Annual Report for the year ended 31 Dec 21 Part 1

RNS Number : 2568B

Challenger Energy Group PLC

30 September 2022

 

30 September 2022

Challenger Energy Group PLC

("Challenger Energy" or the "Company")

Annual Report and Financial Statements for the year ended 31 December 2021

Challenger Energy (AIM: CEG), the Caribbean and Atlantic -margin focused oil and gas company, with oil production, appraisal, development and exploration assets across the region, announces its Annual Report and Financial Statements for the year ended 31 December 2021.

The 2021 Annual Report and Financial Statements will be posted to shareholders today. The Company's AGM will be held on 29 November 2021 at 34 North Quay, Douglas, Isle of Man IM1 4LB. Notice of the AGM will also be posted to shareholders in due course.

The 2021 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:

Challenger Energy Group PLC Eytan Uliel, Chief Executive Officer	Tel: [phone]
Strand Hanson Limited - Nomad Rory Murphy / James Spinney / Rob Patrick	Tel: [phone]
Arden Partners plc - Broker Simon Johnson	Tel: [phone]
CAMARCO Billy Clegg / James Crothers / Hugo Liddy	Tel: [phone]

Notes to Editors

Challenger Energy is a Caribbean and Atlantic margin focused oil and gas company, with a range of exploration, appraisal, development and production assets and licences, located onshore in Trinidad and Tobago, and Suriname, and offshore in the waters of Uruguay and The Bahamas. In Trinidad and Tobago, Challenger Energy has five (5) producing fields, two (2) appraisal / development projects and a prospective exploration portfolio in the South West Peninsula. In Suriname, Challenger Energy has on onshore appraisal / development project. Challenger Energy's exploration licences in Uruguay, the South West Peninsula of Trinidad, and The Bahamas offer high-impact value exposure within the overall portfolio value.

Challenger Energy is quoted on the AIM market of the London Stock Exchange. 

https://www.cegplc.com  

ENDS

Challenger Energy Overview

Challenger Energy is a Caribbean and Atlantic margin focused energy business with a range of exploration, appraisal, development and production assets and licences, located onshore in Trinidad and Tobago and Suriname, and offshore in Uruguay and The Bahamas.

Trinidad and Tobago

· 7 licences (100%), 1 licence (83.8%) -all onshore

· Low-risk production operations at five fields; considerable existing well stock (~250 wells of which approximately 80 are in production at any time); close to sales infrastructure

· 2P Reserves of 1.3MMbbls; 2C Resources of 6.4MMbbls (per 2020 CPR)

Production and cashflow focused strategy

· Production enhancement potential from workovers, recompletions, reactivations, enhanced oil recovery techniques, and swabbing, and growth potential from new wells / field developments in 2023 and beyond

· Consolidation and new licence opportunities offer scope to grow production base further

Suriname

· 1 onshore licence- Weg naar Zee PSC (100%), 900 km2

· 2C Resources of 1.1MMbbls; 3C Resources of 3.5 MMbbls (24 MMbbls STOIIP) (per 2020 CPR)

· Technical work underway to define and implement production test well design along with enhanced oil recovery techniques, success would lead to a development

Uruguay

· 1 offshore licence- OFF-1 (100%) 14,557 km2 with multiple leads and prospects -resource potential in excess of 1 billion bbls

· Low-cost initial 4-year exploration period commenced 25 August 2022, initial 2D seismic licencing and reprocessing work underway

· Uruguay is an emerging industry "hot spot" given successful conjugate margin exploration drilling in Namibia in early 2022, as well as recent Uruguay entry by majors with substantial forward work programme commitments

The Bahamas

· 4 offshore licences (100%), licence renewals currently pending

· Perseverance-1 well drilled in 2021: encountered hydrocarbons via logs although commercial volumes were not proven; post well analysis indicates potential for a deeper Jurassic play and continued prospectivity of other structures and targets

· People and Assets

· ~75 staff, with the majority in Trinidad and Tobago

· 2 workover rigs and 1 swabbing rig, owned and operated in Trinidad and Tobago to support routine production and maintenance activities

Chief Executive Officer's Report to the

Shareholders

Dear fellow Shareholders,

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

This Annual Report covers the 2021 financial year period (that is, from January to December 2021). As with last year, however, timing for 2021 reporting was delayed more than usual, owing to residual local impacts of the Covid-19 pandemic in some of the jurisdictions in which we operate. Hopefully, as the world rebounds from the pandemic and work gets back to normal in all jurisdictions, this will not be the case next year when it comes to reporting for 2022.

As a result of the timing delay for this Annual Report, its release coincides with the timing for release of the half-year results for the period January-June 2022, and much of the restructuring activity (which I elaborate on below), although commenced in the second half of 2021, only saw significant outcomes for the Group during the first half of 2022. Therefore, even though strictly speaking this Annual Report relates to the period January to December 2021, I will refer in my report more generally, to the period from the start of 2021 until the middle of 2022.

2021 in Context

For the majority of the Group's history its business and asset base focused exclusively on the frontier basin "wildcat" operations associated with its Bahamian licences - a preserve usually associated with International Majors and NOCs. Entry into an exploration licence in Uruguay in May 2020 broadened the portfolio for the first time, by adding another early-stage high-impact exploration asset. Then, through the acquisition in August 2020 of production, near term production, appraisal and exploration assets in Trinidad and Tobago and Suriname, we transformed the Group by extending the asset base across the region and sector value chain, and diversified the corporate risk profile.

2021 thus marked the Group's first full year of operations with an expanded asset suite, and we commenced 2021 with a much larger business and team, and a full slate of planned work before us: drilling of Perseverance-1 in The Bahamas, which was the culmination of over a decade's work and efforts; drilling of Saffron-2 in Trinidad; operating the producing fields in Trinidad; and undertaking the initial work needed to mature the assets in Uruguay and Suriname.

The Drilling Campaigns

The Group's 2021 drilling campaigns both occurred in the first half of the year: the bulk of drilling for the Perseverance-1 exploration well in The Bahamas occurred in January 2021 with the well completed in early February 2021, and the Saffron-2 appraisal well in Trinidad was drilled in June - July 2021.

We are proud of the fact that, despite many challenges, we did what we said we would do: we drilled both wells safely and without incident and met the objective of testing the relevant structures at the chosen drilling locations. This was no small feat, especially for a Group of our size: we had to secure the financing needed, we had to recruit an experienced operations team, and in two different geographies we had to operate complex drilling programmes more typically undertaken by much larger companies. We did all of this at the peak of the global pandemic, and in the case of The Bahamas, whilst successfully overcoming a legal challenge from environmental activists that was frivolously launched at the very last minute.

This highlights the commitment, professionalism and dedication of the people who work at Challenger Energy, as well as our robust business systems and procedures, all of which remain core assets of the Group as we move forward.

In terms of outcomes, Perseverance-1 did not result in the commercial discovery we hoped for, but a substantial amount of data and learning was obtained from the drilling of the well, which was the first in the region linked to 3D seismic and using modern techniques. During the balance of 2021 we analysed this data, and concluded that The Bahamas might yet offer long-term potential. In simple terms, Perseverance-1 only tested one part of one structure, but there are at least four other locations and multiple structures that were upgraded following the Perseverance-1 outcome, and which therefore in the future could merit further analysis and testing. Data from Perseverance-1 also provides encouraging support for the possibility of a deeper, sizeable Jurassic oil play.

As I have observed before, in frontier basins it is not at all uncommon for several exploration wells to be required before the potential of that basin is unlocked. Given this, in March 2021 we submitted documentation for renewal of our Bahamian licences into a third, three-year exploration period - this remains pending with The Bahamian Government, but the Group has completed all of its work obligations and is thus entitled to a renewal. At the same time, we have been clear on our go-forward strategy in The Bahamas - any future activity will require a "big brother" partner, ideally a larger industry player, to provide expertise and the capital that will be needed for the next phase of activity.

Turning to the Saffron-2 well in Trinidad, it did not provide the immediate production boost we were seeking from Lower Cruse reservoir units, although that well, along with Saffron-1 (drilled prior to Challenger Energy assuming control of the asset) provided much data on the viability of production from the Upper Cruse and Middle Cruse sands across the broader licence area. Thus, during the second half of 2021 and continuing into 2022, technical work commenced to assess the commercial feasibility of a development focused only on these upper reservoir horizons. A project of this nature would not be of the same scale as what we had hoped for based on a Lower Cruse development, but an Upper and Middle Cruse focused development, if economic, would still enable us to access valuable increased production, and derive benefit from our extensive licence position in the area. Over the coming months we will complete the work needed to firm up our plans. 3

Production Operations in Trinidad and Tobago

During 2021 we strategically repositioned the Group so as to prioritise our producing assets in Trinidad and Tobago. We also established a very clear, simple objective for the operations in Trinidad: to focus on production, to manage costs tightly, and to thereby try to generate positive cashflow from these operations.

There were three reasons for this strategic repositioning. One, routine production provides a baseline level of cashflow, which we can use to plan our business around. Two, we believe that by applying efficient oilfield management practices, production at our fields can be sustained and thereafter increased, producing surplus cash that could be reinvested in value-adding work in the fields themselves, as well as applied towards covering the business' total operating cost. And three, the oil and gas industry is cyclical, and in the last few years higher-risk activities - especially those considered to be "frontier exploration" - have fallen largely out of favour. By contrast, in the context of the recent industry environment, investors and capital providers have seemed far more interested in that part of our business offering a lower-risk, predictable cashflow profile, even if that does not offer the same level of upside potential as successful high-impact exploration activities.

In support of this strategic repositioning, the work undertaken in Trinidad and Tobago during 2021 broadly fell into two categories of work, "above ground" and "below ground".

The focus of our "above ground" work essentially related to the fact that prior to Challenger Energy assuming control of the Trinidadian production assets in August 2020, they had been starved of cash, and generally poorly managed. This was evident in low field activity levels, poor morale amongst staff, inadequate policies and procedures, poor record keeping, many local suppliers who had not been paid, and a business reputation in-country that was suffering, especially with the regulators.

"Below ground", the work focus related to the fact that our assets in Trinidad are mature - some have been producing oil for more than 60 years now. The reservoirs are thus depressurised and the resource depleted, such that there is always going to be a natural, inevitable level of production decline each year. This has to be offset through efficient mature oilfield management practices, targeted production enhancement activities, very tight cost control, and ultimately the maturation of resources and drilling of new wells in areas of the fields that have previously not been tapped.

Insofar as "above ground" work is concerned, all through 2021 we made operational improvements: well workover rates increased, preventative maintenance increased, we restructured the staff base, we worked to restore staff morale and productivity, and we rescheduled and cleared the Trinidadian business of many old debts and claims. Policies and procedures were revamped, and new country management was identified (with key new hires, including a new Country Manager, taking effect from early 2022 onward).

A good measure of our success in this regard is the restored business relationship we have seen with various suppliers essential to ongoing operations (many of whom were previously threatening to suspend services). Another measure of success is the fact that toward the end of 2021 and into 2022 we secured extensions of two key licences in Trinidad, I believe largely because we could demonstrate to the regulators the extent of the improvements we had made.

Therefore, in relation to the "above ground", my report is that 2021 and H1 2022 have been periods of solid progress.

We systematically tackled many issues so that, in an operational sense, the overall business in Trinidad and Tobago today is in a

far better shape today than it was 18 months ago.

More challenging, however, has been the "below ground" work I mentioned above - i.e., the work needed to offset natural production decline, sustain and enhance baseline production, and generate positive cashflow. This was especially difficult because during the first half of 2021 attention and capital was focused on our drilling activities, and access to Trinidad was restricted due to the pandemic. Then, from the middle of 2021 onwards, available capital and our ability to do substantive work in this area was greatly limited until the restructuring process (which I discuss further below) was completed.

Through 2021 we thus saw a decline in our average production rate -approximately 450 barrels of oil produced per day toward the start of the year, and then declining to end the year at below 350 barrels of oil produced per day. Since completing the restructure and recapitalisation of the Group in March 2022 we have been able to turn our attention fully to production maintenance and enhancement activities. This, along with the benefit of greater access as Covid-19 restrictions have lifted, means we have since seen steady improvement with production rates improving during the first half of 2022 and ranging between 375 - 400 barrels of oil produced per day towards the end of 2H2022. Given current oil prices, and with the in-country cost structure we now have in place, this means we have achieved our first goal: a baseline level of production that can sustain the business in Trinidad (the average oil price realised in 2021 was approximately US$60 per barrel, a level considerably below current prices being realised).

