running/sustaining our business across the period. In that respect, as noted, our Trinidadian operations operated on a largely self-sustaining basis through 2023 (thus requiring no cash support from the group), and the general and administration cost for the rest of our business was reduced to under US$200,000 per month (this being a reduction of 37% as compared to 2022). Based on benchmarking, we believe that this level of "burn" which represents the basic costs needed to stay in business as an AIM-listed vehicle, compares favourably with most of our peers. That said, we are always considering ways in which we can reduce our cost base further.

Capital Allocation and Funding

For a junior E&P company, effective capital allocation is one of management's most important tasks. This is because within any given portfolio of assets, there will almost always be more opportunities and activities in need of funding than there are funds available. With this in mind, prudently managing our available capital has always been a key priority, with the overriding goal being to strike a balance between advancing our business quickly and in the most advantageous way, but at the same time making the most out of every dollar spent, and avoiding to the greatest extent possible the need to seek additional funding by way of dilutive equity raisings.

Pleasingly, over the last 18 months we have largely been able to achieve this goal. Specifically, Challenger Energy's last equity capital raising was in March 2022 as part of a broader corporate restructure / recapitalisation. At that time, we raised an amount that was then estimated to be sufficient to sustain 12 months of future operations, but we have "stretched" the funds raised such that we have operated without needing to undertake an equity placing for more than two years now. We have done this by:

(i)      keeping overheads lean and efficient: as mentioned, through the course of 2023 our corporate overhead was low, both in an absolute sense and as compared to 2022;

(ii)     ensuring any incremental expenditure is very focused in its application: in 2023, we only allocated discretionary capital to value-adding technical work in Uruguay, and, as noted, operations in Trinidad and Tobago were largely self-funding through the period, thus requiring almost no financial support from the Group; and

(iii)    successfully selling non-core assets: the sales of the South Erin and Cory Moruga assets supplemented available working capital, and whilst a delay in regulatory approval for the sale of the Cory Moruga asset necessitated a bridge funding facility being put in place in mid-2023, we were eventually able to deliver on that transaction, which in addition to releasing capital back to the business also allowed for the bridge funding facility to be fully repaid and cancelled.

Subsequently, in May 2024 we secured a meaningful equity investment - at a premium price - from specialist E&P investor Charlestown Energy, and as previously noted, on closing of the farm-out for the AREA OFF-1 licence in Uruguay we will receive US$12.5 million in cash. Against this we have no debt, our cost base is low, the minimum work program on AREA OFF-1 in Uruguay has been completed and our share of 3D seismic costs will be carried by Chevron, the work program for AREA OFF-3 is modest, and we have no unfunded forward work program commitments. This means that once the AREA OFF-1 farm-out completes we will have cash reserves more than adequate to ensure ongoing operations on a "fully-funded" basis for the foreseeable future. This puts our Company in the best financial position it has been in for many years.

ESG

As I noted in last year's Annual Report, the broad category of activities generally referred to nowadays as Environment, Social and Governance, or ESG, are central to everything we do. It is a core value in our business to ensure that achieving our commercial objectives never comes at the expense of harm to people or the environment, and that our "social licence to operate" is maintained intact at all time. We want to be known as a responsible, reliable operator and a partner / employer of choice.

In 2023, our excellent track record in this all-important area was maintained. Across all of our operations there were no incidents of note - whether personal injury, property damage or environmental. We maintained productive and positive relationships with all relevant Governments and regulatory bodies, we continued our policy of investing considerably in Company-wide training programs and ESG awareness activities, and we made a number of targeted social and welfare contributions in the communities where we operate. A tangible expression of our record of achievement in this area was the considerable body of work undertaken in support of renewing our Safe-to-Work (STOW) accreditation in Trinidad, a regulatory certification granted to only a few operators in that country. After almost a full year of preparation and audits this renewal was granted in April 2024, a testament to the strong culture of workplace health and safety awareness, commitment, accountability and performance that we have fostered and maintained.

In summary, the Company's excellent ESG performance record continued in 2023, and everyone at Challenger Energy is 100% aligned to ensure that this continues into the future.

Outlook

I believe that the outlook for our Company over the coming period is as strong as it has ever been.

In the next 12 months we will be looking to see a result from efforts to realise value from our assets in Trinidad, and, as noted, we hope to reach a resolution in relation to our licences in The Bahamas in the same timeframe. But, undoubtedly, the key area of focus and value creation for Challenger Energy going forward will be Uruguay.

There, we expect the AREA OFF-1 farm-out to be finalised in the coming months, following which we expect that Chevron will begin to rapidly take the project forward. 3D seismic acquisition may happen as soon as the end of 2024, meaning that we could see new data for AREA OFF-1 as soon as the middle of 2025, leading to a decision on exploration well drilling thereafter.

Meanwhile, we will shortly kick off our technical work program for AREA OFF-3, which will see reprocessing of legacy 2D and 3D seismic, as well as a number of other work streams similar to those we found leveraging for the AREA OFF-1 farm-out strategy. We will be looking to replicate our AREA OFF-1 farm-out success for AREA OFF-3, this time with a process we expect will commence in early-to-mid 2025, with a goal to secure a new partner during 2025/early 2026, and exploration well drilling thereafter. And, all of this activity in Uruguay will occur against a backdrop of heightened industry interest, and substantial offshore exploration work being undertaken by others in Uruguay, northern Argentina, and southern Brazil - so it will be a busy and exciting time.

In concluding my review of 2023, I would like to take this opportunity to thank all of our team. We may be a small company, but we have highly-skilled, committed, and fiercely loyal employees, whose hard work and dedication deserves recognition. I also wish to express my deep appreciation for the support we receive from our Board, stakeholders, regulators, suppliers, contractors and shareholders.

2023 was a period of great progress for Challenger Energy. Now, with the benefit of the excellent foundations put in place over the past few years, our task is to realise the value we see in our assets. All of us who work at Challenger Energy are very much looking forward to doing just that.

Eytan Uliel

Chief Executive Officer

26 June 2024

Challenger Energy Overview

Challenger Energy is an Atlantic-margin focused energy company, with a range of offshore and onshore oil and gas assets in the region. The Company's shares are traded on the AIM Market of the London Stock Exchange (AIM: CEG).

The following is a brief summary of key aspect of the Company's assets, operations and business. Additional information is available on the Company's website: www.cegplc.com.

Challenger Energy's Uruguay Assets

Challenger Energy principal area of focus is offshore Uruguay, where the Company has an interest in two blocks: AREA OFF-1 and AREA OFF-3. Together these represent a total licence holding of approximately 27,800 km² (net to Challenger approximately 19,000 km²) - the third largest offshore acreage holding in Uruguay.

FIGURE 1: OFFSHORE LICENCE HOLDERS, URUGUAY

Uruguay is located on the Southern Atlantic coast of South America, bordering Brazil to the north and Argentina to the south and west. The country has the highest per-capita income in South America, and represents an advantaged operating regime, frequently ranking first in Latin America in measures such as democracy, anti-corruption, and ease of doing business. Uruguay is also a leader in providing reliable, sustainable and affordable energy and therefore has a highly supportive policy environment for exploration and production, with an emphasis on promoting responsible development of the nation's energy mix.

Recent conjugate margin discoveries offshore Southwest Africa have renewed interest in the types of plays present offshore Uruguay. The data and enhanced technical understanding provided from recent discoveries offshore Namibia has accelerated the licensing, seismic acquisition, and drilling across the offshore basins of Uruguay, northern Argentina and southern Brazil. In particular, developments in offshore Namibia have provided greater confidence for the potential of a new, prolific petroleum system offshore Uruguay, including Challenger Energy's blocks.

As at the date of this Annual Report, all blocks offshore Uruguay have been licenced, with the final block, AREA OFF-3, having being awarded to Challenger Energy in May 2023. With the exception of the two licences awarded to the Company, all offshore Uruguayan blocks have been awarded to international oil and gas majors / national oil companies. The collective work program of other Uruguay licence holders is estimated to be in excess of $200 million over the next few years. Additionally, adjacent areas in Brazil's Pelotas Basin, proximal to Uruguay, were awarded in December 2023 to supermajors and national oil companies, and licence holders in Argentina have begun undertaking 3D acquisition and deepwater drilling.

AREA OFF-1

The AREA OFF-1 block is a large block covering approximately 14,557 km² and located approximately 100 kms offshore Uruguay in relatively shallow water depth (from 80 to 1,000 meters). Challenger Energy bid for the block in May 2020 - this was the first bid by any company in the new Uruguay Open Round. In June 2020, the Company was awarded the block, with the licence signed post-Covid on 25 May 2022, and the licence's initial four-year exploration period commencing on 25 August 2022.

In late 2022, the Company made a decision to both accelerate and expand the work required to be completed during the first four-year exploration period. As a result, during the course of 2023 all first period minimum work obligations were completed, as well as a considerable body of additional discretionary work. The result of this technical work program was the identification, delineation and high grading of three materials prospects with significant resource potential. These prospects have been named Teru Teru, Anapero and Lenteja, and are summarised as follows:

On 6th of March 2024, following a formal process, the Company announced that it has entered into a farm-out agreement with a subsidiary of Chevron for the AREA OFF-1 block. The key terms of the farm-out agreement are (i) Chevron will acquire a 60% participating interest in AREA OFF-1 and will take over operatorship of the block, (ii) Challenger Energy will retain a 40% non-operating interest in the block, (iii) Challenger Energy will receive US$12.5 million from Chevron as an entry fee, with these funds available to support the further development of the Company's business, (iv) Chevron will carry 100% of Challenger Energy's share of the costs associated with a 3D seismic campaign on AREA OFF-1 block, up to a maximum of US$15 million (net to Challenger Energy), and (v) following the 3D seismic campaign, should Chevron decide to drill an initial exploration well on the AREA OFF-1 block, Chevron will carry 50% of Challenger Energy's share of costs associated with that well, up to a maximum of US$20 million (net to Challenger Energy). As at the date of this Annual Report, formal approval of the farm-in from Uruguayan regulatory authorities is pending, and is expected to be concluded in the coming months, so as to facilitate commencement of a 3D seismic campaign on AREA OFF-1 towards the end of 2024 / early 2025.

AREA OFF-3

The AREA OFF-3 block is a large block covering an area of 13,252 km² and located approximately 75 to 150kms offshore Uruguay in relatively shallow water depths (from 20 to 1,000 meters), prospects in ~200 meters. Challenger Energy bid for the block in May 2023 and was awarded the licence in June 2023. Subsequently, the licence was signed on 7 March 2024, with the initial four-year exploration period commencing on 7 June 2024. Challenger Energy hold a 100% working interest in and is the operator of the block.

There has been considerable prior technical work and seismic acquisition on and adjacent to the area of the AREA OFF-3 block (what is now AREA OFF-3 was previously held by BP until 2016). That prior activity had identified and mapped two primary prospects:

PROSPECT       LOCATION                                                                                                                                  ESTIMATED

P10/P50/P90

AMALIA            Straddles the boundary with Shell's AREA OFF-2, an estimated 30% is contained within AREA OFF-3           EUR (mmbbl) gross

2,189/980/392

MORPHEUS      Entirely contained within AREA OFF-3                                                                                                EUR (TCF) gross

-8.96/2.69/0.84

The AREA OFF-3 licence has a modest work commitment in the initial four-year exploration period, comprising of reprocessing 1,000 kms of legacy 2D seismic data and undertaking two geotechnical studies. There is no drilling obligation in the initial four-year exploration period. However, similar to AREA OFF-1, Challenger Energy's plan during the initial four-year exploration period is to accelerate and expand the technical work program, with a primary objective being to reprocess existing 3D seismic data. This is because the Company considers that the geological prospectivity and petroleum system understanding has changed drastically since the 2022 Namibian discoveries specifically regarding the new Cretaceous petroleum system and seismic identification, and therefore the application of latest 3D reprocessing technology and amplitude analysis will assist to delineate the extent of the previously identified plays and their coverage onto AREA OFF-3. The Company is also planning to pursue an early partnering strategy in the form of a farm-out. As with AREA OFF-1, the objective is to secure cash and a significant carry in an accelerated work program.

Trinidad and Tobago Assets

The Republic of Trinidad and Tobago is a Caribbean nation consisting of the two islands of Trinidad and Tobago, approximately 7 kms offshore from Venezuela. The nation has a long history of oil and gas activity, both onshore on the island of Trinidad, and offshore, with some of the world's oldest hydrocarbon producing fields located in the country.

Challenger Energy holds a 100% interest in, and is the operator of, three producing fields, all onshore Trinidad. Across these fields, there are a total of approximately 250 wells, of which approximately 60 are in production at any given time. Within the fields, regular well workover operations are undertaken on the existing productive well stock, including well stimulation operations, reperforations, reactivations and repairs to shut-in wells, as and when appropriate. Production from the three producing fields - Goudron, Inniss-Trinity and Icacos, averages approximately 275 - 300 bopd.