Beyond this, we hope to see further improvements in the coming months as various production enhancement initiatives are rolled-out, and we've developed a plan for additional field work, potential new well drilling, and various Enhanced Oil Recovery (EOR) initiatives over the coming 12 months. We are also continuously assessing various opportunities to expand our producing asset base through adding new licences.

Therefore, in relation to the "below ground" challenge we face in Trinidad, my report is that 2021 and the first half of 2022 were periods of laying foundations, but we are still at the early stages of executing a long-term plan to build a production base of scale in Trinidad. I hope next year to be able to report on our continued progress.

Other Activities

Notwithstanding the unambiguous focus placed on the production business in Trinidad and Tobago since mid-2021, we continued to progress the broader asset portfolio, albeit in a low-cost, "below the radar" way. These activities can be summarised as follows:

Weg naar Zee PSC in Suriname

There was no field activity in relation to the WNZ block in Suriname during 2021. We had initially hoped for drilling of an initial pilot well in late 2021 or early 2022, but the pandemic made this impossible - Covid-19 restrictions in Suriname remained in place until early 2022. Instead, we took the opportunity during 2021 to completely revisit all of our assumptions on this project and update our thoughts on well design and development pacing. We have also applied for an extension of the initial period under our licence, given the delays occasioned by the pandemic - approval is pending with the regulators. Subject to this approval, we expect to be able to resume activity in Suriname during 2023, and between now and then, we are working on developing potential partnering opportunities for this asset. Further updates will be provided in due course.

AREA OFF-1 in Uruguay

In June 2020, we were awarded the AREA OFF-1 licence block, offshore Uruguay. However, through all of 2021 there was minimal activity on the licence, while we waited for its ratification by the Uruguayan Ministry and regulatory agency, ANCAP. This had been delayed due to the impacts of Covid-19 in Uruguay. Subsequently, it was only on 25 May 2022 that all procedural matters were completed and the licence formally executed. As a result, our initial four-year exploration period only commenced on 25 August 2022.

To remind shareholders, our minimum work obligation for this period is to licence 2,000 kms of 2D seismic from ANCAP, to reprocess / re-interpret that data, and to complete two geological studies. There is no obligation to acquire 3D seismic, nor obligation to drill a well in the first exploration period. We are well advanced in the process of meeting this minimum work obligation, having recently licenced the required 2D seismic, with reprocessing already underway - we expect to have the full results of this work in early 2023.

We anticipate that this initial activity - low cost as it may be - will prove to be very timely, because the delay experienced while waiting for formal licence ratification has been serendipitous. Specifically, as I noted in the 2020 Annual Report, two "wildcat" exploration wells had been planned for late 2021 in Namibia by two different majors (Total Energies and Shell), on the conjugate margin of AREA OFF-1, and we were thus keenly interested in the outcomes. As it turns out, in both cases the drill results, which became known in February 2022, were what have been described as "mega-discoveries".

This in turn has unleashed a huge amount of industry interest over the past few months not only offshore Namibia, but also offshore Uruguay and northern Argentina, because the successful Namibian wells have de-risked the potential presence of a high-quality, oil-prone source rock and charge on the western sides of the South Atlantic margin. The Uruguayan basin has thus become, almost overnight, an emerging industry "hotspot". For AREA OFF-1 in particular, the chance of eventual success has increased significantly, with multiple leads and prospects and a resource potential in excess of 1 billion barrels.

Of course, it is perfectly understandable that shareholders might be sceptical, given the recent exploration experiences in The Bahamas and Trinidad. However, Uruguay is a different asset in both below and above ground profile, and success or failure in one location is not indicative of the potential of another entirely independent play or drill prospect. More than that, the early proof is that in May 2022 Shell and APA (a division of Apache) both bid for and were awarded licences in Uruguay - including AREA OFF-2 which is directly adjacent to AREA OFF-1. But whereas our minimum work obligation, as set in 2020, was modest, Shell and APA have committed to spending more than US$200 million on their Uruguayan acreage in the coming years. Clearly, therefore, we are not the only ones who see great promise in Uruguay.

Finally, it is also worth noting that our early entry, first-mover strategy for Uruguay is different to previous ventures, in that we are going to seek a partner very early in the asset life cycle, so that the Group does not bear all of the financial risk. We have already seen strong interest in potential partnering arrangements from multiple parties, and we will update shareholders as matters develop.

ESG

At Challenger Energy, achieving our commercial objectives will never be at the expense of harm to people or the environment - this is a non-negotiable principle of how we do business. Moreover, as a participant in the international energy industry, everything we do depends on what is sometimes described as the "social licence to operate": the way in which our activities and operations impact on our employees, stakeholders, host Governments, regulators, the communities in which we live and work, and the environment. Maintaining consistently excellent performance in relation to what is nowadays generally referred to as ESG (Environmental, Social and Governance) has become critical for many businesses in the modern world, not just because it is a moral duty, but because it makes good business sense.

The Group thus devotes a considerable amount of focus to this area, every day. We have full-time staff committed to ensuring strong ESG performance, overseen at Board level by a Health, Safety, Environment & Security (HSES) Committee. This Committee meets regularly to ensure adequacy of and compliance with standards, processes, systems and procedures. Beyond this, we seek to embed ESG awareness into every aspect of the business, and every person who works at Challenger Energy, no matter their seniority, role or location, is required as a condition of their job to participate actively in various ESG-related activities - things as diverse as crisis management simulations, daily safety briefings, diversity training, and anti-bribery and corruption seminars.

The results of this commitment to ESG as a business priority have been evident. As already noted, during 2021 the Group operated two substantial and complex drilling campaigns, in two different countries, and at the peak of the pandemic. Both drilling campaigns were completed without any incident - whether personal injury, property damage or environmental. More generally, the Group's operations throughout 2021, routine and non-routine, took place without the occurrence of any Lost Time Incidents, and in the same period we saw a marked improvement in staff morale and the manner in which external stakeholders viewed and engaged with the Group. We were especially pleased, after an extensive audit process, to be awarded Safe to Work (STOW) accreditation for the first time. This certification is local to Trinidad and Tobago, and is only given to companies that are adjudged to possess a world-class, robust and functional HSES Management System.

There is always room for improvement in the area of ESG, and over the coming year we will continue to seek out ways to do even better, as well as formalise a structure for setting ESG goals and then tracking and reporting against those goals. Overall, however, I believe that shareholders should be pleased with the Group's ESG performance and track record in 2021. Further details in relation to ESG are set out on page 11 of this Annual Report.

Corporate Restructuring

As noted, the two wells drilled during the first half of 2021 were both completed safely and without incident, and advanced our technical understanding of the relevant reservoirs, thus providing key inputs for consideration of future activity plans which in the long-run we hope will yet offer value creation opportunities. However, I do not wish to sugar-coat the fact that neither of the wells were the immediate success we had been hoping for. Perseverance-1 did not prove commercial volumes of hydrocarbons, Saffron-2 was not able to achieve sustained production from the deeper Cruse reservoir units that we were targeting and the final cost of both wells was considerably higher than anticipated pre-drill.

These were clearly not the outcomes longstanding shareholders (myself included) had been hoping for. But, as I have commented before, this is the risk assumed when investing in the oil and gas exploration business. Companies with significant exposure to exploration outcomes will inevitably face adverse business and financial consequences if those outcomes are below expectation.

In our case, the below expectation outcomes of the two successive drills meant that in my initial few months as CEO (I assumed the role in June 2021), the priority became to initiate a difficult but necessary Group restructuring process.

First, we engaged in a dialogue with various contractors and creditors, reaching common agreement with almost every contractor and creditor whereby each agreed to accept a discounted payment in final settlement for work undertaken on the drilling campaigns. Second, we worked to reshape our operations and reduce the overhead costs of the business - ultimately by approximately 80%. Third, as mentioned previously, we refocused the business strategy so as to prioritise our producing assets in Trinidad and Tobago. And fourth, we brought in fresh capital.

The overall process took some time to complete, but in March 2022 we successfully closed a fundraising of approximately

US$10 million, which allowed us to complete the restructure, clean up the balance sheet and put the Group into a position where

it was largely free of financial debts, and able to fund planned activities during 2022.

As we wrapped up the restructuring process in March 2022, a number of members of the Board and executive ceased in various roles, Iain McKendrick joined as our new Non-Executive Chairman, and several key hires, especially in support of our operations in Trinidad and Tobago, took effect. We also changed our corporate broker and "revamped" many of our longstanding corporate advisory and services relationships, in pursuit of further operating efficiencies and cost reductions.

Finally, it is worth mentioning that through the restructuring process we were able to attract a number of larger shareholders to our register, such that as at the date of this report approximately 45% of the Group's shares are now held by a relatively small group of shareholders and management (including myself).

2022, 2023, and Beyond

In summary, 2021 can largely be described as having been a year of two distinct parts for the Group: the first half of the year dominated by active exploration and appraisal drills in The Bahamas and then Trinidad; and directly following on from that, the second half of the year (and into the first half of 2022), dominated by the work needed to "reset" the Group based upon the outcomes of those drilling activities.

We have come through that now, and Challenger Energy's go-forward business strategy is guided by a simple objective: to focus on production, to manage costs tightly, and to thereby grow cashflow from the Trinidadian operations. At the same time, we will seek to maximise value of the other exploration assets by introducing strategic partners as early as possible.

In pursuit of this objective, during 2021 we made strong progress operationally, and the business today is leaner, more responsive, and unburdened of legacy issues. We have also undoubtedly benefitted from the rising oil price environment, such that our operations in Trinidad & Tobago have reached a point where they are largely self-sustaining.

This improved operational position has also provided the platform on which we can work towards a broader goal: the Group as a whole generating positive operating cashflow. Achieving this goal will require being able to drive an increase in production from current levels, a task which has been a work-in-progress to-date, and which work will continue into 2023. As noted in my report above, this is not a simple technical "nut" to crack, given that the fields we have are mature, and production is often disrupted for reasons we cannot always control (wells go offline, power supplies get disrupted in inclement weather, etc). We have, however, been seeing good initial results from the work we are doing to maintain and optimise field performance, and we have outlined a plan for further field improvements, new well drilling and various Enhanced Oil Recovery (EOR) initiatives over the coming 12 months, so we remain hopeful we will get there.

We also expect that the next 12 months will be a defining time for our asset in Uruguay, and which I hope might provide an unexpected upside surprise for shareholders. As mentioned before, the industry we operate in is cyclical, and the cycle appears to once again be turning, with interest in high-quality exploration prospects on the increase. We should be a prime beneficiary if this trend continues.

Finally, I would like to take this opportunity to thank all those Board members, employees and consultants who made a contribution to Challenger Energy - in some cases over many years - but who, as a result of the restructuring during 2021, are no longer with the Group. We are grateful for your past efforts. I would also like to extend my sincere thanks to all of our continuing staff, who have given 100% at all times. And collectively, all of us who work at Challenger Energy wish to express our deep appreciation for the patience and support we have received over the past 18 months, from stakeholders, regulators, suppliers, contractors and especially our shareholders, old and new.

Eytan Uliel

Chief Executive Officer

29 September 2022

Assets Summary

Trinidad and Tobago

The Group has five producing fields and one dormant field, all onshore Trinidad and Tobago. Across the fields there are a total of approximately 250 wells, of which approximately 80 are in production at any given time. The Group also has a large licence position in the South-West Peninsula of Trinidad (SWP), with a potential shallow development project at the Bonasse licence (based on the outcomes of the Saffron-1 and Saffron-2 wells drilled in 2020 and 2021 respectively), and several exploration prospects identified in the SWP more broadly.

Goudron Field

The Group owns and operates 100% of the Goudron field by way of an enhanced production service contract ("EPSC") with Heritage Petroleum Company Limited ("Heritage"), the Trinidadian state-owned oil and gas company. The current terms of the EPSC runs until 30 June 2030. Within the field, regular well workover operations are undertaken on the existing production well stock, including well stimulation operations, reperforations, and repairs to shut-in wells, as and when appropriate. The Group has identified certain well recompletion opportunities (perforating potential oil-bearing zones previously not produced) and is undertaking a comprehensive well optimisation and swabbing programme with the objective of achieving production stability, growth and longevity, as well as reducing overall field operating costs. The Group is awaiting approvals for a planned water injection enhanced oil recovery pilot project focused on repressuring reservoir units.

Inniss-Trinity Field

The Group owns and operates 100% of the Inniss-Trinity field by way of an incremental production service contract ("IPSC") with Heritage. The IPSC has been extended to 30 September 2022 on an interim basis to allow for ministerial consent required for execution of a fresh EPSC effective 1 January 2022 and expiring on 30 September 2031. Within the field, regular well workover operations are undertaken on the existing production well stock, including well stimulation operations, reperforations, and repairs to shut-in wells, as and when appropriate. As with the Goudron field, the Group has identified certain well recompletion opportunities and is undertaking a comprehensive well optimisation and swabbing programme with the objective of achieving production stability, growth and longevity, and reduced field operating costs. During 2020 and 2021, a CO2 enhanced oil recovery pilot project was undertaken on the field and the Group continues to undertake technical work to evaluate potential to undertake further CO₂ projects in other parts of the field.

South Erin Field

The Group owns and operates 100% of the South Erin field by way of a farm-out agreement with Heritage. The farm-out agreement has been renewed until 31 December 2023 and is extendable up to 30 September 2031 subject to work programme completion. The Group is in the process of defining a well drilling programme targeting additional production from undrained reservoir compartments, and that would satisfy the work programme requirements necessary for extension of the farm-out agreement.

Southwest Peninsula (SWP)

The SWP contains the Bonasse and Icacos producing oilfields, in which the Group holds a 100% operated interest via a number of private leases covering the Bonasse, Cedros and Icacos licence areas. Similar to other fields, regular well operations are undertaken on the existing production well stock and repairs to shut-in wells, as and when appropriate. The Saffron-1 and Saffron-2 wells were drilled in the Bonasse licence area during 2020 and 2021, respectively. Both wells primarily targeted the Lower Cruse reservoir horizons and while production could not be sustained from these Lower Cruse horizons, both wells yielded valuable data on the commercial viability of production from the shallower Upper Cruse and Middle Cruse horizons. Accordingly, the Group is presently evaluating the potential for a shallow field development plan.

Cory Moruga Field

The Group owns 83.8% of the Cory Moruga licence and is the operator, alongside its partner Touchstone Exploration Inc. which holds a 16.2% non-operated interest. The Cory Moruga field is presently not in production. The Cory Moruga licence includes the Snowcap oil discovery, with oil having previously been produced on test from the Snowcap-1 and Snowcap-2ST wells (but rapidly declined when the wells were put on production). The Group has formally written to the Trinidadian Ministry of Energy and Energy Industries ("MEEI") proposing a programme of further appraisal work conditional on past dues being waived and annual licence fees being rebased to an appropriate level. To the extent a suitable arrangement of this nature cannot be agreed with MEEI, the Group intends to surrender the licence.

Suriname - Wag naar Zee Project

The Group holds a 100% interest in a Production Sharing Contract ("PSC") with Staatsolie Maatschappij Suriname N.V, the Suriname state-owned petroleum company ("Staatsolie"), for an onshore appraisal / development project contained in the Weg naar Zee Block ("WNZ"). The PSC has a 30-year term with the initial exploration period expiring in October 2022. The Group has applied to extend the initial exploration term for a period of 18 months given disruptions occasioned by the Covid-19 pandemic, and confirmation of such extension is pending.

WNZ is a large block covering approximately 900 km² in a proven hydrocarbon province with 70 historical wells and 2D seismic coverage. Up to 24 MMbbls STOIIP (15° API) has been identified in eight pools with the CPR assessing 2C resources of 1.1 MMbbls and 3C resources of 3.5 MMbbls.

The Group is currently working with Gaffney, Cline & Associates to review the available technical information pertaining to the WNZ block and redesign an extended well test accordingly, which is likely to include a horizontal pilot well along with the potential use of certain enhanced oil recovery techniques, so as to maximise production and oil recovery from the reservoir.

Uruguay

The Group holds a 100% working interest in and is the operator of the AREA OFF-1 block, offshore Uruguay. AREA OFF-1 was awarded in June 2020, and formally signed on 25 May 2022. The licence has a 30-year tenure with the first four-year exploration period having commenced on 25 August 2022.

The AREA OFF-1 block covers a total area of 14,557 km² and is situated in water depths ranging from 20 to 1,000 metres, approximately 100 kms off the Uruguayan coast. The Group's minimum work obligation during the initial four-year exploration period is to undertake relatively modest and low-cost reprocessing and reinterpretation of selected historical 2D seismic. There is no 3D seismic or drilling obligation in the initial phase. The relatively modest level of work required in the initial licence phase reflects the first-mover advantage gained by the Group in applying for its Uruguay acreage based on perceived technical merit in April 2020, notwithstanding the then uncertain potential longer-term impacts of the Covid-19 pandemic.

The prospect and lead screening undertaken by ANCAP, the Uruguayan oil and gas regulatory body, includes the specific identification of the syn-rift Lenteja prospect on AREA OFF-1 with a P50 estimated ultimate recovery volume (EUR) of 1.359 billion barrels of oil and, located in just 80 metres of water depth. This volume estimate is consistent with the Group's internal estimate.

The AREA OFF-1 play system is directly analogous to the recent prolific, conjugate margin discoveries made offshore Namibia by TotalEnergies (Venus well) and Shell (Graff well), where reported multi-billion-barrel Cretaceous turbidite reservoirs have been encountered. The AREA OFF-1 licence exhibits the same Aptian play source rock as these Namibia discoveries with similar petroleum systems present and hence the AREA OFF-1 is thought to be analogous with these recent discoveries.

More recently, on 23 June 2022, ANCAP announced that three further offshore blocks had been awarded - two to Shell (including one block directly adjacent to the Group's AREA OFF-1 block) and one to APA (a division of Apache). Both awards have been granted with substantial minimum work obligations, as announced by ANCAP to be over US$200 million in aggregate between the 3 blocks.

The Group has recently licenced 2,000 kms of legacy 2D seismic data and commenced reprocessing of this data. This work would allow for the Group to undertake geological and geophysical studies, identify specific leads and prospects, update the resource assessment, and thus complete all of the minimum work obligation for the entire first four-year exploration term by early 2023. In parallel, the Group is considering early-stage partnership possibilities for the AREA OFF-1 licence, with a view to expediting 3D seismic acquisition and processing work.

The Bahamas

The Group is the 100% owner of four conjoined exploration licences offshore The Bahamas. The Perseverance-1 exploration well was drilled in the licence area, from 20 December 2020 to 7 February 2021, at a location approximately 20 miles from the Bahamas-Cuba maritime border, in water depth of approximately 518 metres. Perseverance-1 represented the first exploration drilling in The Bahamas since the mid-1980s, and the first test of any prospect located in deeper waters off the shallower water carbonate banks.

The well reached a depth of 3,905 metres, having intersected five Albian, Upper Aptian, and Mid-Aptian horizons of interest but did not result in a commercial discovery at the drilling location. Notwithstanding the outcome of Perseverance-1, a number of other structures and drill targets remain prospective across the licence areas, and the technical findings from Perseverance-1 indicate the potential of deeper Jurassic horizons - all of which might merit further exploration activity in the future. As such, the Group is considering partnering opportunities for any potential next phase of activity in The Bahamas. In parallel, in March 2021, the Group notified the then Government of The Bahamas of its intent to renew the licences into a third 3-year exploration period. A new Government was elected in The Bahamas in September 2021, and the Group is engaging with the administration on the renewal process.

Reserves and Resources

In late 2020, the Group commissioned an independent Competent Person's Report ("CPR") from ERC Equipoise ("ERCE"). The scope of the report was to focus on reserves and resources across the Group's producing assets in Trinidad and Tobago, and the Group's Weg naar Zee licence in Suriname. ERCE certified net 2P reserves of 1.29 MMbbls and net 2C contingent resources of 7.46 MMbbls across the portfolio of assets in Trinidad and Suriname, summarised as follows:

Reserves (MMbbls)1	1P	2P	3P
Total as of 30 September 20203	0.69	1.29	1.92
Contingent Resources (MMbbls)2	1C	2C	3C
Total as of 30 September 20203	0.71	7.46	24.70

Remaining Estimated Ultimate Recoverable

The CPR also included the Remaining Estimated Ultimate Recoverable ("Remaining EUR") volumes, without considering economic limit and excluding contingent resources, across the Group's five producing fields as of 30 September 2020 at low, best and high levels of confidence. An aggregate summary of the Remaining EUR volumes as of 30 September 2020 as per the ERCE CPR and the Group's internal estimate of Remaining EUR volumes as of 31 December 2021, after adjusting for production from October 2020 to December 2021, are summarised below:

Remaining EUR (MMbbls)4	High (1P)	Best (2P)	Low (3P)
Total Remaining EUR as of 30 September 20203	0.97	1.69	2.69
Less: Production for the period from 1 October 2020 to 31 December 2021	(0.17)	(0.17)	(0.17)
Estimated Remaining EUR as of 31 December 20215	0.80	1.52	2.52

Notes

1.  Group Working Interest reserves are based on the working interest share of the field gross resources and are prior to deduction of royalties but after applying economic cut-off. Challenger Energy hold a 100% interest in all relevant fields, being Goudron, Inniss-Trinity, South Erin, Icacos and Bonasse in Trinidad, and Weg naar Zee in Suriname.

2.  The Contingent Resources are on unrisked basis and have not been risked for chance of development and are sub-classified as development unclarified.

3.  Totals are added arithmetically which means statistically there is a greater than 90% chance of exceeding the total IP or 1C and less than a 10% chance of exceeding the total 3P or 3C.

4.  Remaining Estimated Ultimate Recoverable volumes are volumes estimated to be technically recoverable from the existing wells across the five producing fields. These estimates do not consider economic limit and exclude contingent resources. High (1P), Best (2P) and Low (3P) represent level of confidence.

5.  Estimated Remaining EUR as of 31 December 2021 is the Group's internal estimate of volumes based on volumes estimated in the CPR as of 30 September 2020 reduced by the volume of production for the period from 1 October 2020 to 31 December 2021. This estimate is not certified by ERCE and has not been included in the CPR.

6.  ERCE did not audit the Group's prospective exploration acreage in the South West Peninsula of Trinidad as part of its CPR.

2P reserves relate to known oil that is capable of being produced economically, and thus the 2P reserves as certified by ERCE relate solely to production capable of being generated from the Group's existing wells in existing fields. The 2P reserves do not assume any contribution from infill drilling and enhanced oil recovery projects. Moreover, apart from routine operating costs required to keep wells online, accessing this production potential does not require material amounts of incremental capital expenditure.

At oil prices ranging from US$60 to US$90 per barrel, it is estimated this level of 2P reserves represent US$75 million to

US$120 million of gross cashflow potential to the Group, and a reserve base equivalent to a baseline production of 400 bopd for approximately nine years.

Environmental, Social and Corporate

Governance Report

In recent years, many businesses, including those operating in the energy industry, have seen an emerging need to develop strategies relating to, and then monitoring and reporting performance against, a diverse range of business activities that collectively are commonly referred to as Environmental, Social and Corporate Governance, or "ESG". In broad terms:

· Environment relates to considerations of the impact that a company's business has on the natural environment, and how to best minimise / manage that impact. Relevant areas include the energy a company utilises in conducting its business, the waste it produces, the resources it needs, and the consequences of its operations in terms of emissions, waste, water, biodiversity and climate change.

· Social relates to the manner in which a company seek to discharge its broader social obligations, including those owed to its employees, external stakeholders, and the communities in which it operates. Relevant areas include employee engagement and training, diversity and inclusion, labour relations, and community involvement and development.

· Governance relates to the controls and procedures a company adopts to govern itself. Examples of relevant governance areas include considerations of board composition, how a company's board functions in practice, and preventing bribery and corruption.

Set out below are details of Challenger Energy's ESG Philosophy and Management framework, approach to Corporate Governance and certain other ESG related areas, as well as selected ESG Highlights from 2021.

ESG Philosophy and Management

At Challenger Energy, we believe that pursuit of commercial objectives should never be at the expense of harm to people, community or the environment.