Other Assets

The Bahamas: Challenger Energy holds four exploration licences offshore The Bahamas. In early 2021, the Perseverance-1 exploration well was drilled in this licence area, but it did not result in a commercial discovery at that location. However, several other structures and drill targets across the licence areas remain prospective, and the technical findings from Perseverance-1 suggest potential in deeper Jurassic horizons. In March 2021, the Group notified the Government of The Bahamas of its intent to renew the licences for a third three-year exploration period. This renewal is still pending. Additionally, the Company is considering various other options for achieving value from these assets.

Suriname: during 2023, the Company relinquished the Weg Naar Zee licence held onshore Suriname, and completed a withdrawal from operations in that country.

People and Operations

The Group's registered office is in the Isle of Man. Additionally, the Group has operational offices in London (United Kingdom), Montevideo (Uruguay), and San Fernando (Trinidad). The business employs approximately 75 staff, with the majority being operational staff in Trinidad. To support its active field operations in Trinidad, the Group owns and operates two workover rigs, one swabbing rig, and various items of heavy field equipment.

The Company's Board, management team, and staff possess a wide range of skills and extensive technical and industry experience - profiles of Board and senior executive members can be found on the Company's website, www.cegplc.com.

The Company takes great pride in its exemplary HSE&S track record and strives to be an employer and partner of choice, and to make a valued contribution to the communities and nations in which it operates.

Environmental, Social & Governance

ESG Philosophy and Management

At Challenger Energy, we believe that pursuing our commercial objectives should never come at the cost of harm to people, communities, or the environment. We acknowledge our responsibility and duty of care to our employees, contractors, suppliers, and the broader communities where we operate. We take every possible step to ensure the health, wellbeing, and safety of everyone involved in our projects, with the goal of achieving zero lost time injuries or incidents.

Challenger Energy is committed to conducting business with integrity and high ethical standards, and fostering a respectful working environment for all employees. We support the personal and professional development of our people and recognise the importance of diversity in our business, including gender, nationality, faith, and personal background. We value how diversity benefits our business and how the unique experiences of our employees contribute to a positive environment within the Group.

Operating in various international locations, we both rely on and impact the people and institutions in these areas. Our business is part of the societies in which we operate, and we are committed to being a responsible business and good corporate citizen, making meaningful and valued contributions to these communities.

We are acutely aware of the natural environments we operate in and strive to minimize our impact. The Group is dedicated to responsible environmental stewardship and aims for zero environmental incidents, spills, or leaks.

Recognising ESG as a core business priority, the Group maintains a structured Health, Safety, Environment & Security (HSES) Management System. This system includes a documented set of policies, procedures, and practices, which are revised and updated regularly, with company-wide application designed to promote and foster excellence in all relevant HSES areas.

Governance

Challenger Energy operates in the energy sector, which is governed by stringent laws and regulations imposed by host Governments and international regulators, and is also subject to intense public scrutiny. Additionally, as the Group's shares are traded on the AIM Market of the London Stock Exchange, it is subject to various additional rules and regulations associated with being a publicly traded entity.

Consequently, the Board is dedicated to upholding the highest standards of corporate governance at all times.

QCA Code

In accordance with the rules of the AIM Market of the London Stock Exchange, the Group is required to apply a recognized corporate governance code and demonstrate its compliance with that code, including any deviations. Since the Group is not obligated to follow the UK Corporate Governance Code, its Directors have chosen to apply the QCA Corporate Governance Code (the "QCA Code") as their standard of measurement.

In accordance with the AIM Rules for Companies, Challenger Energy departs from the QCA Code in relation to Principle 7 - "Evaluate board performance based on clear and relevant objectives, seeking continuous improvement." Challenger Energy's board is small and extremely focused on implementing the Company's strategy. However, given the size and nature of the Company, the Board does not consider it appropriate to have a formal performance evaluation procedure in place, as described and recommended in Principle 7 of the QCA Code. The Board will closely monitor the situation as and when the Company grows.

The Board and its Committees

The Board meets regularly to discuss and review all aspects of the Group's activities. A Board Charter has been approved and adopted, outlining the membership, roles, and responsibilities of the Board. The Board is primarily responsible for formulating, reviewing, and approving the Group's strategy, budgets, major capital expenditures, acquisitions, and divestments. The Board currently consists of the Non-executive Chairman (Iain McKendrick), the Chief Executive Officer (Eytan Uliel), and three Non-executive Directors (Stephen Bizzell, Simon Potter and Robert Bose). Iain McKendrick and Stephen Bizzell are deemed independent by the Board. All Directors have access to the Company Secretary and the Group's professional advisers. Overall, the Board is responsible for the long-term success of the Company and providing leadership to the business including culture, values and ethics and ensuring effective corporate governance and succession planning. The Board operates in an accountable open and transparent environment where the views of all Directors and the actions of Executive Directors can be challenged. The Board is satisfied it has the appropriate balance of skills and experience on the one hand, and, independence and knowledge on the other, to enable it to discharge its respective duties and responsibilities effectively, and that all Directors have adequate time to fill their roles.

Iain McKendrick has over 30 years of industry experience, holding Board positions across several listed companies. He was previously with NEO Energy, was Chief Executive Officer of Ithaca Energy, was Executive Chairman of Iona Energy, and spent several years with Total, including acting as Commercial Manager of Colombia. Iain is the Chairman of the Company's Remuneration and Nomination Committee and a member of the Company's Audit Committee.

Eytan Uliel assumed the position as Chief Executive Officer from 27 May 2021, having previously served as the Company's Commercial Director since 2014. Eytan is a finance executive with significant oil and gas industry experience. He has significant experience in mergers and acquisitions, capital raisings, general corporate advisory work, oil and gas industry-specific experience in public market takeovers and transactions, private treaty acquisitions and farm-in / farm-out transactions. He has held executive roles in various ASX and SGX listed companies. Prior to working with Challenger Energy, from 2009 - 2014 Eytan was Chief Financial Officer and Chief Commercial Officer of Dart Energy Limited, an ASX listed company that had unconventional gas assets (coal bed methane and shale gas) in Australia, Asia and Europe, and Chief Commercial Officer of its predecessor company, Arrow International Ltd, a Singapore based company that had unconventional gas asset primarily in Asia and Australia. He holds a Bachelor of Arts (Political Science) and Bachelor of Laws (LLB) degree from the University of New South Wales, and was admitted as a solicitor in the Supreme Court of New South Wales in 1997. Eytan is a member of the Company's Remuneration Committee, Nomination Committee and the Health, Safety, Environmental and Security Committee.

Simon Potter was previously the Chief Executive Officer of the Company for nearly 10 years and oversaw the safe drilling of the Perseverance-1 well in the Bahamas. Simon assumed the role of a Non-Executive Director in May 2021. Simon qualified as a geologist with an M.Sc. in Management Science, has over 30 years oil and gas industry and mining sector experience. From the Zambian Copperbelt to a 20-year career with BP he has held executive roles in companies managing oil and gas exploration, development and production; gas processing, sales and transport; LNG manufacture, marketing and contracting in Europe, Russia, America, Africa and Australasia. On leaving BP, having helped create TNK-BP, he took up the role of CEO at Hardman Resources where he oversaw growth of the AIM and ASX listed Company into an oil producer and considerable exploration success ahead of executing a corporate sale to Tullow Oil. Simon is a member of the Company's Remuneration Committee, Nomination Committee and the Health, Safety, Environmental and Security Committee.

Stephen Bizzell has over 25 years' corporate finance and public company management experience in the resources sector in Australia and Canada with various public companies. He is the Chairman of boutique corporate advisory and funds management group Bizzell Capital Partners Pty Ltd. He is also the Chairman of ASX listed MAAS Group Holdings Ltd and Savannah Goldfields Ltd, and a Non-executive Director of ASX listed Renascor Resources Limited and Strike Energy Ltd. He was an Executive Director of ASX listed Arrow Energy Ltd from 1999 until its acquisition in 2010 by Shell and PetroChina for A$3.5 billion. He was instrumental in Arrow's corporate and commercial success and its growth from a junior explorer to a large integrated energy company. He was also a founding director of Bow Energy Ltd until it's A$550 million takeover and was also a founding director of Stanmore Resources Ltd. Stephen qualified as a Chartered Accountant and early in his career was employed in the Corporate Finance division of Ernst & Young and the Corporate Tax division of Coopers & Lybrand. Stephen is also the Chairman of Challenger Energy Audit Committee.

Robert Bose is the Managing Member of Charlestown Energy Partners, a private investment company associated with a New York-based family office that has been making investments globally in the upstream business since 2016. Robert is also the Chief Executive Officer and a member of the Board of Directors of Sintana Energy, Inc., a Toronto Venture listed oil and gas exploration with a portfolio of licenses in Namibia. Robert is also a non-executive director of New Zealand Energy, Corp., a company providing gas, gas storage and liquids solutions to support the domestic energy economy and is also on the Board of Managers of Black Bayou Energy Hub, a private company developing a gas storage opportunity on the Gulf Coast of the U.S. Prior to joining Charlestown, Robert spent 17 years in the Investment Banking Group at Scotiabank, latterly as Managing Director and Industry Head, Global Power & Utilities. Effective 1 July 2024, Robert will replace Iain McKendrick as the member of the Company's Audit Committee.

Audit Committee

The Audit Committee of the Board consists of Stephen Bizzell (Chair) and Iain McKendrick, with input from the Chief Financial Officer as needed. The Audit Committee is primarily responsible for ensuring the Group's financial performance is accurately reported and monitored, reviewing the scope and results of the audit, evaluating its cost-effectiveness, and maintaining the independence and objectivity of the auditor. Additionally, the Audit Committee oversees public reporting and the Group's internal controls. A Charter of the Audit Committee, which defines its membership, roles, and responsibilities, has been approved and adopted. All members of the Audit Committee have access to the Company Secretary and the Group's professional advisers, including direct access to the Group's auditor. The Audit Committee meets regularly and convened twice in 2023, with all members present at both meetings. Effective 1 July 2024, Robert Bose will replace Iain McKendrick on the Audit Committee.

Renumeration & Nomination Committee

The Remuneration & Nomination Committee consists of Simon Potter (Chair), Iain McKendrick, and Eytan Uliel. This committee is responsible for recommending executive remuneration packages, including bonus awards and share options, to the Board of Directors. It also assists the Board in identifying and evaluating potential new Directors, ensuring that the size, composition, and performance of the Board are suitable for the Group's and Company's activities. Shareholders of the Group ultimately have the responsibility for determining Board representation. The Remuneration & Nomination Committee meets as needed and convened once in 2023, with all members present.

Health, Safety, Environmental and Security Committee

The Board has a Health, Safety, Environmental, and Security (HSES) Committee, currently comprising Iain McKendrick (Chair), Simon Potter, and Eytan Uliel. The Committee's purpose is to assist the Directors in establishing ESG strategy, reviewing, reporting, and managing the Group's performance, assessing compliance with applicable regulations, internal policies, and goals, and contributing to the Group's risk management processes. The HSES Working Group reports to the HSES Committee, which meets regularly. In 2023, the HSES Committee met four times, with all members present at each meeting.

Record of the board meetings

There were 3 formal meetings of the board of the parent entity in the period 1 January 2023 to 31 December 2023. In addition,

there were a number of other ad-hoc gatherings of the Board through the period.

Internal Control

The Directors acknowledge their responsibility for the Group's system of internal control and for reviewing its effectiveness.

The system of internal control is designed to manage the risk of failure to achieve the Group's strategic objectives. It cannot totally

eliminate the risk of failure but will provide reasonable, although not absolute, assurance against material misstatement or loss.

Going Concern

These financial statements have been prepared on a going concern basis, which assumes that the Group will continue in

operation for the foreseeable future.

The Group has incurred an operating loss of $19.9 million for the financial year ended 31 December 2023 (2022: loss of $4.2 million) and the Group's current liabilities exceeded current assets by approximately $2.9 million as of 31 December 2023 (2022: $2.0 million), however this includes approximately $4.1m in respect of taxes and penalties owed in Trinidad and Tobago that the Group expects to settle by way of offset against future tax refunds or are derived from notional estimates of tax penalties dating back to 2021 that the Group does not expect will be levied or assessed with final resolution still pending with the local tax authorities (refer to note 18 for further details). At 31 December 2023, the Group had approximately $1.0 million (2022: $2.5 million) in unrestricted cash funding and at the date of authorisation of these financial statements, the Group continues to have approximately $1.5 million in unrestricted cash funding.

On 6 March 2024, the Group entered into a farm-out agreement with Chevron, a leading global energy super-major, in relation to the Group's AREA OFF-1 licence offshore Uruguay pursuant to which the Group will receive $12.5 million upfront payment at completion along with Chevron carrying the Group's share of certain future work programme costs (the "Farm-out"). The Farm-out is subject to Uruguayan regulatory approval. Management is highly confident that the requisite regulatory approvals will be forthcoming in the near-term, as Chevron meets all requirements to operate an energy project in Uruguay, and the submissions for regulatory approvals were made in consultation with ANCAP, the Uruguayan regulatory body. In addition, the Group expects $0.3 million of presently restricted cash (in support of AREA OFF-1 performance bond) to become unrestricted shortly after the Farm-out completion.

On 18 April 2024 the Group announced that it had entered into a legally binding term sheet for an investment by Charlestown Energy Partners LLC, whereby Charlestown will invest £1.5 million in the Group, initially in the form of a loan, This investment was completed on 28 May 2024 and provides the Group with finance in the medium term until the completion of the farm-out agreement with Chevron, and, on completion of the farm-out, the Charlestown investment will convert into a shareholding of approximately 8.7% in the Company.

The Directors have thus prepared these financial statements on a going concern basis, as based on the Group's cash flow forecasts (which include the proceeds from Charlestown investment and the Farm-out described above), the Group expects to have adequate financial resources to support its operations for the next 12 months (and well into the foreseeable future beyond that). In addition, the Directors note that the Company is a publicly listed company on a recognised stock exchange, thus affording the Company the ability to raise capital equity, debt and/or hybrid financing alternatives as and when the need arises. The Company has a robust track record in this regard, having raised in excess of US$100 million in equity and alternative financing in the recent past.

Anti-bribery and Corruption ('ABC')

Challenger Energy enforces a zero-tolerance policy for bribery, corruption, or unethical conduct in our business. Our policies mandate compliance with applicable anti-bribery and corruption (ABC) laws, particularly the UK Bribery Act 2010, as well as all relevant laws in the jurisdictions where we operate. We have implemented a documented system of ABC policies and procedures that provide a consistent framework across The Group, ensuring our employees are aware of potential threats and maintaining appropriate governance of ABC matters. In 2023, all employees were required to attend mandatory ABC training, focusing on the most relevant legislation for the Group.

Anti-Money Laundering ('AML')

Challenger is acutely aware of the risks posed by money laundering and terrorist financing. These criminal activities not only threaten society but also impact The Group, its partners, shareholders, and staff. The Group exercises the highest level of vigilance in all its operations to combat these threats. This vigilance also applies to third-party associates involved with The Group. Annual AML training is mandatory for all Group staff, and in 2023, various employees and contractors participated in money laundering training courses.

Taxation

 Depending on the jurisdiction of operation, The Group is subject to various taxes, including corporate income tax, supplemental petroleum taxes, royalties, other fiscal deductions, VAT, and payroll taxes. As a responsible operator and corporate citizen, The Group is committed to complying with all relevant tax laws in every jurisdiction where we operate. Adhering to tax laws and regulations is fundamental to our license to operate, and we take this obligation seriously.

​

​

Risk Management

Understanding our principal risks and ensuring that Challenger Energy has the appropriate controls in place to manage those risks is critical to our business operations. Managing business risks and opportunities is a key consideration in determining and then delivering against the Group's strategy. The Group's approach to risk management is not intended to eliminate risk entirely, but provides the means to identify, prioritise and manage risks and opportunities. This, in turn, enables the Group to effectively deliver on its strategic objectives in line with its appetite for risk.

The Board's Responsibility for Risk Management

The board has overall responsibility for ensuring the Group's risk management and internal control frameworks are appropriate and are embedded at all levels throughout the organisation. Principal risks are reviewed by the board and are specifically discussed in relation to setting the Group strategy, developing the business plan to deliver that strategy and agreeing annual work programmes and budgets. See "Principal Risks and Uncertainties" section below and the mitigation steps taken to minimise these risks.

Principal risks and uncertainties

The principal risks facing the Group together with a description of the potential impacts, mitigation measures and the appetite for the risk are presented below. The analysis includes an assessment of the potential likelihood of the risks occurring and their potential impact. Identified risks are segregated between those that we can influence and those which are outside our control. Where we can influence risks, we have more control over outcomes. Where risks are external to the business, we focus on how we control the consequences of those risks materialising.

RISKS THAT WE CAN INFLUENCE

1.      Health, safety and environment (HSE)

Oil and gas exploration, development and production activities can be complex and are physical in nature. HSE risks cover many

areas including major accidents, personal health and safety, compliance with regulations and potential environmental harm.

Potential impact: High            Probability: Low

Risk Appetite

The Group has a very low appetite for risks associated with HSE and strives to achieve a zero-incident rate.

Mitigation

The Group strives to ensure the safety of its employees, contractors and visitors. We are very conscious of the natural

environment that we operate in and seek to minimise our environmental impact and footprint.

2.      Exploration, development and production

The ultimate success of the Group is based on its ability to maintain and grow production from existing assets and to create value

through exploration activity across the existing portfolio together with selective acquisition activity to grow the asset portfolio.

Potential impact: High            Probability: Moderate

Risk appetite

The Group's current production is derived from later-life production assets that are in the latter portion of the production decline curve. The development of later life assets can be complex and technically challenging. This can expose the Group to higher levels of risk, particularly in stimulating existing wells through workover or enhanced oil recovery techniques which may, due to their nature, not be successful or may compromise existing production. Identifying locations for optimal locations new infill wells that do not interfere with existing production can be challenging.

The Group has some tolerance for this risk and acknowledges the need to have effective controls in place in this area.

Mitigation

The production team responsible for operating the Group's assets is very experienced in the industry and in the management, workover and enhancement of the Group's assets. In addition, the Group has built a trusted network of service providers who are similarly familiar with the assets and who support production enhancing activity including targeted recompletions and other well interventions to further extend the productive life of the Group's well stock.

3.      Reserves and resources

The estimation of oil and gas reserves and resources involves a high level of subjective judgment based on available geological, technical and economic information.

Potential impact: Medium Probability: Low

Risk appetite

The Group has a strong focus on subsurface analysis. We employ industry technical specialists and qualified reservoir engineers and geologists who work closely with our operational teams who are responsible for delivering asset performance.

The Group tolerates some risk related to the estimation of reserves and resources.

Mitigation

Reserve and resource volumes are assessed periodically using the Petroleum Resource Management System (PRMS) developed by the Society of Petroleum Engineers. An external assessment of reserve volumes may also be undertaken periodically by an independent petroleum engineering firm. CEG has staff and consultants who are qualified reservoir engineer with significant international experience.

4.      Portfolio concentration

The Group's producing assets are concentrated in Trinidad and are principally characterised as later-life assets. This concentrates production risk in a single jurisdiction and in an asset group with a particular age and production profile

Potential impact: Medium Probability: High

Risk appetite

The principal location of the Group's producing assets and their age profile places emphasis on the Group's ability to successfully

maintain existing production in Trinidad. The Group has a moderate appetite for this risk.

Mitigation

The Group is continuously seeking to selectively add new development or production onshore Trinidad or elsewhere in the Atlantic margin through new licence applications, M&A activity or partnering arrangements with service providers.

Progressing exploration and eventual development of Uruguay, if successful, will similarly mitigate this risk over time.

5.      Financing

Oil and gas exploration, development and production activity are capital intensive. The Group currently generates modest levels of cash from operations and relies on investment capital to enhance the asset base and, in turn, production and consequential cash generation.

Potential impact: High             Probability: Moderate

Risk appetite

The Group has a low appetite for financing risk. The inability to fund financial commitments, including licence obligations, could significantly delay the development of the Group's assets and consequent value creation. Financial or operational commitments are often a pre-condition to the grant of a licence. The Group's inability to satisfy these could result in financial penalty and/or termination of licences.

Mitigation

The Group has a strong track record over many years of successfully raising finance to fund its activities as and when required.

6.      Bribery and corruption

There is a risk that third parties or staff could be encouraged to become involved in corrupt or questionable practices. Transparency International's rankings (out of 180 countries) and respective scores (out of a maximum of 100 points) on their 2022 Corruption Perceptions Index for the jurisdictions where the Group has presence are as below:

Risk appetite

The Group has a zero-tolerance policy regarding bribery and corruption.

Mitigation

The Group, its board and management have an established anti-bribery and corruption (ABC) policy that requires all new hires to confirm that they have read and understood the contents and personal requirements of the policy. The Group ensures that our third-party contractors and advisers follow our procedures and policies related to ABC. Annual ABC training and briefings are carried out.

RISKS BEYOND OUR INFLUENCE

7.      Commodity prices

The Group is exposed to commodity price risk in relation to sales of crude oil.

Potential impact: High          Probability: Moderate

Risk appetite

The Group has a moderate appetite for commodity price risk. A material decline in oil prices could adversely affect the Group's profitability, cash flow, financial position, and ability to invest.

Mitigation

All the Group's production in Trinidad is sold to Heritage under the terms of the respective production licences and the Group is fully exposed to adverse commodity price fluctuation (and also conversely benefits from favourable commodity price movement).

The Group does not currently use hedging instruments to mitigate oil price risk as the volumes are relatively small and significant volatility observed in crude prices in the recent years coupled with oil futures curve backwardation make it difficult to assess effectiveness of a hedge. The Group monitors the oil and gas benchmark prices, principally WTI and Brent Crude, and may consider enter hedging arrangements if market conditions and financial and risk analysis suggest that price risk is lowered by doing so.

8.      Demand/ limited sales routes

All the Group's current production is derived from its Trinidad assets and sold to a single customer, Heritage Petroleum Company Limited, the state-owned oil and gas company.

Potential impact: High          Probability: Low

Risk appetite

Demand can be negatively affected by economic conditions in Trinidad and globally. The Group accepts demand risk related to its crude oil production.

Mitigation

All the Group's production is sold to Heritage as required under the terms of the licence agreements with Heritage. There is no history of Heritage refusing delivery of crude produced by the Group. The Group accepts this potential risk.

9.      Fiscal and political

The Group's operations are located in Uruguay and Trinidad and Tobago, with legacy assets in The Bahamas, and the Group is therefore exposed to both in-country fiscal and political risk.

Potential impact: High          Probability: Moderate

Appetite

The Group accepts a modest amount of fiscal risk. The Group is exposed to currency risk resulting from fluctuations between currencies in various jurisdictions of operation, and in particular between the US Dollar (in which most expenses are denominated) and the Pound Sterling (as a significant amount of the Group's cash holdings are denominated in Pound Sterling). Currency hedging instruments are not used.

Mitigation

The Group closely monitors fiscal and political situation in the jurisdictions it operates in with a view to identifying and minimising the downside risk presented by changes in fiscal and political circumstances. While the Group has not hedged its currency exposure in the past, the Group closely monitors currency fluctuations with a view to assessing potential downside risk vis-à-vis foreign currency requirements (and the timing thereof) so as to determine the efficacy of a potential hedge. The Group monitors political risk and political developments of the countries of its operations and considers the structure and operation of the respective governments in each of the jurisdictions of its operations to present low risk to the Group. Further, the Group interacts with relevant Governments, Government Ministries and Agencies, and the state-owned oil and gas companies in the jurisdictions in which it operates. The Group has no exposure to Russian oil production, and recently enacted sanctions have had no impact on the Group's business or operations.

Directors' Report

The Company's Directors present their report and audited financial statements of the Company and the consolidated group consisting of Challenger Energy Group PLC ("Challenger Energy" or "the Company") and the entities it controlled (the "Group") at the end of, or during, the financial year ended 31 December 2023.

Directors

The following persons were Directors of the Company during the financial year under review:

Iain McKendrick
Eytan Uliel

Simon Potter
Stephen Bizzell

On 28 May 2024 the Group announced that Mr Robert Bose joined the Board following the completion of the investment in the Company by Charlestown Energy Partners LLC.

Principal Activity

The principal activity of the Group and the Company consists of oil & gas exploration, appraisal, development and production, in Uruguay, Trinidad and Tobago and The Bahamas.

Results and dividends

The results of the Group for the year are set out on page 25 and show a loss for the year ended 31 December 2023 of $13,421,000 (2022: profit of $4,382,000). The total comprehensive loss for the year of $10,986,000 (2022: loss of $1,360,000) has been transferred to the retained deficit. The results include an impairment charge of intangible and tangible assets in Trinidad and Suriname totaling $12,957,000 (2022: $2,201,000) which includes a full write down of goodwill of $4,610,000 (2022: nil).

The Directors do not recommend payment of a dividend (2022: nil).

Significant Shareholders

The following tables represent shareholdings of 3% or more notified to the Company at 31 December 2023: Top shareholders (by parent company)

Directors' Shareholding and Options

The interests in the Company at balance sheet date of all Directors who hold or held office on the Board of the Company at the year-end and subsequent to year end are stated below.

On 28 May 2024 the Group announced that Mr Robert Bose joined the Board following the completion of an investment in the Company by Charlestown Energy Partners [[C.

Record of Board Meetings

There were 3 board meetings of the parent entity of the Group during the financial year.

In addition to the Board Meetings, there were a number of informal gatherings of the Board to discuss various items during the period.