We believe that we have a responsibility for, and owe a duty of care to, the people who work for us, the contractors and suppliers that work alongside us in our operations, and the broader communities in which we live and work. We take all steps possible to safeguard the health, wellbeing and personal safety of all involved with us as we deliver our operational projects. Our objective is for zero lost time injuries or incidents.

At all times Challenger Energy seeks to conduct its business with integrity and high ethical standards, and foster a working environment of respect for all employees. We wish to see the personal and professional development of our people in the roles that they perform for us. Our objective is to create a working environment that supports our people while challenging them to deliver their best and to develop their own skills and experiences.

We recognise the importance of diversity to our business, which may relate to gender, nationality, faith, personal background and other factors. We value how diversity benefits our business and how the individual experiences of our people contribute to a positive environment in the Group. We are committed to promoting an environment where our people learn and develop in a collaborative manner, regardless of who they are.

Challenger Energy operates in a number of international locations, and we both depend on and impact the people and institutions in those places. Our business does not exist in a vacuum, and we are part of the societies we operate in. We recognise and respect the dignity of all human beings and seek to improve the life of the communities in which we function. Our commitment is to be a responsible business and good corporate citizen, making a meaningful contribution to the places in which we live and work.

We are very conscious of the natural environment that we operate in, and we work hard to minimise our impact on that environment. The Group is committed to the responsible stewardship of the environment and at all times we seek to operate safely and responsibly. During operations we maintain work procedures and field access infrastructure to minimise encroachment on the environment, and we remain alert at all times to potential environmental hazards and incidents that can result from our operations, as well as having clear and tested response protocols should any incidents occur. At the conclusion of our operations, we return our sites to the condition in which we found them. Our objective is for zero environmental incidents and zero spills or leaks.

Recognising ESG as a core business priority, the Group maintains a structured Health, Safety, Environment & Security (HSES) Management System. This comprises a documented set of policies, procedures and practices with Company-wide application, designed to promote and foster excellence in all relevant areas of HSES. The HSES Management System is reviewed periodically, and was substantially revised and updated in early 2021, the focus of doing so being to ensure that a functional system, tailored to the needs of the Group's operations, is in place and operating effectively at all times.

A central component of the HSES Management System is the HSES Working Group, which comprises Board members, senior executives, and representatives from all levels of operations. The HSES Working Group functions without hierarchy, and meets weekly to ensure adequacy of and compliance with HSES standards, processes, systems and procedures. The HSES Working Group operates independently from, and reports to, the formal HSES Committee of the Board of Directors (as described under Corporate Governance, below).

Corporate Governance

Challenger Energy operates in the energy sector, a global industry that is typically subject to strict laws and rules and regulations imposed by host Governments and international regulators, as well as intense public scrutiny given the essential nature of the product we supply and the risks associated with that supply. Additionally, the Group's shares are traded on the AIM Market of the London Stock Exchange, and the Group is thus subject to various additional rules and regulations associated with being a publicly traded entity.

Accordingly, the Board is committed to maintaining the highest standards of corporate governance at all times.

QCA Code

Pursuant to applicable rules of the AIM Market of the London Stock Exchange, the Group is required to apply a recognised corporate governance code, and demonstrate how the Group complies with such corporate governance code and where it departs from it. Given that the Group is not subject to the requirements of the UK Corporate Governance Code, the Directors of the Group have decided to apply the QCA Corporate Governance Code (the "QCA Code") as the standard against which the Group chooses to measure itself.

The QCA Code emphasises the need for well balanced, effective boards, with a strong emphasis on overseeing risk management aimed at protecting the Group from unnecessary risk to enable the Group to secure its long-term future. In addition, the QCA Code highlights the alignment of remuneration policies with shareholder interests and sound shareholder relations. Further information on the Group's application of the QCA Code is available on the Group website at www.cegplc.com .

The Board and its Committees

The Board of Directors

The Board meets regularly to discuss and consider all aspects of the Group's activities. A Charter of the Board has been approved and adopted which sets out the membership, roles and responsibilities of the Board. The Board is primarily responsible for formulating, reviewing and approving the Group's strategy, budgets, major items of capital expenditure and acquisitions. The Board currently consists of the Chairman, the Chief Executive Officer, and two Non-executive Directors. All Directors have access to the Company Secretary and the Group's professional advisers.

Records of the board meetings

There were 14 board meetings of the parent entity of the Group during the financial year.

Audit Committee

The Audit Committee of the Board comprises Stephen Bizzell (Chair) and Iain McKendrick, with input as required from the Chief Financial Officer. The Audit Committee is primarily responsible for ensuring that the financial performance of the Group is properly reported on and monitored, for reviewing the scope and results of the audit, its cost effectiveness and the independence and objectivity of the auditor. The Audit Committee has oversight responsibility for public reporting and the internal controls of the Group. A Charter of the Audit Committee has been approved and adopted which formally sets out the membership, roles and responsibilities of the Audit Committee. All members of the Audit Committee have access to the Company Secretary and the Group's professional advisers, including in particular direct access to the Group's auditor. The Audit Committee meets on a regular basis, and in 2021 met on four occasions, with all members being present for all meetings.

Remuneration & Nomination Committee

The Remuneration & Nomination Committee comprises Simon Potter (Chair), Iain McKendrick and Eytan Uliel. The Remuneration & Nomination Committee is responsible for making recommendations to the Board of Directors regarding executive remuneration packages, including bonus awards and share options, and assisting the Board in fulfilling its responsibilities in the search for and evaluation of potential new Directors and ensuring that the size, composition and performance of the Board is appropriate for the scope of the Group's and Company's activities. It is recognised that shareholders of the Group have the ultimate responsibility for determining who should represent them on the Board. The Remuneration & Nomination Committee meets on an as-required basis, and in 2021 met on two occasions, with all members being present for all meetings.

Health, Safety, Environmental and Security Committee

The Board has a Health, Safety, Environmental and Security (HSES) Committee which currently comprises Iain McKendrick (Chair), Simon Potter and Eytan Uliel. The Committee's purpose is to assist the Directors in establishing ESG strategy and reviewing, reporting and managing the Group's performance, to assess compliance with applicable regulations, internal policies and goals and to contribute to the Group's risk management processes. The HSES Working Group reports to the HSES Committee, which meets on a regular basis. In 2021 the HSES Committee met on 11 occasions, with all members being present for all meetings.

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

The Directors have prepared a cash flow forecast which anticipates the Group and Company being able to continue in operation for at least the next twelve months from the date of this report. The forecasts include certain assumptions and underlying estimates. Certain of these items are outside of the Group and Company's control and unfavourable actual outcomes may materially and adversely affect the Group's cash resources and cast significant doubt about the Group and the Company's ability to continue as a going concern, as further detailed in the independent auditor's report. Further information regarding the appropriateness of the use of the going concern assumption in the basis of preparation can be found in note 1 to the consolidated financial statements.

Anti-bribery and corruption ("ABC")

Challenger Energy applies a zero-tolerance policy for bribery, corruption or unethical conduct in our business. Our policies require compliance across our businesses with applicable ABC laws, in particular the UK Bribery Act 2010, and all applicable laws in other jurisdictions in which we operate. We have a system of documented ABC policies and procedures in place that provide a

consistent policy framework across the Group to ensure awareness of potential threats among our employees and help to ensure appropriate governance of ABC matters. In 2021, all employees across the Group were required to attend mandatory ABC training, with a focus on the areas of legislation most relevant to the Group.

Anti-Money Laundering ("AML")

Challenger is conscious of the risks arising out of money laundering and terrorist financing. These criminal activities threaten society, as well as the Group, its partners, shareholders, and staff. The Group is committed to fighting these threats by harnessing the strength of the Group and its associates. The Group exercises the utmost vigilance wherever its operations are taking place. This vigilance extends to third party associates who are at any time active in the Group. Annual AML training is compulsory for Group staff, and during 2021, over 100 anti-money laundering training courses were taken by various employees and contractors.

Taxation

Depending on the jurisdiction of operation, the Group is subject to a range of taxes, including corporate income tax, supplemental petroleum taxes, royalties, other fiscal deductions, VAT and payroll taxes, amongst others. We are a responsible operator and corporate citizen and the Group is committed to adhering to all relevant tax laws in all jurisdictions of operation: compliance with tax laws and regulations is fundamental to our licence to operate, and is an obligation that we take seriously.

2021 ESG Highlights

Challenger Energy intends to adopt a formalised ESG monitoring / reporting framework in 2023. However, the diverse aspects that comprise ESG have always been treated as business priorities for Challenger Energy, and thus ESG awareness, performance culture and accountability is already embedded across the Group. It is a core principle of how we do business that the pursuit of ESG excellence should not just be an aspirational statement, but rather should manifest daily in tangible actions and activities, with measurable impact, across every aspect of the Group's business.

During 2021, all Group policies and procedures were reviewed and updated, and a comprehensive business continuity plan was prepared and adopted. In addition, key ESG-related themes of specific relevance to the Group's expanded operations were selected for emphasis throughout the year. These themes were (i) behavioural safety, (ii) training, (iii) Covid-19 management, and (iv) the environment.

Specific ESG-related highlights of note from 2021 are:

· There were no Lost Time Incidents recorded in 2021 in any of the Group's operations, both routine and non-routine. This exemplary track record has continued into 2022 - from the start of January 2022 to the date of this report, no Lost Time Incidents have been recorded in any of the Group's operations.

· Two complex drilling campaigns were carried out during 2021 - the Perseverance-1 well offshore The Bahamas, and the Saffron-2 well onshore in Trinidad. Both drilling campaigns were executed safely and responsibly, without any incidents or harm to people or the environment, and in full compliance with all applicable laws, regulations and international standards.

· It is a requirement by Heritage Petroleum Company Limited, the Trinidadian state-owned oil & gas company, that all contractors and operators are Safe-To-Work ("STOW") certified. Challenger Energy underwent the requisite STOW audit process in February 2021 and attained accreditation for a 2-year period in August 2021. Being independently accredited was a milestone event for the Group.

· In 2021, the Group obtained all relevant approvals from NIMOS, the Surinamese environmental regulator, for the drilling of an initial test well in Suriname (albeit the drilling did not subsequently proceed, owing to the impact of the pandemic). Similarly, the Group had previously (in 2020) obtained Environmental Approval ("EA") for the drilling of Perseverance-1 in The Bahamas. In early 2021 the Group vigorously defended a legal challenge that had been brought in The Bahamas seeking to halt the drilling programme on the basis of alleged inadequacies of the EA. Drilling proceeded and the legal challenge was ultimately dismissed in May 2021, reflecting the robust, world-class work undertaken by the Group in preparing the EA over a period of more than 2 years. 3

· In terms of field operations, three areas of specific relevance to the Group's operations were selected for focus during 2021. These were:

o  water disposal : the Group's activities result in production of a considerable volume of water, which prior to release into the environment undergoes treatment to ensure it is free of contaminants, so as to minimise harm to the environment. A programme was initiated to evaluate the potential for unused well within the producing fields to be reassigned as water disposal wells, which (subject to regulatory approval) would enable produced and treated water to be injected back into the ground, and thus not discharged into the natural environment at all. Evaluation is ongoing, with the expectation is that initial water reinjections might commence in 2023;

o  field energy efficiency : a field-wide programme was implemented to introduce more sustainable and efficient pumps. The impact was a measurable impact in well runtimes and uptimes for relevant wells, and a measured 5% increase in energy efficiency; and

o  roads : a road audit was undertaken, resulting in various road repairs and improvements initiated across the Group's Trinidad portfolio. Road repair and improvement allows for greater operating efficiencies, as well as reducing driver fatigue, wear and tear of vehicles and carbon emissions, and rig movements.

· Challenger Energy's goal is to operate with zero environmental incidents. During 2021 there was one environmental incident, which was occasioned as a result of illegal dumping of waste hydrocarbon substances by third parties in one of the Group's site pits at an operating field in Trinidad. Adverse weather in the area led to the pit overflowing, and a number of nearby residences being affected by oil contaminated floodwaters. Notwithstanding that the incident arose as a result of illegal third-party activity, because it involved the Group's assets the incident was managed in accordance with the Group's incident response and contingency plans. This included the Group arranging for clean-up of all affected residences, and care packages being distributed to affected people. Heritage and all relevant regulatory agencies in Trinidad were informed, a number of post incident site visits were conducted, and the measures taken by the Group in response to this incident was found to be satisfactory, with no residual environmental impact.

· The Group's HR focus in 2021 was to ensure a competent and trained workforce, reflecting the increased scope of the Group's activities in the period. This involved a systematic programme of internal and external meetings, engagements and formal training programs, including a number of sizeable incident response simulations, mandatory attendance at various training events, and the roll-out of various initiatives specifically targeting practical areas of concern. This included internal awareness sessions conducted in the areas of risk assessment and job safety analysis, oil spill response, permit to work, management of change and incident reporting and investigation. Additionally, external training sessions were provided to employees in Defensive Driving, First Aid and CPR, Fire Warden and Well Control. The Group exceeded almost all internal-set metrics established in relation to engagement and training. For example, the Group has an internal goal to undertake one "toolbox talk" safety briefing per day, or a target of 365 each full year. During 2021, a total of 665 such toolbox talks were conducted.

· In terms of community engagement, the focus in 2021 was to assist with ameliorating the impacts of the pandemic in local communities in which we operate. In Trinidad, this took the form of the Group participating in a programme of computer equipment donation in the Guayaguayare, Moruga and Southwest Peninsula areas, to enable online schooling during the pandemic for children whose families would otherwise have been unable to afford the equipment. In The Bahamas, the Group provided aid to a number of families severely impacted as a result of Covid-19 lockdowns, in the form of emergency food supplies and rental assistance.

· More broadly, the Group has continued throughout to support local education and community service, in addition to social and community cash contributions required as conditions of the Group's various licences. Tangible support initiatives have included Christmas Hamper donations to families in need in more remote areas of Trinidad, a donation to the Mayaro Past Pupils Association towards their SEA Awards and Back to School Initiative, the sponsorship of two students pursuing Master of Science and Public Health degrees in Suriname, the sponsorship of an MBA and LLB Admission to Bar in The Bahamas, and the support (both in terms of time and money) of UK-based staff participating in the UK Army Reserves.

· In relation to Covid-19, throughout 2021 stringent protocols were implemented on a Group-wide basis focused on social behaviours and interaction in the workplace, and covering all field staff and office-based staff. Working from home was encouraged where possible and clear protocols were put in place for instances when symptoms were identified or suspected. Specific Covid-19 protocols enabled uninterrupted operations throughout 2021, including during the two drilling campaigns in the first half of the year. A concerted effort was made to encourage vaccination across the Group, with the Company-wide vaccination rate as at the end of 2021 approximately 80%, well in excess of national averages in jurisdictions of operation.

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 targeted development activity across the existing portfolio together with selective acquisition activity to grow the asset portfolio.

The Group's current production is derived from later-life production assets that are in the latter portion of the production decline curve.

Potential impact: High  Probability: Moderate

Risk appetite

The continued 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 ultimate success of the Group is based on its ability to maintain and grow production from existing assets and to create value through targeted development activity across the existing portfolio together with selective acquisition activity to grow the asset portfolio.

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

Mitigation

The Group's current production derived from later-life production assets that are in the latter portion of the production decline curve. 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 is undertaken periodically by an independent petroleum engineering firm.

The recently appointed country manager for Trinidad is a qualified reservoir engineer with significant Trinidad and other international experience, having previously worked with a major international reservoir engineering firm for more than 15 years.

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 will selectively add new development or production onshore Trinidad or elsewhere in the Atlantic margin through

specific and M&A activity or partnering arrangements with drilling contractors related to the existing Trinidad fields.

The Group holds an appraisal / development asset in Suriname that is related to an existing production area. Development options for the asset remain under consideration and may involve farm-out of a portion of the asset as a method of financing. The development of Suriname, if successful, will mitigate this risk.

In addition, the Group holds an exploration licence in Uruguay that is on the conjugate margin of recent significant discoveries by both Shell and TotalEnergies offshore Namibia. Progressing work in Uruguay will likely include some form of partnering, for instance through farm-out, to share risk and bring additional experience and financing to pursue higher capital work programme so as to de-risk and make the project drill-ready.

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 track record over many years of successfully raising finance to fund its activities as and when required.

Funds raised in March 2022 (the most recent capital raising) are being deployed in specific, targeted development activity including lower-risk recompletions to open new productive zoned in existing production wells. Funds are also being deployed for

the purchase of additional in-field equipment to reduce reliance on third party contractors and their availability to undertake straightforward workover activity.

The objective of the planned work is to increase production in order to move the Trinidad assets from self-sufficiency to cashflow accretive. Generating surplus cash from operations is expected to translate to additional funding options including reserve based lending and other potential alternative financing.

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 2021 Corruption Perceptions Index for the jurisdictions where the Group has presence are as below:

	2021	2021
	(2020)	(2020)
Jurisdiction	Rank	score
The Bahamas	30 (30)	64 (63)
Suriname	87 (94)	39 (38)
Trinidad and Tobago	82 (86)	41 (40)
United Kingdom	11 (11)	78 (77)
Uruguay	18 (21)	73 (71)

Potential impact: High  Probability: Moderate

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 would adversely affect the Group's profitability, cash flow, financial position, and ability to invest.

Oil sales in Trinidad are closely linked to the West Texas Intermediate (WTI) crude oil benchmark price with the realised oil price by the Group being typically at approximately 10% discount to the WTI benchmark.

In addition, the Trinidad supplementary petroleum tax regime has a regressive effect when realised oil prices are between US$75 and US$95 per barrel. This is due to SPT applying at a flat rate above the trigger oil price (presently, US$75).

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 benefit 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 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.  Impact of Covid-19 virus

The emergence of Covid-19 as a global pandemic has had a significant effect on economies worldwide and has been disruptive to

commercial and operating activity.

Potential impact: High  Probability: Moderate

Appetite

The Covid-19 virus that was first identified in China in late 2019 spread rapidly in early 2020, becoming prevalent in Europe and Asia initially, followed by North America, South America, and Africa. Almost all countries have now been affected by the virus that is extremely contagious.

The almost universal initial governmental response was one of social distancing, self-isolation and quarantine. Whilst the global roll-out of vaccines has largely mitigated the most severe consequences of contracting Covid-19, not all jurisdictions have the same level of vaccine uptake or are as advanced in their roll-out programmes as they might be.

Mitigation

The Group has strict Covid-19 protocols at all locations and operates an active isolation and test programme where Covid-like

symptoms are experienced by staff or contractors.

The Group actively encourages the take-up of vaccinations by all staff. The Group has a low appetite for risk related to Covid-19 and has contingency / business continuity plans in place in the event of another Covid-19 wave or a similar health emergency.

10.  Fiscal and political

The majority of the Group's operations are located in Trinidad and Tobago and it is therefore exposed to both in-country fiscal and

political risk. In addition, the Group has operations in The Bahamas, Suriname and Uruguay with limited activity at present.

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 in Trinidad and Tobago dollars as majority of the Group's activities are presently in Trinidad and Tobago, and Pound Sterling as a significant amount of the Group's cash holdings are denominated in Pound Sterling. Currency hedging instruments are not currently used due to the historically stable relationship between the Trinidad and Tobago dollar and the United States dollar (the functional currency of the companies comprising the Group) and unexpected recent volatility in Pound Sterling.

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. The Group interacts indirectly with the Trinidad and Tobago Government through its relationships with both the state-owned oil and gas company and the Ministry of Energy and Energy Industries. The Group does not undertake any lobbying activity with any members of the Trinidad and Tobago Government or in any other jurisdiction.

Fiscal

The currency used in Trinidad is the Trinidad and Tobago dollar (TTD) and has been relatively stable, fluctuating between

TTD 6.60 and TTD 6.80 to the US dollar during the reporting period. Similarly, Pound Sterling has been relatively stable fluctuating

between USD 1.32 to USD 1.42 to the Pound Sterling during the reporting period, however, has witnessed sharp depreciation

recently.

Political

The Group considers the jurisdictions of its operations to have low political risk. World Bank's Worldwide Governance Indicators

(2020 percentile rankings, 100 being the highest rank) for the jurisdictions where the Group has presence are set out below:

Jurisdiction	Political Stability and Absence of Violence / Terrorism	Government Effectiveness
The Bahamas	73.58	69.71
Suriname	58.96	33.17
Trinidad and Tobago	53.3	61.06
United Kingdom	61.31	89.42
Uruguay	87.74	75.00

Mitigation

Fiscal

The relationship of the TTD to the US dollar is subject of a managed float regime under which the exchange rate is actively managed by the Government of Trinidad and Tobago through currency purchases and sales. Pound Sterling on the other hand is largely a floating currency and exposed to market volatility. 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.

Political

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 the state-owned oil and gas company and the Ministry of Energy and Energy Industries in relation to its operations in Trinidad and maintains a regular and open dialogue with each. In addition, the Group interacts with the Bahamian Government in relation to the renewal of its licences in The Bahamas.

No Russian Exposure

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 2021.

Directors

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

Stephen Bizzell (appointed 1 June 2021)
Adrian Collins (resigned 25 May 2021)
Leo Koot (resigned 22 January 2021)
Ross McDonald (resigned 1 June 2021)
Simon Potter

William Schrader (resigned 5 March 2022)
James Smith (resigned 5 March 2022)
Eytan Uliel (appointed 1 June 2021)

Subsequent to the financial year under review, the following persons joined the Board of Directors:

Iain McKendrick (appointed 5 March 2022)

Timothy Eastmond (appointed 5 March 2022, resigned 15 July 2022)

Principal Activity

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

Results and dividends

The results of the Group for the year are set out on page 28 and show a loss for the year ended 31 December 2021 of $23,697,000 (2020: loss of $13,992,000). The total comprehensive expense for the year of $23,845,000 (2020: expense of $13,845,000) has been transferred to the retained deficit.

The Directors do not recommend payment of a dividend (2020: nil).

Significant Shareholders

The following tables represent shareholdings of 3% or more notified to the Company at 31 December 2021 and at the date of this report respectively:

Top shareholders at 31 December 2021 (by parent company)

Shareholder	31-Dec-21	%
Hargreaves Lansdown Asset Management	147,595,687	18.53
Interactive Investor	95,437,257	11.98
Bizzell Capital Partners	87,658,600	11.01
Halifax Share Dealing	72,591,395	9.11
Barclays Wealth	39,293,238	4.93
TOTAL	442,576,177	55.56

Top shareholders as of the date of this Report (by parent company)

Shareholder	At the date of this report	%
Bizzell Capital Partners	914,633,600	9.51
Choice Investments (Dubbo) Pty Ltd	837,000,000	8.70
Hargreaves Lansdown Asset Management	780,382,175	8.11
Mr Mark Carnegie	560,000,000	5.82
Mr Eytan M Uliel	545,373,962	5.67
Rookharp Capital Pty Ltd	528,000,000	5.49
Jarvis Investment Management	509,491,516	5.30
Merseyside Pension Fund	417,350,000	4.34
G.P. (Jersey) Ltd	390,000,000	4.05
RAB Capital Holdings Ltd	336,800,000	3.50
UBS	309,668,912	3.22
TOTAL	6,128,700,165	63.71

Directors' Shareholding and Options

The interests in the Company 31 December 2021 and at the date of this Report respectively 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.

Director	Number of Shares 31-Dec-21	Number of Options 31-Dec-21
William Schrader (resigned 5 March 2022)	2,713,138	1,800,000
James Smith (resigned 5 March 2022)	1,451,134	1,650,000
Simon Potter	12,436,472	8,750,000
Eytan Uliel (appointed 1 June 2021)	10,373,962	19,500,000
Stephen Bizzell (appointed 1 June 2021)	4,314,286	-

Director	Number of Shares date of this report	Number of Options date of this report
William Schrader (resigned 5 March 2022)	29,796,471	-
James Smith (resigned 5 March 2022)	19,159,467	-
Simon Potter	71,462,807	-
Eytan Uliel (appointed 1 June 2021)	545,373,962	340,000,000
Stephen Bizzell (appointed 1 June 2021)	51,189,286	-
Iain McKendrick (appointed 5 March 2022)	50,000,000	100,000,000

Record of Board Meetings

There were 14 board meetings of the parent entity of the Group during the financial year.