Statement of Directors' Responsibilities in

respect of the financial statements

The Directors are responsible for preparing the Annual Report and the Financial Statements in accordance with applicable Isle of Man law and regulation.

Company law requires the Directors to prepare financial statements for each financial year. The Directors have elected to prepare the Group and Company financial statements in accordance with International Financial Reporting Standards ("IFRSs").

The financial statements are required by law to give a true and fair view of the state of affairs of the Group and the Company and of the profit or loss of the Group for that period.

In preparing the financial statements, the Directors are required to:

·        select suitable accounting policies and then apply them consistently;

·        state whether IFRSs have been followed, subject to any material departures disclosed and explained in the financial statements;

·        make judgements and accounting estimates that are reasonable and prudent; and

·        prepare the financial statements on the going concern basis unless it is inappropriate to presume that the Group and the Company will continue in business.

The Directors are responsible for keeping proper accounting records that are sufficient to show and explain the Group and Company's transactions and disclose with reasonable accuracy at any time the financial position of the Group and the Company and to enable them to ensure that the financial statements comply with the Isle of Man Companies Acts 1931 to 2004. 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. The Directors are responsible for the maintenance and integrity of the Company's website. Legislation in the Isle of Man governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

On behalf of the Board

Eytan Uliel

Director

26 June 2024

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Independent auditor's report to the members of Challenger Energy Group PLC

Opinion

We have audited the financial statements of Challenger Energy Group PLC (the "Company") and its subsidiaries (the "Group"), which comprise the Consolidated Statement of Comprehensive Income, Consolidated and Company Statements of Financial Position, Consolidated and Company Statements of Cash Flows and Consolidated and Company Statements of Changes in Equity for the year ended 31 December 2023, and the related notes to the financial statements, including a summary of material accounting policies.

The financial reporting framework that has been applied in the preparation of the financial statements is applicable law and International Financial Reporting Standards (IFRS).

In our opinion, Challenger Energy Group PLC's consolidated and company financial statements:

·        give a true and fair view in accordance with IFRS of the assets, liabilities and financial position of the Group and Company as at 31 December 2023, and of the Group's financial performance and the Group and Company cash flows for the year then ended; and

·        have been properly prepared in accordance with the requirements of the Isle of Man Companies Acts of 1931 to 2004.

Basis for opinion

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 'Responsibilities of the auditor for the audit of the financial statements' section of our report. We are independent of the Group and Company in accordance with the ethical requirements that are relevant to our audit of the financial statements in the Isle of Man, including the FRC's Ethical Standard and the ethical pronouncements established by Chartered Accountants Ireland, applied as determined to be appropriate in the circumstances for the entity. 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 opinion.

Conclusions relating to going concern

In auditing the financial statements, we have concluded that the directors' use of going concern basis of accounting in the preparation of the financial statements is appropriate. Our evaluation of the validity of the directors' assessment of the Group and Company's ability to continue to adopt the going concern basis of accounting included:

·        verifying the mathematical accuracy of management's cash flow forecast and agreeing the opening cash position;

·        assessing management's underlying cash flow projections for the Group for the period to December 2025 and evaluating and challenging the assumptions including production, prices and operating expenditure. In doing so we compared production forecasts to historical trends and considered the price assumptions against consensus market prices and historical prices. We compared forecast costs with historical expenditure and to other external and internal sources, including the impairment assessments, where appropriate;

·        assessing and validating the impact of post year end cash inflow sources including the proceeds from capital raising and farm-out payment related to a 60% interest in the Area Off-1 block;

·        assessing management's ability to take mitigating actions, if required; and

·        assessing the completeness and appropriateness of management's going concern disclosures in the financial statements.

Based on the work we have performed, we have not identified any material uncertainties relating to events or conditions that, individually or collectively, may cast significant doubt on the Group and Company's ability to continue as a going concern for a period of at least twelve months from the date when the financial statements are authorised for issue.

We have nothing material to add or draw attention to in relation to the directors' statement in the financial statements about whether the directors considered it appropriate to adopt the going concern basis of accounting in preparing the financial statements.

Our responsibilities and the responsibilities of the directors with respect to going concern are described in the relevant sections of this report.

Key audit matters

Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial statements of the current financial 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 the directing of 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 therefore we do not provide a separate opinion on these matters.

Overall audit strategy

We designed our audit by determining materiality and assessing the risks of material misstatement in the financial statements. In particular, we looked at where the directors made subjective judgements, for example, in respect of significant accounting estimates that involved making assumptions and considering future events that are inherently uncertain. We also addressed the risk of management override of internal controls, including evaluating whether there was any evidence of potential bias that could result in a risk of material misstatement due to fraud.

Based on our considerations as set out below, our areas of focus included:

·     Valuation of the Group's intangible exploration and evaluation assets;

·     Going concern; and

·     Valuation of the Group's tangible oil and gas assets.

How we tailored the audit scope

Challenger Energy Group Plc is the holders of several oil & gas exploration and production licences located in Uruguay, Trinidad &

Tobago and The Bahamas.

Our Group audit was scoped by obtaining an understanding of the Group and its environment, including the Group's system of internal control and assessing the risks of material misstatement in the financial statements. We also addressed the risk of management override of internal controls, including assessing whether there was evidence of bias by the directors that may have represented a risk of material misstatement.

We performed an audit of the complete financial information of four components, audit of one or more classes of transactions of two components which includes the assessment of impairment of intangible exploration and evaluation assets and performed audit procedures on specific balances for a further four components. The remaining components of the Group were considered non-significant and these components were subject to analytical review procedures.

Components represent business units across the Group considered for audit scoping purposes.

Materiality and audit approach

The scope of our audit is influenced by our application of materiality. We set certain quantitative thresholds for materiality. These, together with qualitative considerations, such as our understanding of the entity and its environment, the history of misstatements, the complexity of the Group and the reliability of the control environment, helped us to determine the scope of our audit and the nature, timing and extent of our audit procedures and to evaluate the effect of misstatements, both individually and on the financial statements as a whole.

Based on our professional judgement, we determined materiality for the Group and Company at 0.75% of total assets at 31 December 2023. We have applied this benchmark because the main objective of the Group is to utilise its existing oil and gas assets and exploration and evaluation assets to provide investors with returns on their investments.

We have set performance materiality for the Group and Company at 65% of materiality, having considered business risks and fraud risks associated with the entity and its control environment. This is to reduce to an appropriately low level the probability that the aggregate of uncorrected and undetected misstatements in the financial statements exceeds materiality for the financial statements as a whole.

We agreed with the audit committee and directors that we would report to them misstatements identified during our audit above 2.5% of Group materiality and 3% of Company materiality, as well as misstatements below that amount that, in our view, warranted reporting for qualitative reasons.

Significant matters identified

The risks of material misstatement that had the greatest effect on our audit, including the allocation of our resources and effort, are set out below as significant matters together with an explanation of how we tailored our audit to address these specific areas in order to provide an opinion on the financial statements as a whole. This is not a complete list of all risks identified by our audit.

We completed our planned audit procedures, with no exceptions noted.

Other information

Other information comprises information included in the annual report, other than the financial statements and our auditor's report thereon, including the Chief Executive Officer's Report to the Shareholders and Directors' Report. The directors are responsible for the other information. Our opinion on the 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.

In connection with our audit of the financial statements, 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 audit, or otherwise appears to be materially misstated. If we identify such material inconsistencies in the financial statements, we are required to determine whether there is a material misstatement in the financial statements or a material misstatement of the other information. 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.

We have nothing to report in this regard.

Matters on which we are required to report by exception

We have nothing to report in respect of the following matters where the Companies Acts 1931 to 2004 require us to report to you if, in our opinion:

·      the Group and Company has not kept proper books of account, or if proper returns adequate for our audit have not been received from branches not visited by us; or

·      the financial statements are not in agreement with the books of account and returns; or

·      the financial statements do not contain particulars as to loans to, and remuneration of, Directors; or

·      we have not received all the information and explanations which are necessary for the purposes of our audit.

Responsibilities of management and those charged with governance for the financial statements

As explained more fully in the Statement of Directors' Responsibilities, management is responsible for the preparation of the financial statements which give a true and fair view in accordance with IFRS, and for such internal control as directors determine necessary to enable the preparation of financial statements are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, management is responsible for assessing the Group and 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 management either intends to liquidate the Group or Company or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Group and Company's financial reporting process.

Responsibilities of the auditor for the audit of the financial statements

The objectives of an auditor 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 their 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.

A further description of an auditor's responsibilities for the audit of the financial statements is located on the Financial Reporting Council's website at: www.frc.org.uk/auditorsresponsibilities. This description forms part of our auditor's report.

Explanation as to what extent the audit was considered capable of detecting irregularities, including fraud

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. Owing to the inherent limitations of an audit, there is an unavoidable risk that material misstatement in the financial statements may not be detected, even though the audit is properly planned and performed in accordance with the ISAs (UK). The extent to which our procedures are capable of detecting irregularities, including fraud is detailed below.

Based on our understanding of the Group and industry, we identified that the principal risks of non-compliance with laws and regulations related to compliance with AIM Listing Rules, Data Privacy law, Employment Law, Environmental Regulations, Health & Safety, and we considered the extent to which non-compliance might have a material effect on the financial statements. We also considered those laws and regulations that have a direct impact on the preparation of the financial statements such as the local law, Isle of Man Companies Act 1931 to 2004 and local tax legislations. The Audit engagement partner considered the experience and expertise of the engagement team to ensure that the team had appropriate competence and capabilities to identify or recognise non-compliance with the laws and regulation. We evaluated management's incentives and opportunities for fraudulent manipulation of the financial statements (including the risk of override of controls), and determined that the principal risks were related to posting inappropriate journal entries to manipulate financial performance and management bias through judgements and assumptions in significant accounting estimates, in particular in relation to significant one-off or unusual transactions. We apply professional scepticism through the audit to consider potential deliberate omission or concealment of significant transactions, or incomplete/inaccurate disclosures in the financial statement.

The group engagement team shared the risk assessment with the component auditors so that they could include appropriate audit procedures in response to such risks in their work.

In response to these principal risks, our audit procedures included but were not limited to:

·     enquiries of management, board and audit committee on the policies and procedures in place regarding compliance with laws and regulations, including consideration of known or suspected instances of non-compliance and whether they have knowledge of any actual, suspected or alleged fraud;

·     inspection of the Group and Company's regulatory and legal correspondence and review of minutes of board and audit committee meetings during the year to corroborate inquiries made;

·     gaining an understanding of the entity's current activities, the scope of authorisation and the effectiveness of its control environment to mitigate risks related to fraud;

·     discussion amongst the engagement team in relation to the identified laws and regulations and regarding the risk of fraud, and remaining alert to any indications of non-compliance or opportunities for fraudulent manipulation of financial statements throughout the audit;

·     identifying and testing journal entries to address the risk of inappropriate journals and management override of controls;

·     designing audit procedures to incorporate unpredictability around the nature, timing or extent of our testing;

·     challenging assumptions and judgements made by management in their significant accounting estimates, including impairment assessment of intangible exploration and evaluation assets, tangible oil and gas assets, investment in subsidiaries and amounts owed by subsidiary undertakings;

·     review of the financial statement disclosures to underlying supporting documentation and inquiries of management; and

·     requesting information from component auditors on instances of non-compliance with laws or regulations that could give rise to a material misstatement of the group financial statements.

The primary responsibility for the prevention and detection of irregularities including fraud rests with those charged with governance and management. As with any audit, there remains a risk of non-detection or irregularities, as these may involve collusion, forgery, intentional omissions, misrepresentations or override of internal controls.

The purpose of our audit work and to whom we owe our responsibilities

This report is made solely to the company's members, as a body, in accordance with Section 15 of the Companies Act 1982. 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.

Grant Thornton

Chartered Accountants & Statutory Auditors

13-18 City Quay

Dublin 2

Ireland

Consolidated Statement of Comprehensive

Income

For the year ended 31 December 2023

The accompanying accounting policies and notes form an integral part of these financial statements. Refer to note 28 for the Company's comprehensive income/(expense) for the year.

Consolidated Statement of Financial Position

At 31 December 2023

The accompanying accounting policies and notes form an integral part of these financial statements. Refer to note 28 for the Company's comprehensive income/(expense) for the year.

These financial statements were approved and authorised for issue by the Board of Directors on 26 June 2024 and signed on its behalf by:

Eytan Uliel                           Iain McKendrick

Director                                             Director

Company Statement of Financial Position

At 31 December 2023

The accompanying accounting policies and notes form an integral part of these financial statements.

These financial statements were approved and authorised for issue by the Board of Directors on 26 June 2024 and signed on its behalf by:

Eytan Uliel                           Iain McKendrick

Director                                             Director

Consolidated Statement of Cash Flows

For the year ended 31 December 2023

Company Statement of Cash Flows

For the year ended 31 December 2023

Statement of Changes in Equity - the Company

For the year ended 31 December 2023

Notes to the financial statements for the year

ended 31 December 2023

1      Summary of material accounting policies

1.01 General information and authorisation of financial statements

Challenger Energy Group PLC (the "Company") and its subsidiaries (together, the "Group") is the holders of several oil & gas

exploration and production licences located in Uruguay, Trinidad & Tobago and The Bahamas.

The Company is a limited liability company incorporated and domiciled in the Isle of Man. The address of its registered office is The Engine House, Alexandra Road, Castletown, Isle of Man IM9 1TG. The Company's review of operations and principal activities is set out in the Directors' Report. See note 13 to the financial statements for details of the Company's principal subsidiaries.

The accounting reference date of the Company is 31 December.

1.02 Statement of compliance with IFRS

The Group's financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS). The Company's financial statements have been prepared in accordance with IFRS and as applied in accordance with the provisions of the Isle of Man Companies Acts 1931 to 2004. As permitted by part 1 Section 3(5) of the Isle of Man Companies Act 1982, the Company has elected not to present its own Statement of Comprehensive Income for the year. The principle accounting policies adopted by the Group and Company are set out below.

New standards, interpretations and amendments adopted without an impact on the Group's consolidated financial statements

Amendments to IAS 1 Presentation of Financial Statements and IFRS Practice Statement 2: Disclosure of Accounting policies require the disclosures of material accounting policies rather than significant accounting policies.

Amendments to IAS 8 Accounting policies, Changes in Accounting Estimates and Errors: Definition of Accounting Estimates replace the definition of change in accounting estimates with the definition of accounting estimates as monetary amounts subject to measurement uncertainty following accounting policies requirements.

Amendments to IAS 12 Income Taxes: Deferred Tax related to Assets and Liabilities arising from a Single Transaction clarify that the recognition exemption in paragraphs 15 and 24 of IAS 12 does not apply to transactions that, on initial recognition, give rise to equal taxable and deductible temporary differences.

Amendments to IAS 12 International Tax Reform - Pillar Two Model Rules introduce disclosure requirements related to pillar two income taxes. The Group is not in scope of the Pillar Two model rules as its revenue is less than 750 million Euros per year.

New and revised standards and interpretations not applied

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2023 reporting period and have not been early adopted by the Group and the Company. These standards are not expected to have a material impact on the Group and the Company in the current or future reporting periods and on foreseeable future transactions.

1.03 Basis of preparation

The financial statements have been prepared on the historical cost basis, except for the measurement of certain assets and

financial instruments at fair value as described in the accounting policies below.

The financial statements have been prepared on a going concern basis, refer to note 1.29 for more details.

The financial statements are presented in United States Dollars ($) and all values are rounded to the nearest thousand dollars ($'000) unless otherwise stated.

1.04 Basis of consolidation

The financial statements incorporate the results of the Company and its subsidiaries (collectively, the "Group") using the acquisition method. Control is achieved where the Company has power over the investee, is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity.

The Group re-assesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control. Consolidation of a subsidiary begins when the Group obtains control over the subsidiary and ceases when the Group loses control of the subsidiary. Assets, liabilities, income and expenses of a subsidiary acquired or disposed of during the year are included in the consolidated financial statements from the date the Group gains control until the date the Group ceases to control the subsidiary. If the Group loses control over a subsidiary, it derecognises the related assets (including goodwill), liabilities, non-controlling interest and other components of equity, while any resultant gain or loss is recognised in profit or loss.

Inter-company transactions and balances between Group companies are eliminated in full.

Where necessary, adjustments are made to the financial statements of subsidiaries to bring the accounting policies used in line with those used by the Group.

1.05 Business combinations

On the acquisition of a subsidiary, the business combination is accounted for using the acquisition method. In the consolidated statement of financial position, the acquiree's identifiable assets and liabilities are initially recognised at their fair values at the acquisition date. The cost of an acquisition is measured as the fair value of aggregated amount of the consideration transferred, measured at the date of acquisition. The consideration paid is allocated to the assets acquired and liabilities assumed on the basis of fair values at the date of acquisition. Acquisition costs not directly related to the issuance of shares in consideration are expensed when incurred and included in administrative expenses. Acquisition costs which are directly related to the issuance of shares in consideration are deducted from share premium. The results of acquired operations are included in the consolidated statement of comprehensive income from the date on which control is obtained.

If the cost of acquisition exceeds the fair value of the identifiable net assets attributable to the Group, the difference is considered as purchased goodwill, which is not amortised but annually reviewed for impairment. In the case that the identifiable net assets attributable to the Group exceed the cost of acquisition, the difference is recognised in profit or loss as a gain on bargain purchase.

If the initial accounting for a business combination cannot be completed by the end of the reporting period in which the combination occurs, only provisional amounts are reported, which can be adjusted during the measurement period of up to 12 months after acquisition date.

After initial recognition, goodwill is measured at cost less any accumulated impairment losses.

1.06 Intangible assets - exploration and evaluation assets

Exploration and evaluation expenditure incurred which relates to more than one area of interest is allocated across the various areas of interest to which it relates on a proportionate basis. Exploration and evaluation expenditure incurred by or on behalf of the Group is accumulated separately for each area of interest. The area of interest adopted by the Group is defined as a petroleum title.

Expenditure in the area of interest comprises direct costs and an appropriate portion of related overhead expenditure but does not include general overheads or administrative expenditure not linked to a particular area of interest.

As permitted under IFRS 6, exploration and evaluation expenditure for each area of interest, other than that acquired from the purchase of another entity, is carried forward as an asset at cost provided that one of the following conditions is met:

·        the costs are expected to be recouped through successful development and exploitation of the area of interest, or alternatively by its sale; or

·        exploration and/or evaluation activities in the area of interest have not, at the reporting date, reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves, and active and significant operations in, or in relation to, the area of interest are continuing.

Such costs are initially capitalised as intangible assets and include payments to acquire the legal right to explore, together with the directly related costs of technical services and studies, seismic acquisition, exploratory drilling and testing. Exploration and evaluation expenditure which fails to meet at least one of the conditions outlined above is taken to the consolidated statement of comprehensive income.

Expenditure is not capitalised in respect of any area of interest unless the Group's right of tenure to that area of interest is current.

Intangible exploration and evaluation assets in relation to each area of interest are not amortised until the existence (or otherwise) of commercial reserves in the area of interest has been determined.

Exploration and evaluation assets are assessed for impairment when facts and circumstances suggest that the carrying amount may exceed its recoverable amount. In accordance with IFRS 6, the Group reviews and tests for impairment on an ongoing basis and specifically if the following occurs:

a)      the period for which the Group has a right to explore in the specific area has expired during the period or will expire in the near future, and is not expected to be renewed;

b)      substantive expenditure on further exploration for and evaluation of hydrocarbon resources in the specific area is neither budgeted nor planned;

c)       exploration for and evaluation of hydrocarbon resources in the specific area have not led to the discovery of commercially viable quantities of mineral resources and the Group has decided to discontinue such activities in the specific area; and

d)     sufficient data exists to indicate that although a development in the specific area is likely to proceed the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or by sale.

An impairment loss is recognised for the amount by which the asset's carrying value exceeds its recoverable amount. The recoverable amount is the higher of an asset's fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash inflows which are largely independent of the cash inflows from other assets or groups of assets (cash-generating units).

Net proceeds from any disposal of an exploration asset are initially credited against the previously capitalised costs. Any surplus proceeds are credited to the consolidated statement of comprehensive income.

1.07 Oil and gas development/producing assets and commercial reserves

If the field is determined to be commercially viable, the attributable costs are transferred to development/production assets

within tangible assets in single field cost centres.

Subsequent expenditure is capitalised only where it either enhances the economic benefits of the development/producing asset or replaces part of the existing development/producing asset.

Decreases in the carrying amount are charged to the consolidated statement of comprehensive income.

Net proceeds from any disposal of development/producing assets are credited against the previously capitalised cost. A gain or loss on disposal of a development/producing asset is recognised in the consolidated statement of comprehensive income to the extent that the net proceeds exceed or are less than the appropriate portion of the net capitalised costs of the asset.

Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be at least a 50% statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as a proven and probable reserves.

1.08 Depletion and amortisation

All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field-by-field basis. In certain circumstances, fields within a single development area may be combined for depletion purposes. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs necessary to bring the reserves into production. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively.

1.09 Decommissioning

Where a material liability for the removal of production facilities and site restoration at the end of the productive life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. The cost of the relevant tangible fixed asset is increased with an amount equivalent to the provision and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed asset.

1.10 Property, plant and equipment

Property, plant and equipment is stated in the consolidated statement of financial position at cost less accumulated depreciation and any recognised impairment loss. Depreciation on property, plant and equipment other than exploration and production assets, is provided at rates calculated to write off the cost less estimated residual value of each asset on a straight-line basis over its expected useful economic life. Depreciation rates applied for each class of assets are detailed as follows:

Furniture, fittings and equipment                   1 - 4 years

Motor vehicles                                                  5 years

Leasehold improvements                                Over the life of the lease

The assets' residual values and useful lives are reviewed, and adjusted if appropriate, at each balance sheet date.

An asset's carrying amount is written down immediately to its recoverable amount if the asset's carrying amount is greater than its estimated recoverable amount with any impairment charge being taken to the consolidated statement of comprehensive income.

Gains and losses on disposals are determined by comparing proceeds with carrying amount and are recognised in the consolidated statement of comprehensive income.

1.11 Non-current assets and liabilities classified as held for sale and discontinued operations

A discontinued operation is a component of the Group that either has been disposed of, or is classified as held for sale.

A discontinued operation represents a separate major line of the business. Profit or loss from discontinued operations comprises

the post-tax profit or loss of discontinued operations and the post-tax gain or loss recognised on the measurement to fair value less costs to sell or on the disposal group(s) constituting the discontinued operation.

Non-current assets classified as held for sale are presented separately and measured at the lower of their carrying amounts immediately prior to their classification as held for sale and their fair value less costs to sell. However, some held for sale assets such as financial assets or deferred tax assets, continue to be measured in accordance with the Group's relevant accounting policy for those assets. Once classified as held for sale, the assets are not subject to depreciation or amortisation.

Any profit or loss arising from the sale of a discontinued operation or its remeasurement to fair value less costs to sell is presented as part of a single line item, profit or loss from discontinued operations. See Note 14 for further details.

1.12 Inventories

Inventories are stated at the lower of cost and net realisable value. Cost is determined by the weighted average cost formula, where cost is determined from the weighted average of the cost at the beginning of the period and the cost of purchases during the period. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution.

1.13 Revenue recognition

Revenue from sales of oil and natural gas is recognised at the transaction price to which the group expects to be entitled, exclusive of indirect taxes and excise duties. Revenue is recognised when performance obligations have been met, on delivery of product or when control of the product is transferred to the customer.

1.14 Foreign currencies

Transactions in foreign currencies are translated at the exchange rate ruling at the date of each transaction. Foreign currency monetary assets and liabilities are retranslated using the exchange rates at the balance sheet date. Gains and losses arising from changes in exchange rates after the date of the transaction are recognised in the consolidated statement of comprehensive income. This treatment of monetary items extends to the Group's intercompany loans whereby gains and losses arising from changes in the exchange rate after the date of transaction are also recognised in the consolidated statement of comprehensive income. Intercompany loans are provided to subsidiaries in the Group with the expectation that these loans will be collected in the foreseeable future. Non-monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated at the exchange rate at the date of the original transaction.

In the financial statements, the net assets of the Group are translated into its presentation currency at the rate of exchange at the balance sheet date. Income and expense items are translated at the average rates for the period. The resulting exchange differences are recognised in equity and included in the translation reserve. The consolidated financial statements and company financial statements are presented in United States Dollars ("$"), which is the functional currency of the Company. Subsidiaries in the Group have a range of functional currencies including United States Dollars, UK Pound Sterling, Trinidad and Tobago Dollars and Euros.

1.15 Leases

The Group leases various offices, warehouses, equipment and vehicles. Rental contracts are typically made for fixed periods of 6 months to 3 years, but may have extension options.

Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. The lease agreements do not impose any covenants other than the security interests in the leased assets that are held by the lessor. Leased assets may not be used as security for borrowing purposes.

Where applicable leases are recognised as a right-of-use asset and a corresponding liability at the date at which the leased asset is available for use by the Group.

Assets and liabilities arising from a lease are initially measured on a present value basis. Lease liabilities include the net present value of the following lease payments:

·        fixed payments (including in-substance fixed payments), less any lease incentives receivable;

·        variable lease payment that are based on an index or a rate, initially measured using the index or rate at the commencement date;

·        amounts expected to be payable by the Group under residual value guarantees;

·        the exercise price of a purchase option if the Group is reasonably certain to exercise that option; and

·          payments of penalties for terminating the lease, if the lease term reflects the Group exercising that option.

1.15 Leases

Lease payments to be made under reasonably certain extension options are also included in the measurement of the liability. The lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be readily determined, which is generally the case for leases in the Group, the lessee's incremental borrowing rate is used, being the rate that the individual lessee would have to pay to borrow the funds necessary to obtain an asset of similar value to the right-of-use asset in a similar economic environment with similar terms, security and conditions.