Director	Number of Board Meetings Attended	Number of Board Meetings Eligible to Attend
William Schrader (resigned 5 March 2022)	13	14
James Smith (resigned 5 March 2022)	14	14
Eytan Uliel (appointed 1 June 2021)	7	7
Simon Potter	14	14
Stephen Bizzell (appointed 1 June 2021)	7	7
Adrian Collins (resigned 25 May 2022)	7	7
Ross McDonald (resigned 1 June 2021)	7	7
Leo Koot (resigned 22 January 2021)	2	2

21

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") as adopted by the European Union. 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 as adopted by the European Union 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

29 September 2022

Independent auditor's report to the members

of Challenger Energy Group PLC

Report on the audit of the financial statements

Our opinion

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

· give a true and fair view of the state of the Group's affairs as at 31 December 2021 and of its loss and its cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the European Union;

· give a true and fair view of the state of the Company's affairs as at 31 December 2021 and of its cash flows for the year then ended in accordance with International Financial Reporting Standards as adopted by the European Union as applied in accordance with the provisions of the Isle of Man Companies Act 1982; and

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

Challenger Energy Group PLC's financial statements comprise:

· the consolidated and company statements of financial position as at 31 December 2021;

· the consolidated statement of comprehensive income for the year then ended;

· the consolidated and company statements of changes in equity for the year then ended;

· the consolidated and company statements of cash flows for the year then ended; and

· the notes to the financial statements, which include significant accounting policies and other explanatory information.

Basis for opinion

We conducted our audit in accordance with International Standards on Auditing ("ISAs"). Our responsibilities under those standards are further described in the "Auditor's responsibilities for the audit of the financial statements" section of our report.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Independence

We are independent of the Group in accordance with the International Code of Ethics for Professional Accountants (including International Independence Standards) issued by the International Ethics Standards Board for Accountants ("IESBA Code"). We have fulfilled our other ethical responsibilities in accordance with the IESBA Code.

Material uncertainty related to going concern

In forming our opinion on the financial statements, which is not modified, we have considered the adequacy of the disclosures made in note 1.28 (ii) of the financial statements concerning the Group's and the Company's ability to continue as a going concern.

As at 31 December 2021, following the difficulties experienced drilling Perseverance-1, the Group and Company had cash and cash equivalents of $1.6 million and $0.9 million and trade and other payables of $23.5 million and £10.8 million respectively. Management were in the process of restructuring the Group, which required shareholder and creditor agreement and additional fund raising.

Subsequent to the year end, the restructuring was progressed with settlement agreements for creditors and an additional $10 million (before expenses) raised through the issue of new shares. Following the restructuring, the Directors have prepared a cash flow forecast which anticipates the Group and Company being able to continue in operation for at least the next twelve months from the date of this report. However, as explained in note 1.28 (ii) the cash flow forecast includes a number of underlying assumptions and estimates. Certain of these items are outside of the Group and Company's control and unfavourable actual outcomes may lead to the Group and Company needing to take additional measures such as fund raising, cost savings or the sale of assets.

These conditions, along with the other matters explained in the notes to the financial statements, indicate the existence of a material uncertainty that may cast significant doubt on the Group's and the Company's ability to continue as a going concern.

The financial statements do not include the adjustments that would result if the Group and the Company were unable to continue as a going concern. In auditing the financial statements, we have concluded that the directors' use of the going concern basis of accounting in the preparation of the financial statements is appropriate. 3

Our evaluation of the directors' assessment of the Group's and the 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 to other external and internal sources, including the impairment assessments, where appropriate;

· assessing and validating the impact of post year end cash movements and commitments;

· 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.

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

Our audit approach

Overview

As part of designing our audit, we determined materiality and assessed the risks of material misstatement in the financial statements. In particular, we considered 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. As in all of our audits, we also addressed the risk of management override of internal controls, including among other matters, consideration of whether there was evidence of bias that represented a risk of material misstatement due to fraud.

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 period. These matters were addressed in the context of our audit of the financial statements as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

Key audit matter

How our audit addressed the key audit matter

Recoverability of the Group's intangible exploration and evaluation assets / Recoverability of the Company's investment in subsidiaries and amounts owed by subsidiary undertakings (Group and Company) Refer to notes 1.28, 10, 14 and 16 of the financial statements. At 31 December 2021 the carrying value of the intangible exploration and evaluation assets was $94.4 million (2020: $75.3 million). As the carrying value of these intangible exploration and evaluation assets are significant to the financial statements of the Group, we consider it necessary to assess whether any facts or circumstances exist to suggest that the carrying amount of these assets may exceed their recoverable amount. The Company's investment in subsidiaries holding the Group's intangible exploration and evaluation assets totalled $29.6 million (2020: $29.6 million) and the amount owed by subsidiary undertakings totalled $113.2 million (2020: $83.8 million). The recoverability of the Company's investments in subsidiaries and amounts owed by subsidiary undertakings are dependent on successful development or sale of the respective licence areas.

We critically evaluated management's assessment of each impairment trigger per 'IFRS 6 - Exploration for and Evaluation of Mineral Resources', including but not limited to: · Assessing whether the Group had the rights to explore in the relevant geographical areas by obtaining supporting documentation such as licence agreements and assessed compliance with licence conditions. · Enquiring to determine whether management had the intention to carry out exploration and evaluation activity in the relevant exploration areas. We reviewed management's cash flow forecast models to assess the level of the budgeted expenditure on these areas, and obtained details of contracts. · Critically assessing the outcome of drilling activities as to whether any impairment indicators were present to suggest that the carrying value of these exploration and evaluation assets is unlikely to be recovered through development or a sale. · Validating the capitalised costs on a sample basis for adherence with the criteria set out in IFRS 6. Having completed our work, we did not identify any material misstatements regarding the carrying value of the intangible exploration and evaluation assets and, as a result, no material issues were noted with respect to the recoverability of the Company's investment in subsidiaries and amounts owed by subsidiary undertakings.

Key audit matter

How our audit addressed the key audit matter

Recoverability of the Group's tangible oil and gas assets / Recoverability of the Company's investment in subsidiaries (Group and Company) Refer to notes 1.28, 11 and 14 to the financial statements. At 31 December 2021 the carrying value of the tangible oil and gas assets after management's impairment was $21.0 million (2020: $22.3 million). As the carrying value of these tangible oil and gas assets are significant to the financial statements of the Group, we consider it necessary to assess whether any facts or circumstances exist to suggest that the carrying amount of these assets may exceed their recoverable amount. The Company's investment in subsidiaries holding the Group's tangible oil and gas assets totalled $21.4 million (2020: $21.4 million). The recoverability of these investments in subsidiaries 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.

Our audit work included, but was not restricted to: · Assessing the impairment model prepared by management and challenging the key assumptions in the discounted value in use cash flows, remaining sceptical of explanations and obtaining supporting evidence as necessary. · Considering whether the model used was appropriate and checking the related calculations and production assumptions. · Discussing key assumptions underlying the impairment model with management and performing procedures to validate their reasonableness. · Independently determining WACC rates and comparing with management's assessment. · Reviewing projections and sensitivities including independent stress testing of key WACC, oil price, capex and decline rate assumptions. · Issuing instructions to and directing the work of the component auditor in Trinidad in relation to the audit of tangible oil and gas assets. · Holding regular meetings with and reviewing the working papers of the component auditor to ensure that sufficient appropriate audit evidence was obtained over the recoverability of the Group's tangible oil and gas assets. Having completed our work, we did not identify any material misstatements regarding the carrying value or disclosures of the tangible oil and gas assets and, as a result, no material issues were noted with respect to the recoverability of the Company's investment in subsidiaries.

Other information

The other information comprises all of the information in the Annual Report and Financial Statements other than the financial statements and our auditor's report thereon. The directors are responsible for the other information.

Our opinion on the financial statements does not cover the other information and 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 identified above 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, 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.

Responsibilities of the directors for the financial statements

The directors are responsible for the preparation of the financial statements that give a true and fair view in accordance with International Financial Reporting Standards as adopted by the European Union and Isle of Man law, and for such internal control as the directors determine is necessary to enable the preparation of financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the financial statements, the directors are responsible for assessing the Group's 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 the directors either intend to liquidate the Group and Company or to cease operations, or have no realistic alternative but to do so.

Auditor's responsibilities for the audit of the financial statements

Our objectives are to obtain reasonable assurance about whether the financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs 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.

As part of an audit in accordance with ISAs, we exercise professional judgement and maintain professional scepticism throughout the audit. We also:

· Identify and assess the risks of material misstatement of the financial statements, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

· Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group's and Company's internal control.

· Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors.

· Conclude on the appropriateness of the directors' use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group's and Company's ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor's report to the related disclosures in the financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor's report. However, future events or conditions may cause the Group and Company to cease to continue as a going concern.

· Evaluate the overall presentation, structure and content of the financial statements, including the disclosures, and whether the financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

· Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion.

We communicate with the directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide the directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, actions taken to eliminate threats or safeguards applied.

From the matters communicated with the directors, we determine those matters that were of most significance in the audit of the financial statements of the current period and are therefore the key audit matters. We describe these matters in our auditor's report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

This report, including the opinion, has been prepared for and only for the Company's members as a body in accordance with Section 15 of the Isle of Man Companies Act 1982 and for no other purpose. We do not, in giving this opinion, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

Report on other legal and regulatory requirements

Adequacy of accounting records and information and explanations received

Under the Isle of Man Companies Acts 1931 to 2004 we are required to report to you by exception if, in our opinion:

· we have not received all the information and explanations we require for our audit;

· proper books of account have not been kept, or proper returns adequate for our audit have not been received from branches not visited by us;

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

· certain disclosures of directors' loans and remuneration specified by law have not been complied with.

We have no exceptions to report arising from this responsibility.

Andrew Dunn

for and on behalf of PricewaterhouseCoopers LLC

Chartered Accountants

Douglas, Isle of Man

29 September 2022

Consolidated Statement of Comprehensive

Income

For the year ended 31 December 2021

	Note	Year ended 31 December 2021 $ 000's	Year ended 31 December 2020 $ 000's
Net petroleum revenue Cost of sales	2	4,360 (6,121)	1,417 (2,781)
Gross loss		(1,761)	(1,364)
Administrative expenses	3	(9,098)	(9,793)
Impairment charges	3/10/11	(7,416)	(2,435)
Operating foreign exchange (losses) / gains		(17)	32
Operating loss		(18,292)	(13,560)
Other income		256	3
Finance income	9	7	202
Finance costs	9	(5,630)	(628)
Loss before taxation		(23,659)	(13,983)
Income tax expense	5	(38)	(9)
Loss for the year attributable to equity holders of the parent company		(23,697)	(13,992)
Other comprehensive income
Exchange differences on translation of foreign operations		(148)	147
Other comprehensive (expense)/income for the year net of taxation		(148)	147
Total comprehensive expense for the year attributable to equity holders of the parent company		(23,845)	(13,845)
Loss per share (cents)
Basic and diluted	8	(3.6)	(0.5)
All operations are considered to be continuing (see note 2).