To determine the incremental borrowing rate, the Group:

·        where possible, uses recent third-party financing received by the individual lessee as a starting point, adjusted to reflect changes in financing conditions since third party financing was received;

·        uses a build-up approach that starts with a risk-free interest rate adjusted for credit risk for leases held by the Group, which does not have recent third-party financing; and

·        makes adjustments specific to the lease, for example term, country, currency and security.

The Group is exposed to potential future increases in variable lease payments based on an index or rate, which are not included in the lease liability until they take effect. When adjustments to lease payments based on an index or rate take effect, the lease liability is reassessed and adjusted against the right-of-use asset.

Lease payments are allocated between principal and finance cost. The finance cost is charged to profit or loss over the lease period so as to produce a constant periodic rate of interest on the remaining balance of the liability for each period.

Right-of-use assets are measured at cost comprising the following:

·        the amount of the initial measurement of lease liability;

·        any lease payments made at or before the commencement date less any lease incentives received;

·        any initial direct costs; and

·        restoration costs.

Right-of-use assets are generally depreciated over the shorter of the asset's useful life and the lease term on a straight-line basis. If the Group is reasonably certain to exercise a purchase option, the right-of-use asset is depreciated over the underlying asset's useful life.

Payments associated with short-term leases of equipment and vehicles and all leases of low-value assets are recognised on a straight-line basis as an expense in profit or loss. Short-term leases are leases with a lease term of 12 months or less. Low-value assets comprise IT equipment and small items of office furniture.

1.16 Financial instruments

Financial assets

The Group classifies its financial assets as financial assets held at amortised cost. Management determines the classification of its financial assets at initial recognition.

The Group classifies its financial assets as financial assets held at amortised cost only if both of the following criteria are met:

-          the asset is held within a business model whose objective is to collect the contractual cash flows; and

-          the contractual terms give rise to cash flows that are solely payments of principal and interest.

Measurement

Financial assets held at amortised cost are initially recognised at fair value, and are subsequently stated at amortised cost using the effective interest method. Financial assets at amortised cost comprise 'cash and cash equivalents' at variable interest rates, 'restricted cash', 'escrowed and abandonment funds' and 'trade and other receivables' excluding 'prepayments'.

Impairment of financial assets

The Group assesses, on a forward-looking basis, the expected credit losses associated with its financial assets held at amortised

cost. The impairment methodology applied depends on whether there has been a significant increase in credit risk.

The Group applies the expected credit loss model to financial assets at amortised cost. Given the nature of the Group's receivables, expected credit losses are not material.

Financial liabilities

The Group classifies its financial liabilities as other financial liabilities. Other financial liabilities are recognised initially at fair value and are subsequently measured at amortised cost using the effective interest method. Other financial liabilities consist of 'trade and other payables' and 'lease liabilities'. Trade and other payables represent liabilities for goods and services provided to the Group prior to the end of the financial period which are unpaid. The amounts are unsecured and are usually paid within 30 days of recognition.

Fair value measurement

Fair value is the price that would be received when selling an asset or paid to transfer a liability in an orderly transaction between market participants in its principal or most advantageous market at the measurement date. All assets and liabilities for which fair value is measured or disclosed in the financial statements are further categorised using the following three-level hierarchy that reflects the significance of the lowest level of inputs used in determining fair value.

-          Level 1 - Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

-          Level 2 - Pricing inputs are other than quoted prices in active markets used in Level 1. Prices in Level 2 are either directly or indirectly observable as of the reporting date. Level 2 valuations are based on inputs, included quoted forward price for
commodities, time value and volatility factors, which can be substantially observed or corroborated in the marketplace.

-          Level 3 - Valuations in this level are those with inputs that are not based on observable market data.

At each reporting date, the Group determines whether transfers have occurred between levels in the hierarchy by reassessing the level of classification for each financial asset and financial liability measured or disclosed at fair value in the financial statements based on the lowest level input that is significant to the fair value measurement as a whole. Assessments of the significance of a particular input to the fair value measurement require judgement and may affect the placement within the fair value hierarchy.

1.17 Cash and cash equivalents

Cash and cash equivalents include cash on hand and deposits held at call with financial institutions with original maturities of three months or less. For the purposes of the statement of cash flows, restricted cash is not included within cash and cash equivalents.

1.18 Share capital

Ordinary shares are classified as equity. Incremental costs directly attributable to the issue of new shares or options are deducted, net of tax, from the share premium. Net proceeds are disclosed in the statement of changes in equity.

1.19 Finance costs

Borrowing costs are recognised as an expense when incurred.

1.20 Borrowings

Borrowings are initially recognised at fair value, net of any applicable transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period of the borrowings using the effective interest method (if applicable).

Interest on borrowings is accrued as applicable to that class of borrowing.

Convertible loans

Loans with certain conversion rights at the option of the holder to convert to a fixed number of ordinary shares are identified as compound instruments with the liability and equity components separately recognised. If the fixed for fixed test is not met at contract inception, the loan is treated as a liability only. On initial recognition the fair value of the liability component is calculated by discounting the contractual stream of future cash flows using the prevailing market interest rate for similar non-convertible debt. The difference between the fair value of the liability component and the fair value of the whole instrument is recorded as equity within the convertible debt option reserve. Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially recognised. The liability component is subsequently measured at amortised cost using the effective interest rate method, in line with other financial liabilities. The equity component is not remeasured. On conversion of the instrument, equity is issued and the liability component is derecognised. The original equity component recognised at inception remains in equity. No gain or loss is recognised on conversion.

1.21 Provisions

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

When the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the statement of comprehensive income net of any reimbursement.

1.22 Dividends

Dividends are reported as a movement in equity in the period in which they are approved by the shareholders.

1.23 Taxation

The tax expense represents the sum of the tax currently payable and deferred tax.

Current tax, including overseas tax, is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantially enacted by the balance sheet date.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.

The carrying amount of deferred tax assets is reviewed at each balance sheet date and adjusted to the extent that it is probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised. Deferred tax is charged or credited in the consolidated statement of comprehensive income, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.

1.24 Impairment of assets

At each balance sheet date, the Group assesses whether there is any indication that its tangible and intangible assets have become impaired. Exploration and evaluation assets are also tested for impairment when reclassified to oil and natural gas assets. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment, if any. If it is not possible to estimate the recoverable amount of the individual asset, the recoverable amount of the cash-generating unit to which the asset belongs is determined.

The recoverable amount of an asset or a cash-generating unit is the higher of its fair value less costs to sell and its value in use. The value in use is the present value of the future cash flows expected to be derived from an asset or cash-generating unit. This present value is discounted using a pre-tax rate that reflects current market assessments of the time value of money and of the risks specific to the asset, for which future cash flow estimates have not been adjusted. If the recoverable amount of an asset is less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. That reduction is recognised as an impairment loss.

The Group's impairment policy is to recognise a loss relating to assets carried at cost less any accumulated depreciation or amortisation immediately in the consolidated statement of comprehensive income.

Impairment of goodwill

Goodwill acquired in a business combination is, from the acquisition date, allocated to each of the cash-generating units, or groups of cash-generating units, that are expected to benefit from the synergies of the combination. Goodwill is tested for impairment at least annually, and whenever there is an indication that the asset may be impaired. An impairment loss is recognised on cash-generating units, if the recoverable amount of the unit is less than the carrying amount of the unit. The impairment loss is allocated to reduce the carrying amount of the assets of the unit by first reducing the carrying amount of any goodwill allocated to the cash-generating unit, and then reducing the other assets of the unit, pro rata on the basis of the carrying amount of each asset in the unit.

If an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount but limited to the carrying amount that would have been determined had no impairment loss been recognised in prior years. A reversal of an impairment loss is recognised in the statement of comprehensive income. Impairment losses on goodwill are not subsequently reversed.

1.25 Employee benefits

Wages and salaries, and annual leave

Liabilities for wages and salaries, including non-monetary benefits, expected to be settled within 12 months of the reporting date are recognised in other payables in respect of employees' services up to the reporting date and are measured at the amounts expected to be paid when the liabilities are settled.

Share-based payments

Where equity settled share-based instruments are awarded to employees or Directors, the fair value of the instruments at the date of grant is charged to the consolidated statement of comprehensive income over the vesting period. Non-market vesting conditions are taken into account by adjusting the number of equity instruments expected to vest at each balance sheet date so that, ultimately, the cumulative amount recognised over the vesting period is based on the number of instruments that eventually vest. Market vesting conditions are factored into the fair value of the instruments granted. As long as all other vesting conditions are satisfied, a charge is made irrespective of whether the market vesting conditions are satisfied. The cumulative expense is not adjusted for failure to achieve a market vesting condition.

Where equity instruments are granted to persons other than employees or Directors, the consolidated statement of comprehensive income is charged with the fair value of goods and services received.

Bonuses

The Group recognises a liability and an expense for bonuses. Bonuses are approved by the Board and a number of factors are taken into consideration when determining the amount of any bonus payable, including the recipient's existing salary, length of service and merit. The Group recognises a provision where contractually obliged or where there is a past practice that has created a constructive obligation.

Pension obligations

For defined contribution plans, the Group pays contributions to privately administered pension plans. The Group has no further payment obligations once the contributions have been paid. The contributions are recognised as an employee benefit expense when they are due.

Termination benefits

Termination benefits are payable when employment is terminated by the Group before the normal retirement date, or whenever an employee accepts voluntary redundancy in exchange for these benefits. The Group recognises termination benefits when it is demonstrably committed to a termination and when the entity has a detailed formal plan to terminate the employment of current employees without the possibility of withdrawal. Benefits falling due more than 12 months after the end of the reporting period are discounted to their present value.

1.26 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, has been identified as the Board of Directors that makes strategic decisions. The performance of operating segments is assessed on the basis of key metrics applicable, such as barrels of oil produced per day, "netbacks" per barrel, revenue and operating profit.

The Board has determined there is a single operating segment: oil and gas exploration, development and production. However, there are four geographical segments: Trinidad & Tobago (including a single operating segment and a separate disposal group (refer to note 14)), The Bahamas (operating), Uruguay (operating) and The Isle of Man, UK, Spain, Saint Lucia, Cyprus, Netherlands and Suriname (all non-operating).

1.27 Share issue expenses and share premium account

 Costs of share issues are written off against the premium arising on the issues of share capital.

1.28 Share based payments reserve

This reserve is used to record the value of equity benefits provided to employees and Directors as part of their remuneration and

provided to consultants and advisors hired by the Group from time to time as part of the consideration paid.

1.29 Critical accounting estimates, judgements and assumptions

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

(i)       Recoverability of oil and gas exploration and production assets

Impairment of Trinidad and Tobago and Suriname intangible and tangible oil and gas assets and property plant and equipment

The Directors carried out an impairment review of the Group's tangible and intangible assets in Trinidad and Tobago, including goodwill, to determine whether the carrying value of these assets exceeded their fair value. The impairment assessment was undertaken by reference to various market data points and industry valuation standards, including, where applicable, discounted cashflows. Following this exercise, the Directors determined to record a full write down of goodwill totalling $4,610,000 (2022: nil).

In addition to this, two of the cash generating units ("CGU") located in Trinidad and Tobago have not met performance expectations. For these continuing operations, an impairment assessment was prepared on a "value in use" basis using discounted future cash flows based on expected future field performance, a forward oil price of $70 per barrel and a pre-tax discount rate of 10%. Applying this methodology impairments were identified in the relevant cash generating units (CGUs). Consequently, an impairment of related Trinidad and Tobago tangible assets of $8,290,000 (2022: $2,289,000) within these CGUs was recognised at balance sheet date.

A further write down of $57,000 (2022: nil) was recorded to the intangible asset in Suriname following the Group's decision to relinquish licence there during the year.

Further sensitivity analysis determined the following:

-          A $5 per barrel decrease in the oil prices would result increase the overall impairment charge to $8,879,000 to the CGUs;

-          A 5% decrease in production would increase the overall impairment charge to $8,972,000 to the CGUs; and

-          A 5% increase in the pre-tax discount rate would increase the overall impairment charge to $8,542,000 to the CGUs. Refer to note 10 (intangible assets) and note 11 (tangible assets).

Carrying value of capitalised exploration costs

Costs capitalised as exploration assets are assessed for impairment when circumstances suggest that the carrying value may exceed its recoverable value. This assessment involves judgement as to the likely commerciality of the asset, the future revenues and costs pertaining and the discount rate to be applied for the purposes of deriving a recoverable value.

The carrying value of exploration costs at 31 December 2023 is $93,963,000 (2022: $93,963,000) relating almost entirely to the cost of exploration licences, geological and geophysical consultancy, seismic data acquisition and interpretation and the drilling of exploration wells in the Bahamian offshore licences. The Group's exploration activities are subject to a number of significant and potential risks including licence obligations, requirement for further funding, geological and development risks, and political risk.