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

Consolidated Statement of Financial Position

At 31 December 2021

	Note	At 31 December 2021 $ 000's	At 31 December 2020 $ 000's
Assets Non-current assets
Intangible exploration and evaluation assets	10	94,405	75,259
Goodwill	10/15	4,610	4,610
Tangible assets	11	22,748	25,783
Right of use assets	12	14	97
Investment in associate	13	-	47
Escrow and abandonment funds	16	1,564	1,297
Deferred tax asset	5	6,929	8,975
Total non-current assets		130,270	116,068
Current assets
Trade and other receivables	16	4,274	5,313
Inventories	17	259	172
Restricted cash	18	560	946
Cash and cash equivalents		1,555	17,862
Total current assets		6,648	24,293
Total assets		136,918	140,361
Liabilities
Current liabilities
Trade and other payables	19	(23,537)	(18,620)
Lease liabilities	20	(36)	(105)
Borrowings	21	(643)	(498)
Total current liabilities		(24,216)	(19,223)
Non-current liabilities
Borrowings	21	(187)	(1,639)
Provisions	22	(6,294)	(6,314)
Deferred tax liability	5	(6,941)	(8,974)
Total non-current liabilities		(13,422)	(16,927)
Total liabilities		(37,638)	(36,150)
Net assets		99,280	104,211
Shareholders' equity
Called-up share capital	23	218	123
Share premium reserve	23	171,734	152,717
Share based payments reserve	24	5,312	5,228
Retained deficit		(101,381)	(77,684)
Foreign exchange reserve		(1)	147
Convertible debt option reserve	21	114	396
Other reserves	23	23,284	23,284
Total equity attributable to equity holders of the parent company		99,280	104,211

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 29 September 2022 and signed on its behalf by:

Eytan Uliel  Simon Potter

Director  Director

Company Statement of Financial Position

At 31 December 2021

	Note	At 31 December 2021 $ 000's	At 31 December 2020 $ 000's
Assets Non-current assets Property, plant and equipment Right of use assets Investment in subsidiaries Trade and other receivables	11 12 14 16	59 14 50,940 113,187	78 12 50,940 83,839
Total non-current assets		164,200	134,869
Current assets
Trade and other receivables	16	166	238
Restricted cash	18	57	57
Cash and cash equivalents		914	17,160
Total current assets		1,137	17,455
Total assets		165,337	152,324
Liabilities
Current liabilities
Trade and other payables	19	(10,775)	(504)
Lease liabilities	20	(14)	(13)
Borrowings	21	(462)	-
Total current liabilities		(11,251)	(517)
Non-current liabilities
Borrowings	21	-	(1,120)
Total non-current liabilities		-	(1,120)
Total liabilities		(11,251)	(1,637)
Net assets		154,086	150,687
Shareholders' equity
Called-up share capital	23	218	123
Share premium reserve	23	171,734	152,717
Share based payments reserve	24	4,942	4,858
Retained deficit		(52,457)	(36,942)
Convertible debt option reserve	21	114	396
Other reserve	23	29,535	29,535
Total equity attributable to equity holders of the parent company		154,086	150,687

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 29 September 2022 and signed on its behalf by:

Eytan Uliel  Simon Potter

Director  Director

Consolidated Statement of Cash Flows

For the year ended 31 December 2021

	Year ended 31 December 2021 $ 000's	Year ended 31 December 2020 $ 000's
Cash flows from operating activities
Loss before taxation	(23,659)	(13,983)
Decrease/(increase) in trade and other receivables	772	(204)
Decrease in trade and other payables and provisions	(5,105)	(1,164)
Increase in inventories	(87)	(18)
Impairment of goodwill	-	2,435
Impairment of tangible and intangible assets	7,416	-
Depreciation of property, plant and equipment (note 11)	2,944	1,446
Depreciation of right of use asset (note 12)	86	214
Loss on disposal of investment in associate	47	-
Loss on disposal of property, plant and equipment (note 11)	11	105
Amortisation (note 10)	263	113
Share settled payments (note 24)	644	2,455
Other income	(256)	(3)
Finance income (note 9)	(7)	(202)
Finance costs (note 9)	5,630	628
Share based payments (note 24)	84	360
Income tax paid	(99)	(9)
Foreign exchange loss/(gain) on operating activities	17	(32)
Net cash outflow from operating activities	(11,299)	(7,859)
Cash flows from investing activities
Purchase of property, plant and equipment (note 11)	(5,385)	(228)
Proceeds from sale of property, plant and equipment	36	-
Payments for exploration and evaluation assets	(13,745)	(14,566)
Decrease/(increase) in restricted cash	386	(9)
Cash acquired from business combination (note 15)	-	1,039
Other income received	256	3
Interest received (note 9)	7	202
Net cash outflow from investing activities	(18,445)	(13,559)
Cash flows from financing activities
Issue of ordinary share capital	14,456	29,536
Share issue costs	(19)	-
Principal elements of lease payments (note 20)	(86)	(216)
Interest payable on lease liabilities (note 20)	(7)	(17)
Finance costs	(2,575)	(176)
Repayment of borrowings	(648)	(2,694)
Proceeds of borrowings	2,259	1,515
Net cash inflow from financing activities	13,380	27,948
Net (decrease)/increase in cash and cash equivalents	(16,364)	6,530
Effects of exchange rate changes on cash and cash equivalents	57	180
Cash and cash equivalents at beginning of year	17,862	11,152
Cash and cash equivalents at end of year	1,555	17,862
The accompanying accounting policies and notes form an integral part of these financial statements.

Company Statement of Cash Flows

For the year ended 31 December 2021

	Year ended 31 December 2021 $ 000's	Year ended 31 December 2020 $ 000's
Cash flows from operating activities
Loss before taxation	(15,515)	(12,392)
Decrease/(increase) in trade and other receivables	72	(14)
Increase/(decrease) in trade and other payables	23	(869)
Depreciation (notes 11 and 12)	37	31
Provision for doubtful recovery of intercompany receivable	5,813	7,171
Share settled payments	638	2,455
Other income	-	(3)
Finance income	-	(46)
Finance costs	5,418	81
Foreign exchange loss/(gain) on operating activities	213	(142)
Share based payments (note 24)	84	360
Net cash outflow from operating activities	(3,217)	(3,368)
Cash flows from investing activities
Payments to acquire tangible assets (note 11)	(3)	(79)
Interest received (note 9)	-	46
Other income received	-	3
Increase in restricted cash	-	(31)
Advances to and payments on behalf of group companies	(27,239)	(21,610)
Net cash outflow from investing activities	(27,242)	(21,671)
Cash flows from financing activities
Issue of ordinary share capital	14,456	29,536
Share issue costs	(19)	-
Principle elements of lease payments (note 20)	(16)	(15)
Interest payable on lease liabilities (note 20)	(1)	(1)
Finance costs	(2,369)	(79)
Proceeds of borrowings	2,259	1,515
Net cash inflow from financing activities	14,310	30,956
Net (decrease)/increase in cash and cash equivalents	(16,149)	5,917
Effects of exchange rate changes on cash and cash equivalents	(97)	143
Cash and cash equivalents at beginning of year	17,160	11,100
Cash and cash equivalents at end of year	914	17,160
The accompanying accounting policies and notes form an integral part of these financial statements.

Statement of Changes in Equity

For the year ended 31 December 2021

	Called up share capital $ 000's	Share premium reserve $ 000's	Share based payments reserve $ 000's	Retained deficit $ 000's	Foreign exchange reserve $ 000's	Convertible debt option reserve $ 000's	Other reserves $ 000's	Total Equity $ 000's
Group	61 - -	96,157 - -	4,868 - -	(63,692) (13,992) -	- - 147	- - -	23,284 - -	60,678 (13,992) 147
At 1 January 2020 Loss for the year Currency translation differences
Total comprehensive (expense)/income	-	-	-	(13,992)	147	-	-	(13,845)
Share capital issued Recognition of conversion feature (note 21)	62 -	56,560 -	- -	- -	- -	- 396	- -	56,622 396
Share based payments	-	-	360	-	-	-	-	360
Total contributions by and distributions to owners of the Company	62	56,560	360	-	-	396	-	57,378
At 31 December 2020	123	152,717	5,228	(77,684)	147	396	23,284	104,211
Loss for the year Currency translation differences	- -	- -	- -	(23,697) -	- (148)	- -	- -	(23,697) (148)
Total comprehensive expense	-	-	-	(23,697)	(148)	-	-	(23,845)
Share capital issued Recognition of conversion feature (note 21) Realisation of conversion feature (note 21)	95 - -	19,017 - -	- - -	- - -	- - -	- 505 (787)	- - -	19,112 505 (787)
Share based payments	-	-	84	-	-	-	-	84
Total contributions by and distributions to owners of the Company	95	19,017	84	-	-	(282)	-	18,914
At 31 December 2021	218	171,734	5,312	(101,381)	(1)	114	23,284	99,280

Called up share capital $ 000's		Share premium reserve $ 000's	Share based payments reserve $ 000's	Retained deficit $ 000's	Convertible debt option reserve $ 000's	Other reserve $ 000's	Total Equity $ 000's
Company	61 -	96,157 -	4,498 -	(24,551) (12,391)	- -	29,535 -	105,700 (12,391)
At 1 January 2020 Loss for the year
Total comprehensive expense	-	-	-	(12,391)	-	-	(12,391)
Share capital issued	62	56,560	-	-	-	-	56,622
Recognition of conversion feature (note 21)	-	-	-	-	396	-	396
Share based payments	-	-	360	-	-	-	360
Total contributions by and distributions to owners of the Company	62	56,560	360	-	396	-	57,378
At 31 December 2020	123	152,717	4,858	(36,942)	396	29,535	150,687
Loss for the year	-	-	-	(15,515)	-	-	(15,515)
Total comprehensive expense	-	-	-	(15,515)	-	-	(15,515)
Share capital issued	95	19,017	-	-	-	-	19,112
Recognition of conversion feature (note 21)	-	-	-	-	505	-	505
Realisation of conversion feature (note 21)	-	-	-	-	(787)	-	(787)
Share based payments	-	-	84	-	-	-	84
Total contributions by and distributions to owners of the Company	95	19,017	84	-	(282)	-	18,914
At 31 December 2021	218	171,734	4,942	(52,457)	114	29,535	154,086

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

Notes to the financial statements for the year ended 31 December 2021

1  Summary of significant 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 holder of several oil & gas exploration and production licences located in Trinidad & Tobago, Suriname, Uruguay 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 34 North Quay, Douglas, Isle of Man IM1 4LB. The Company's review of operations and principal activities is set out in the Directors' Report. See note 14 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) as adopted by the European Union. The Company's financial statements have been prepared in accordance with IFRS as adopted by the European Union 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 principal accounting policies adopted by the Group and Company are set out below.

New and revised standards and interpretations not applied

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2021 reporting periods 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 1.28 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 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.

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.

The investment in associate (an entity over which the Group has significant influence) has been recorded at cost and has not been adjusted to reflect the Group's 25% share of the net profits/losses and assets/liabilities of the associate from the date of acquisition to the balance sheet date as it was deemed immaterial.

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 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 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 statement of comprehensive income.

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

1.11 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.

1.12 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.

1.13 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 Statement of comprehensive income. 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.

1.14 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.

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.

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.

1.15 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', 'escrow 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.

1.16 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.

1.17 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 proceeds. Net proceeds are disclosed in the statement of changes in equity.

1.18 Finance costs

Borrowing costs are recognised as an expense when incurred.

1.19 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 are identified as compound instruments with the liability and equity components separately recognised. 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. 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 our 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.

1.20 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.

1.21 Dividends

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

1.22 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 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.

1.23 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. Evaluation, pursuit and exploration 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 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.

1.24 Employee benefits

Wages and salaries, annual leave and sick 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 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 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.

1.25 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 three geographical segments: Trinidad and Tobago and Suriname, the Bahamas and the Isle of Man and United Kingdom (including holding companies in Cyprus, Netherlands, and St Lucia, and dormant entities in Spain, Uruguay and United States of America). The Isle of Man and United Kingdom geographic segment is non-operating.

1.26 Share issue expenses and share premium account

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

1.27 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.

1.28 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 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 2021 is $101,405,000 (31 December 2020: $72,885,000) relating to the cost of exploration licences, geological and geophysical consultancy, seismic data acquisition and interpretation and the drilling of exploration wells, being made up of $93,952,000 (2020: $72,880,000) in exploration costs in the Bahamian offshore licences and $7,453,000 (2020: $3,176,000) of costs over exploration licences in Trinidad. 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 statement of comprehensive income.

Bahamas oil and gas exploration costs

On 21 February 2019, the Group received notification from the Bahamian Government of the 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 was 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. Commercial volumes of movable hydrocarbons were not present at this drilling location. Subsequently the Group has undertaken 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 has undertaken 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 2021. 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.

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 current licence period on 30 June 2021. A new Government was elected in The Bahamas in September 2021, and the Group is engaging with the new administration regarding the renewal of these licences and the level of licence fees which remain to be paid for the period that expired on 30 June 2021 and which would be payable for the renewed licence period. Once this renewal process is completed, the key licence obligation for the new three-year period will 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 its obligation to commence a well prior to the end of a renewed licence period will be contingent on securing the funding required to execute a second exploration well. The Group has and will continue to engage in discussions with various industry operators regarding entering into a joint venture partnership or farm-out to fund any future well, and the Directors consider that the Group will be able to discharge the licence requirement of a further exploration well within a renewed term of the licence.

In June 2021 the Group notified the Government of The Bahamas that it did not intend to further discussions regarding renewal of the Miami licence area, against which capitalised costs totalling $416,000 were carried. The Group has thus impaired these costs in full in the financial statements to 31 December 2021.