The recoverability of these assets is dependent on the discovery and successful development of economic reserves, including the ability to raise finance to develop future projects or alternatively, sale of the respective licence areas. The carrying value of the Group's exploration and evaluation expenditure is reviewed at each balance sheet date and, if there is any indication that it is impaired, its recoverable amount is estimated. Estimates of impairment are limited to an assessment by the Directors of any events or changes in circumstances that would indicate that the carrying value of the asset may not be fully recoverable. Any impairment loss arising is charged to the consolidated statement of comprehensive income.

On 21 February 2019, the Group received notification from the Bahamian Government of an extension of the term of its four southern licences to 31 December 2020, with the requirement that the Company commence an exploration well before the end of the extended term. On 23 March 2020, the Group notified the Government of The Bahamas that, due to the impacts of the global response to the Covid-19 pandemic, a force majeure event had occurred under the terms of its exploration licences, such that the term of the licences needed to be extended beyond 31 December 2020 commensurate with the duration of the force majeure event. In November 2020 the Group received notification per the Government of The Bahamas agreeing to an extension of these licences to 30 June 2021 as a result of the force majeure event. On 20 December 2020, the Group commenced drilling of the Perseverance-1 exploration well on its offshore licence area in The Bahamas, with drilling activity ceasing on 7 February 2021. Whilst the well demonstrated presence of hydrocarbons, commercial volumes of movable hydrocarbons were not present at this drilling location. Subsequently the Group undertook an extensive review of the data gathered from the Perseverance-1 well to determine the extent to which this data indicates remaining prospectivity in deeper, untested horizons, as well as horizons of interest at other locations along the B and C structures. The results of this review indicate that substantial prospectivity remains in sufficient potential volumes such that further exploration activity on these licences is merited. On the basis of the revised prospect volume inventory for these untested horizons and structures, the Group undertook an exercise to determine whether the present value of any future economic benefit which may be derived from hydrocarbon extraction from these licences is sufficient to support the carrying value of the capitalised costs at 31 December 2023. Following this review, the Group has determined that the present value of these future economic benefits exceeds the carrying value of this asset and that consequently no impairment of this asset is required.

Given this, in March 2021, the Group notified the then Government of The Bahamas of its election to renew the four southern licences into a further three-year exploration period, having discharged the licence obligation to drill an exploration well before the expiry of the second exploration term which expired on 30 June 2021. Since then, the Group has been in discussions with The Bahamas administration regarding the renewal of these licences. As at the current time, however, the renewal application remains under review with The Bahamas administration. Notwithstanding that the Group's application to renew the southern licences into third exploration period has now been pending for a considerable length of time, management considers this to be within the bounds of normal expectation in The Bahamas, given that (i) the renewal of the southern licences from the first exploration period into the second exploration period took almost five years, (ii) a new Government was elected in The Bahamas in September 2021, and (iii) Covid-19 pandemic related lock downs caused significant administrative delays all across the world. Once this renewal process is completed, the key licence obligation for the new three-year period would be the drilling of a further exploration well within the licence area before the expiry of the renewed licence term. The ability of the Group to discharge this obligation would be contingent on securing the funding required to execute a second exploration well.

(ii)      Going concern

These financial statements have been prepared on a going concern basis, which assumes that the Group will continue in operation for the foreseeable future.

The Group has incurred an operating loss of $19.9 million for the financial year ended 31 December 2023 (2022: loss of $4.2 million) and the Group's current liabilities exceeded current assets by approximately $2.9 million as of 31 December 2023 (2022: $2.0 million), however this includes approximately $4.1m in respect of taxes and penalties owed in Trinidad and Tobago that the Group expects to settle by way of offset against future tax refunds or are derived from notional estimates of tax penalties dating back to 2021 that the Group does not expect will be levied or assessed with final resolution still pending with the local tax authorities (refer to note 18 for further details). At 31 December 2023, the Group had approximately $1.0 million (2022: $2.5 million) in unrestricted cash funding and at the date of authorisation of these financial statements, the Group continues to have approximately $1.5 million in unrestricted cash funding.

On 6 March 2024, the Group entered into a farm-out agreement with Chevron, a leading global energy super-major, in relation to the Group's AREA OFF-1 licence offshore Uruguay pursuant to which the Group will receive US$12.5 million upfront payment at completion along with Chevron carrying the Group's share of certain future work programme costs (the "Farm-out"). The Farm-out is subject to Uruguayan regulatory approval. Management is highly confident that the requisite regulatory approvals will be forthcoming in the near-term, as Chevron meets all requirements to operate an energy project in Uruguay, and the submissions for regulatory approvals were made in consultation with ANCAP, the Uruguayan regulatory body. In addition, the Group expects US$0.3 million of presently restricted cash (in support of AREA OFF-1 performance bond) to become unrestricted shortly after the Farm-out completion.

On 18 April 2024 the Group announced that it had entered into a legally binding term sheet for an investment by Charlestown Energy Partners [[C, whereby Charlestown will invest £1.5 million in the Group, initially in the form of a loan, This investment was completed on 28 May 2024 and provides the Group with finance in the medium term until the completion of the farm-out agreement with Chevron, and, on completion of the Farm-out, the Charlestown investment will convert into a shareholding of approximately 8.7% in the Company.

The Directors have thus prepared these financial statements on a going concern basis, as based on the Group's cash flow forecasts (which include the proceeds from Charlestown investment and the Farm-out described above), the Group expects to have adequate financial resources to support its operations for the next 12 months (and well into the foreseeable future beyond that). In addition, the Directors note that the Company is a publicly listed company on a recognised stock exchange, thus affording the Company the ability to raise capital equity, debt and/or hybrid financing alternatives as and when the need arises. The Company has a robust track record in this regard, having raised in excess of US$100 million in equity and alternative financing in the recent past.

(iii) Recoverability of investment in subsidiaries and amounts owed by subsidiary undertakings in the Company statement of financial position

The investment in the Company's direct subsidiaries and amounts owed by subsidiary undertakings at 31 December 2023 stood at $43,650,000 (2022: $50,940,000) and $128,924,000 (2022: $128,338,000) respectively.

Ultimate recoverability of investments in subsidiaries and amounts owed by subsidiary undertakings is dependent on successful development and commercial exploitation, increasing production through optimisation of existing wells, drilling of new infill wells and/or the application of improved oil recovery methods or alternatively, sale of the respective licence areas. The carrying value of the Company's investments in subsidiaries is reviewed at each balance sheet date and, if there is any indication of impairment, the recoverable amount is estimated. Estimates of impairments are limited to an assessment by the directors of any events or changes in circumstances that would indicate that the carrying values of the assets may not be fully recoverable. Similarly, the expected credit losses on the amounts owed by subsidiary undertakings are intrinsically linked to the recoverable amount of the underlying assets. Any impairment losses arising are charged to the statement of comprehensive income.

At 31 December 2023, an impairment of the Company's investment in Columbus Energy Resources Limited of $7,300,000 (2022: nil) was recorded. In addition to this a loss allowance for expected credit losses of $14,021,000 (2022: $14,737,000) was held in respect of the recoverability of amounts due from subsidiary undertakings.

1.30 Earnings/(loss) per share

Basic earnings per share is calculated as net profit attributable to members of the parent company, adjusted to exclude any costs of servicing equity (other than dividends) and preference share dividends, divided by the weighted average number of ordinary shares, adjusted for any bonus element.

Diluted earnings per share is calculated as net profit attributable to members of the parent company, adjusted for:

(i)      Costs of servicing equity (other than dividends) and preference share dividends;

(ii)     The post-tax effect of dividends and interest associated with dilutive potential ordinary shares that have been recognised as expenses; and

(iii)    Other non-discretionary changes in revenues or expenses during the period that would result from the dilution of potential ordinary shares, divided by the weighted average number of ordinary shares and dilutive potential ordinary shares, adjusted for any bonus element.

1.31 Investment in subsidiary in the Company statement of financial position

Investments in subsidiaries are recognised at initial cost of acquisition, less any impairment to date.

2      Turnover and segmental analysis

Management has determined the operating segments based on the reports reviewed by the Board of Directors that are used to make strategic decisions. The Board has determined there is a single operating segment: oil and gas exploration, development and production. However, there are four geographical segments: Uruguay (operating), Trinidad & Tobago (including a single operating segment and a separate disposal group (refer to note 14)), The Bahamas (operating), and The Isle of Man, UK, Spain, Saint Lucia, Cyprus, Netherlands and Suriname (all non-operating).

The Uruguay segment includes the exploration licences and appraisal works which have commenced in 2022. The segment including Trinidad & Tobago has been reported as the Group's direct oil and gas producing and revenue generating operating segment. The Bahamas segment includes the Bahamian exploration licences on which drilling activities were conducted in 2020 and 2021. The non-operating segment including the Isle of Man (the Group's parent), provides management services to the Group and entities in Saint Lucia, Cyprus, Spain, Netherlands and Suriname all of which are non-operating or in that they either hold investments or are dormant/in the process of being wound up. Their results are consolidated and reported on together as a single segment.

(*)   Intercompany balances and transactions between Group entities have been eliminated.

(**) Sales revenues were derived from a single customer within each of these operating countries.

(***) Administrative expenses includes various non-cash items including depreciation and amortisation, share based payments expense, share settled payment expenses and loss on disposal of fixed assets. Removing these items results in a corporate administration cash cost of approximately $2.29 million for the year ended 31 December 2023, or approximately $190,000 per month.

14 Discontinued operations

Sale of T-Rex (Cory Moruga asset):

On 20 December 2022, the Company announced that it had entered into a binding heads of terms with Predator Oil & Gas Holdings Plc (PRD), providing for the conditional sale of the Company's interest in the non-producing Cory Moruga licence in Trinidad through the sale of 100% of the share capital in T-Rex Resources (Trinidad) Limited (TREX), with retention of 25% future back-in right (at the Company's option) based on the outcomes of future drilling / EOR activity and associated future production.

The sale of the Cory Moruga licence, onshore Trinidad, to PRD, was completed on 6 November 2023.

As a consequence of negotiations associated with reaching an agreed position with the Trinidadian Ministry of Energy and Energy

Industries ("MEEI"), the Company and PRD agreed to vary certain terms of the previously announced agreement between them,

as follows:

-         On completion, PRD paid the Company US$1 million in cash;

-        A further US$1 million, which was due to be paid by PRD to the Company six months from completion, was instead paid immediately by PRD direct to MEEI, in part agreed settlement of past dues on the Cory Moruga licence; and

-        A contingent US$1 million payable by PRD to the Company in the event of the Cory Moruga field achieving certain future production benchmarks, and PRD granting to the Company a future back-in right to a 25% interest in the Cory Moruga field at an uplifted multiple of cost base, will no longer apply, reflective of the Company's contribution to the value of settlement of the balance of past dues on the Cory Moruga licence, which will be recovered by MEEI via agreed quarterly arrears payments.

In addition to the cash consideration received, completion of the transaction had the effect of extinguishing various liabilities in the Company's accounts relating to the Cory Moruga licence, amounting to approximately US$4.5 million. Further, in parallel with completion, all historical differences and disputes between the Company and PRD in relation to the Inniss-Trinity pilot CO2 EOR Project were fully and amicably resolved, pursuant to the terms of the previously announced Settlement Agreement between the Company and PRD.

Consideration was received in cash during the period. At the date of the disposal the carrying amounts of T-Rex net assets were as follows:

(*)      The gain on disposal is included in the gain/(loss) for the year from discontinued operations in the consolidated statement of profit and loss.

Sale of Caribbean Rex Limited ("CREX") (South Erin asset):

On 14 February 2023, the Company announced it had entered into and completed a transaction for the sale of its St Lucia domiciled subsidiary company, CREX which included its associated assets and subsidiary entities. This includes (via interposed subsidiaries) CEG South Erin Trinidad Limited ("CSETL") a Trinidadian company that is party to a farm-out agreement for, and is the operator of, the South Erin field, (onshore Trinidad) and West Indian Energy Group Limited (a Trinidadian service company).

1)       On 31 August 2023, the Company drew down a £550,000 (US$636,000) first tranche of a £3,300,000 (US$4,198,000) convertible loan notes agreed with a UK based alternative asset management and investment firm. The loan notes once drawn down were repayable within 36 months. Interest was fully pre-paid on draw down such that on draw down 90% of the value of the notes was advanced in cash to the Company. The holder had the right, at any time prior to repayment, to elect to convert the Notes into fully paid ordinary shares in the Company at the lesser of (i) 140% of the Company's closing bid price on the trading day immediately prior to the date of draw down, or (ii) 90% of the lowest closing bid price in the five trading days immediately preceding the date of the conversion. The loan notes were redeemable in cash by the Company, all or in part, at any time after draw down at 105% of the par value.

On 29 September 2023, the Company received a conversion notice in respect of £165,000 of outstanding convertible notes requiring the Company to issue 458,333,333 new ordinary shares. The new shares were issued on 5 October 2023 (see note 22).

On 27 October 2023, the Company announced it had re-financed the convertible loan notes and secured a short-term bridge loan of £350,000 (US$432,000) which immediately settled the unconverted balance of the convertible loan notes including early redemption charges. As part of this settlement the holder of the notes issued a further conversion notice in respect of £55,000 of outstanding convertible notes requiring the Company to issue 100,000,000 new ordinary shares which were issued on 2 November 2023 (see note 22). In addition to this, a further 250,000,000 warrants in the Company were granted to the holder at an exercise price of 0.1p per share which will remain valid for 36 months from date of grant. The outstanding bridge loan also included a 12% annual coupon accruing monthly. The bridge loan was subsequently fully repaid on 7 November 2023.

2)       On 30 December 2020, the Company drew down £1,110,000 (US$1,511,000) of a £3,000,000 (US$4,084,000) first tranche of a convertible loan previously agreed with Bizzell Capital Partners Pty Ltd. As part of this initial draw down in 2020, £287,000 (US$396,000) was recognised as the equity component. Tranche 1 had a total fair value, after deduction of all facility costs, of £2,800,000 (US$3,812,000). The term of the loan was 3 years from the date of draw-down. The holder had the right, at any time prior to maturity, to elect to convert the Notes (principal plus any accrued interest) into fully paid ordinary shares in the Company. Initially, the conversion price was set at a 25% premium to the price of the Company's next capital raising (if any) or at 6p per share, whichever was the lower. Subsequently, in February 2021 the conversion price was amended by agreement to 0.8p per share. In May 2021 the balance of the £3,000,000 facility was drawn down in full, resulting in a further £370,000 (US$505,000) equity component being recognised. Thereafter £2,500,000 (US$3,496,000) of the facility amount was converted into ordinary shares resulting in a £579,000 (US$787,000) equity conversion, leaving a remaining principal outstanding of £342,000 (US$462,000) and residual equity component of £84,000 (US$114,000) at 31 December 2021. The remaining balance was converted into ordinary shares as part of the restructuring completed in March 2022.

(*)                         The provisions relate to the estimated costs of the removal of Trinidadian and Spanish production facilities and site restoration at the end of the production lives

of the facilities. Decommissioning provisions in Trinidad and Tobago have been subject to a discount rate of 4.32% -4.94% (2022: 3.8%-4.98%), expected cost inflation of 1.87% (2022: 2.06%-3.22%) and assumes an average expected year of cessation of production of 2032. Decommissioning provisions relating to facilities in Spain are undiscounted and uninflated as the field is no longer operating. The Spanish subsidiary is currently in the process of being liquidated and management's expectation is that the provision for decommissioning relating to Spanish assets will be released on completion of this process.

On 7 March 2022, 73,803,215 options to various parties including management and various consultants were cancelled by mutual consent with the option holders and 1,536,559,845 new options were issued.

On 2 November 2023 250,000,000 warrants were granted to a finance provider in relation to the settlement of a bridging loan facility, refer to note 20 for further details.

The fair value of the warrants and options granted in the year was estimated using the Black Scholes model. The inputs and assumptions used in calculating the fair value of options granted in the year were as follows:

Warrants and options granted in 2023

Warrants and options granted in 2022

The weighted average remaining contractual life of the options and warrants in issue at 31 December 2023 was 3.61 years (2022: 4.98 years) and the weighted average exercise price of these instruments was 0.2p pence per share (2022: 0.24 pence). The range of exercise prices for options and warrants outstanding at 31 December 2023 was 0.10 pence to 28 pence (2022: 0.1 pence to 28 pence).

The expected price volatility used in calculating the fair value of options and warrants granted by the Company is determined based on the historical volatility of the Company share price (based on the remaining life of the options), adjusted for any expected changes to future volatility due to publicly available information.

The above charges in relation to share-based payments include $nil relating to Directors (2022: $76,000), $nil related to staff and consultants (2022: $45,000), $nil relating to warrants granted to the Company's advisors (2022: $130,000) and $1,000

(*)          Represents the fair value of shares issued to various advisors and consultants in lieu of cash for their fees. The fair value of these shares has been calculated based on the number of shares issued and the market price of the Company shares on the date of issuance. These expenses have been recognised in the Group statement of comprehensive income under "Professional fees - share settled" within administrative expenses or share premium with respect to advisory fees for raising share capital. These transactions do not fall within the scope of IFRS 2, Share based payments.

(**)         Represents the fair value of shares issued to directors and staff during the year in settlement of deferred salary and fees, less the total value of accrued salaries and fees on the date of settlement. The fair value of these shares has been calculated based on the number of shares issued and the market price of the Company shares on the date of issuance. Accruals for deferred salary and fees had been recognised based on the value of contractual payments forgone. The excess of the fair value of these shares issued over the total accrued costs for deferred salary and fees to the date of settlement has been recognised in the Group statement of comprehensive income under "Staff costs - share settled" within Administrative expenses. These transactions do not fall within the scope of IFRS 2, Share based payments.

The table below discloses the total share-based payment charges for the year included in the statement of comprehensive income by expense category.

24 Financial instruments and risk management - Group & Company

The Group's activities expose it to a variety of financial risks: oil price, liquidity, interest rate, foreign exchange, credit and capital risk. The Group's overall risk management programme focuses on minimising potential adverse effects on the financial performance of the Group.

Risk management is carried out by the CEO under policies approved by the Board of Directors. The CEO identifies, evaluates and addresses financial risks in close cooperation with the Group's management. The Board provides principles for overall risk management, as well as policies covering specific areas, such as mitigating foreign exchange risk, interest rate risk, credit risk and investing excess liquidity.

The Group uses financial instruments comprising cash, and debtors/creditors that arise from its operations. The net fair value of financial assets and liabilities approximates the carrying values disclosed in the financial statements. The financial assets comprise cash balances in bank accounts at call.

Oil Price Risk

The Group has been exposed to commodity price risk regarding its sales of crude oil which is an internationally traded commodity. The Group sales prices are closely linked to the West Texas Intermediate (WTI) Crude Oil benchmark for sales in Trinidad and Tobago. The pricing of Group oil sales in Trinidad and Tobago is set by the state oil company Heritage and the price realised by the Company is typically at approximately 10% discount to WTI benchmark. The Group does not take out hedging instruments for changes in oil prices, with the risks to Group cashflows associated with changes in the oil price obtained from Heritage being mitigated by controls over elective costs of well workovers and other such production enhancing expenditure.

The spot prices per barrel for WTI are shown below:

Interest rate risk

The Group's strategy for managing cash is to maximise interest income whilst ensuring its availability to match the profile of the

Group's expenditure. This is achieved by regular monitoring of interest rates and monthly review of expenditure forecasts.

The Group's exposure to interest rate risk relates to the Group's cash deposits which are linked to short term deposit rates and therefore affected by changes in bank base rates. At 31 December 2023, short term deposit rates were in the range of 0% to 0.5% (31 December 2022: 0% to 0.5%) and therefore the interest rate risk is not considered significant to the Group. An increase in interest rate of 0.25% in the year would have had an insignificant effect on the Group's loss for the year and profit in the prior year.

Group borrowings are at fixed interest rates and therefore do not present an interest rate risk.

Foreign currency risk

The Group operates internationally and therefore is exposed to foreign exchange risk arising from currency exposures, primarily

with regard to UK Sterling, Trinidad and Tobago Dollars and Euros.

The Company has a policy of not hedging foreign exchange and therefore takes market rates in respect of currency risk; however it does review its currency exposures on an ad hoc basis. Currency exposures relating to monetary assets held by foreign operations are included within the foreign exchange reserve in the Group statement of financial position.

The following table details the Group's sensitivity to a 10% increase and decrease in the US Dollar against the relevant foreign currencies of Pound Sterling, Euro and Trinidadian Dollar. 10% represents management's assessment of the reasonably possible change in foreign exchange rates.

The sensitivity analysis includes only outstanding foreign currency denominated investments and other financial assets and liabilities and adjusts their translation at the year-end for a 10% change in foreign currency rates. The table below sets out the potential exposure, where the 10% increase or decrease refers to a strengthening or weakening of the US Dollar:

Annual licence rental commitments

The Group is required under its Bahamian exploration licences to remit annual rentals in advance to the Government in respect of the licenced areas. On 27 February 2020, the Company advised that, consequent upon the granting of Environmental Authorisation for the Perseverance-1 well, the Company and the Government of The Bahamas had agreed a process seeking a final agreement on the amount of licence fees payable for the balance of the second exploration period (including the additional period of time to which the licence period was extended as a result of force majeure). At the time, the parties entered into discussions with a view to finalising this outstanding matter, although as at the date of this report there has been no substantive progress on this issue with the Government of The Bahamas. The amount which the Group considers to be outstanding is small, and the Group expects this will be addressed as part of the broader discussion around renewal of the licence areas, as previously noted.

The Group does not have any material annual rental payments payable on its licences in Trinidad and Tobago, and Uruguay.

26 Related party transactions - Group & Company

Transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation. Transactions between other related parties are outlined below.

Remuneration of Key Management Personnel

The Directors of the Company are considered to be the Key Management Personnel. Details of the remuneration of the Directors

of the Company are disclosed below, by each of the categories specified in IAS24 Related Party Disclosures.

(*)      Represents the fair value of shares issued to directors during the year in settlement of deferred salary and fees, less the total value of accrued salaries and fees on the date of settlement.

See note 7 for further details of the Directors' remuneration and note 23 for details of the Directors' share-based payment benefits. Share options that have been granted to key management personnel are as follows:

Other related party transactions

Transactions between the Company and its subsidiaries during the year are as follows:

27    Events after the reporting period - Group & Company

On 6 March 2024, the Group announced that it and its wholly-owned Uruguayan subsidiary, CEG Uruguay SA have entered into a farm-out agreement (the "Transaction") with Chevron Uruguay Exploration Limited, a wholly-owned subsidiary of Chevron Corporation, related to a 60% interest in the AREA OFF-1 block, offshore Uruguay. The primary terms of the Transaction include a payment to the Group of US$12.5 million cash on completion of the Transaction. Completion and financial close of the Transaction are subject to the satisfaction of conditions precedent and customary third-party approvals from the Uruguayan regulatory authorities, which are anticipated to finalise in the near-term.

On 11 March 2024, the Group announced that following final regulatory approvals being granted, the AREA OFF-3 licence, offshore Uruguay, was signed in Montevideo on 7 March 2024. Accordingly, AREA OFF-3's first exploration period commenced on 7 June 2024, and runs for four years, until 6 June 2028.

On 18 April 2024, the Group announced that it had entered into a legally binding term sheet for an investment by Charlestown Energy Partners LLC, whereby Charlestown will invest £1.5 million in the Group, initially in the form of a loan, which upon closing of the AREA-OFF-1 farm-out to Chevron and subject to prior completion of an agreed share consolidation shall convert at a fixed price of 0.168 pence per share (being approximately a 20% premium to the current share price at the date of the announcement) and resulting in a shareholding of approximately 8.7% of the Group. It was subsequently announced on 7 May 2024 that the long-form legal documentation for the Charlestown loan had been finalised in line with the original term sheet as detailed on the 18 April, and the loan proceeds were received on 28 May 2024.

On 28 May 2024, the Group announced that Mr. Robert Bose joined the Board following the completion of the investment in the Company by Charlestown Energy Partners LLC.

28 Comprehensive income/(expense) for the year - Company

The Company's loss after tax for the year was $9,070,000 (2022: profit of $1,330,000).

Corporate Directory

Company Number                                          Registered in the Isle of Man with registered number 123863C

Current Directors                                           Iain McKendrick                                             Eytan Uliel

Non-Executive Chairman                                  Chief Executive Officer

Simon Potter                                                  Stephen Bizzell

Non-Executive                                                   Non-Executive

Robert Bose
Non-Executive

Secretary                                                         Benjamin Proffitt                                           Jonathan Gilmore

Company Secretary                                          Joint Company Secretary

Registered Office and                                   The Engine House

Corporate Headquarters                             Alexandra Road,

Castletown

Isle of Man

IM9 1TG

Registrar                                                          Link Market Services (IOM) Limited

PO Box 227

Peveril Buildings

Peveril Square

Douglas

Isle of Man

IM99 1RZ

Auditor                                                             Grant Thornton

13-18 City Quay
Dublin 2

Ireland

Principal Legal Advisors                               Clyde & Co

St Botolph Building

138 Houndsditch

London

EC3A 7AR

United Kingdom

Nominated Advisor                                       WH Ireland

24 Martin Lane

London

EC4R 0DR

United Kingdom

Joint Brokers                                                  WH Ireland                                                      Zeus Capital PLC

24 Martin Lane                                                  125 Old Broad Street

London                                                              London

EC4R 0DR                                                          EC2N 1AR

United Kingdom                                               United Kingdom

ENDS