Trinidad and Tobago oil and gas exploration costs

The exploration oil and gas costs in relation to the Group's business in Trinidad and Tobago predominantly relate to the Group's Bonasse field onshore Trinidad. The Bonasse field comprises of historical wells in production, as well as the two further recent wells, namely the Saffron-1 well drilled in 2020 and the Saffron-2 well drilled during 2021.

The Saffron-1 well resulted in the discovery of oil in the deeper Lower Cruse horizon in addition to proving reservoir continuity and producibility in the shallower Upper Cruse and Middle Cruse horizons. Following this, the Saffron-2 well was drilled during 2021 with the Lower Cruse horizons as the primary target for testing, as well as to confirm reservoir continuity and producibility in the Upper and Middle Cruse horizons. The Saffron-2 well was successfully drilled to the Lower Cruse horizon and demonstrated flow of oil to surface from the Lower Cruse horizon, however, the well could not be put on sustained production due to technical and mechanical issues encountered during attempted production tests in the Lower Cruse horizon. Subsequently, the Lower Cruse horizon was isolated and the well was completed in the Middle Cruse horizon.

Based on the results of the Saffron-1 and the Saffron-2 wells and the broadened subsurface understanding, the Company considers that a shallow well development on the Bonasse licence is potentially viable, and the Group is in the process of undertaking detailed evaluation to identify potential well locations that would allow for a field development plan to be carefully validated and submitted to the Trinidadian Ministry of Energy and Energy Resources.

The Group has therefore determined that there is no indication that the carrying value of this asset is impaired at 31 December 2021.

Impairment of Trinidad and Tobago 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. This 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 that one of the cash generating units (CGU) located in Trinidad and Tobago has not met performance expectations determined at the time of the Columbus Energy Group acquisition in August 2020, and again at 31 December 2020. Consequently, an impairment of related intangible assets of $1,653,000 (2020: nil) and tangible assets of $5,347,000 (2020: nil) within this CGU has been recognised at balance sheet date. No impairment has been recognised to goodwill of $4,610,000 (2020: $2,435,000) at the balance sheet date. Refer to note 10 (intangible assets) and note 11 (tangible assets).

(ii) Going concern

These financial statements have been prepared by the Directors on a going concern basis, which assumes that the Group

and Company will continue in operation for the foreseeable future.

As at 31 December 2021, the Group and Company had $1,555,000 and $914,000 in unrestricted cash funding respectively.

Subsequent to the end of the financial year, in March 2022 the Group and Company completed a comprehensive restructuring and recapitalisation exercise which resulted in:

i)  the Group and Company raising approximately £7.3 million (or approximately $10 million) (before expenses) via the issue of new shares, to fund certain payments to creditors as part of the agreed discounted payment plan, as well as to fund a work programme for 2022;

ii)  a substantial reduction in balance sheet payables, debts and potential liability exposures, that would have reasonably required settlement in cash, from approximately $23.5 million to approximately $2.5 million, being the estimated liabilities amount that would be required for settlement in cash by the Group in the foreseeable future. The substantial majority of liability settlements took place subsequent to the year-end, predominantly in the first quarter of 2022. As a substantial majority of these settlement agreements were conditional on making settlements post year end, the liabilities as of the balance sheet date reflect full amounts that would otherwise have been payable in the absence of settlement agreements (see Note 19 for further information); and

iii)  the Company reducing its net current liability position from approximately $10.1 million at balance sheet date to a net current asset position of approximately $4.1 million as a result of the settlements and recapitalisation made subsequent to year end.

Following the restructuring and recapitalisation, the Directors have prepared a cash flow forecast which anticipates the Group and Company being able to continue in operation for at least the next twelve months from the date of this report.

The cash flow forecast includes underlying assumptions and estimates, including oil price, sustained production from the Group's producing fields in Trinidad and Tobago along with certain incremental production from the intended work programme, reliability of reserves estimates and renewal of licences upon expiry.

In addition, the projections assume offsetting of certain tax liabilities and deferral of certain historical liabilities in Trinidad

and Tobago that the Directors believe are either not likely to require settlement in cash or are capable of being deferred and settled on long-dated payment terms so as to not require material amounts of cash during the forecast period.

Certain of these items are outside of the Group and Company's control and unfavourable actual outcomes may materially and adversely affect the Group's cash resources and cast significant doubt about the Group and the Company's ability to continue as a going concern. In such an event, the Group and the Company may be required to implement certain other measures including, but not limited to,

i)  raising additional third-party capital in form of equity, debt or other instruments of a similar nature, and / or

ii)  undertake cost reduction, and / or

iii)  sell certain assets of the Group,

and a successful outcome of such measures cannot be guaranteed.

These financial statements do not include the adjustments that would result if the Group or the Company were unable to continue as a going concern.

Following the outbreak of the Covid-19 global pandemic, the Group had implemented appropriate remote working procedures, where necessary, across all of its teams and operations to ensure the ongoing safety of its staff and consultants. As a consequence, the Group does not consider the Covid-19 pandemic to have any material impact on its operations.

(iii) Recoverability of investment in subsidiary 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 2021 stood at $50,940,000 (2020: $50,940,000) and $113,187,000 (2020: $83,839,000) 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 2021 a loss allowance for expected credit losses of $12,984,000 (2020: $7,171,000) was held in respect of the recoverability of amounts due from subsidiary undertakings.

1.29 Earnings 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.

1.30 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 three geographical segments: Trinidad & Tobago & Suriname (operating), The Bahamas (operating) and The Isle of Man, UK, Uruguay, Spain, Saint Lucia, Cyprus, Netherlands & USA (all non-operating).

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), which provides management service to the Group and entities in Uruguay, Saint Lucia, Cyprus, Spain, the Netherlands, and the U.S.A. all of which are non-operating in that they either hold investments, or are dormant, or in the case of Uruguay had not yet commenced operations as of the year-end. Their results are consolidated and reported on together as a single segment.

Year ended 31 December 2021	Trinidad & Suriname Operating $ 000	Bahamas Operating $ 000	Non-Operating Entities (*) $ 000	Total $ 000
Operating loss by geographical area Net petroleum revenue (**)	4,360	-	-	4,360
Operating loss	(11,638)	(2,083)	(4,571)	(18,292)
Other income	75	16	165	256
Finance costs	(209)	(3)	(5,418)	(5,630)
Finance income	7	-	-	7
Loss before taxation	(11,765)	(2,070)	(9,824)	(23,659)
Other information
Depreciation, amortisation	(3,185)	(54)	(54)	(3,293)
Impairment charges	(7,000)	(416)	-	(7,416)
Capital additions	5,385	21,486	20	26,891
Segment assets
Tangible and intangible assets	23,061	93,991	4,725	121,777
Deferred tax asset	6,929	-	-	6,929
Escrow and abandonment funds	1,564	-	-	1,564
Trade and other receivables	3,519	542	213	4,274
Inventories	259	-	-	259
Restricted cash	503	-	57	560
Cash	591	4	960	1,555
Consolidated total assets	36,426	94,537	5,955	136,918
Segment liabilities
Trade and other payables	(11,615)	(1,049)	(10,873)	(23,537)
Borrowings	(368)	-	(462)	(830)
Deferred tax liability	(6,941)	-	-	(6,941)
Lease liabilities	-	(22)	(14)	(36)
Provisions	(3,760)	-	(2,534)	(6,294)
Consolidated total liabilities	(22,684)	(1,071)	(13,883)	(37,638)

Year ended 31 December 2020	Trinidad & Suriname Operating $ 000	Bahamas Operating $ 000	Non-Operating Entities (*) $ 000	Total $ 000
Operating loss by geographical area Net petroleum revenue (**)	1,417	-	-	1,417
Operating loss	(3,081)	(2,167)	(8,312)	(13,560)
Other income	-	-	3	3
Finance costs	(96)	(21)	(511)	(628)
Finance income	-	-	202	202
Loss before taxation	(3,177)	(2,188)	(8,618)	(13,983)
Other information
Depreciation, amortisation	(1,529)	(197)	(47)	(1,773)
Impairment charges	-	-	(2,435)	(2,435)
Capital additions	78	22,441	79	22,598
Segment assets
Tangible and intangible assets	27,985	73,000	4,764	105,749
Investment in associate	47	-	-	47
Deferred tax asset	8,975	-	-	8,975
Escrow and abandonment funds	1,297	-	-	1,297
Trade and other receivables	3,123	1,882	308	5,313
Inventories	172	-	-	172
Restricted cash	889	-	57	946
Cash	577	97	17,188	17,862
Consolidated total assets	43,065	74,979	22,317	140,361
Segment liabilities
Trade and other payables	(8,979)	(8,738)	(903)	(18,620)
Borrowings	(1,017)	-	(1,120)	(2,137)
Deferred tax liability	(8,974)	-	-	(8,974)
Lease liabilities	(41)	(51)	(13)	(105)
Provisions	(3,562)	-	(2,752)	(6,314)
Consolidated total liabilities	(22,573)	(8,789)	(4,788)	(36,150)

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

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

3  Operating loss - Group	2021 $ 000's	2020 $ 000's
Operating loss is arrived at after charging: Fees payable to the Company's auditors and its associates for:
- the audit of the Company and Group financial statements	325	315
- non audit related services	-	48
Directors' emoluments - fees and benefits (*)	1,311	1,693
Impairment of goodwill (**)	-	2,435
Impairment of tangible and intangible assets	7,416	-
Loss on disposal of associate	47	-
Depreciation (***)	3,030	1,660
Amortisation	263	113

(*) See note 7 for further details.

(**) See note 10 for further details.

(***) Depreciation of certain oil and gas assets of $2,330,000 (2020: $1,113,000) has been recognised within cost of sales.

	2021 $ 000's	2020 $ 000's
Administrative expenses
Staff costs - cash settled	2,714	1,521
Staff costs - share settled (note 24)	506	1,425
Travel and accommodation	190	206
Professional fees - cash settled	2,896	3,324
Professional fees - share settled (note 24)	482	1,030
Depreciation and amortisation	963	660
Share based payments	84	360
Other	1,263	1,267
Total	9,098	9,793

4  Staff costs - Group
	2021			2020
	$ 000's			$ 000's
Wages and salaries - cash	3,230			1,733
Wages and salaries - share settled (note 24)	506			1,425
Share based payments	17			169
Other staff costs	483			441
Total	4,236			3,768
5  Taxation - Group
	2021			2020
	$ 000's			$ 000's
Analysis of tax charge in the year Tax charge on ordinary activities		38	9
Factors affecting the tax charge for the year:
Loss on ordinary activities before tax		23,659	13,983
Standard rate of income tax in the IOM		-%	-%
Loss on ordinary activities multiplied by the standard rate of income tax		-	-
Effects of:
Overseas tax on profits		38	9
Current tax charge for the year		38	9

Deferred tax:

The net deferred tax balances solely relate to the Company's Trinidad and Tobago operations. The components of the asset and

liability for the years ended December 31, 2021 and 2020 were as follows:

	2021 $ 000's	2020 $ 000's
Losses carried forward Leased property	6,929 -	8,974 1
Deferred tax asset	6,929	8,975
Property and equipment	6,941	8,974
Deferred tax liability	6,941	8,974

Deferred tax assets related to tax losses have been recognised to the extent to which deferred tax liabilities have been recognised on taxable temporary differences. As these temporary differences unwind, release of the deferred tax liabilities creates a taxable profit against which deferred tax assets are utilised. At 31 December 2021, the Group had an unrecognised deferred tax asset of $47,000,000 (2020: $47,700,000) calculated at 46.8% (2020: 45.7%) (weighted average across taxable entities) in respect of an estimated $123,100,000 (2020: $100,500,000) of accumulated tax losses. The deferred tax asset was not recognised as there was insufficient evidence to suggest that it would be recoverable in future periods.

The recognition of movements in deferred tax assets and deferred tax liabilities in the statement of comprehensive income for the year have given rise to a net deferred tax charge of nil (2020: nil).

6 Dividends

During the year, no dividends were paid or proposed by the Directors (2020: nil).

7  Directors' remuneration - Group				2021 $ 000's	2020 $ 000's
Directors' remuneration (details set out in tables below)				1,311	1,693
	Cash		Share based	*Share-settled
	payments	Other	payments	payments	Total
Directors' remuneration - 2021	$ 000's	$ 000's	$ 000's	$ 000's	$ 000's
Executive Directors
Simon Potter	253	7	1	213	474
Eytan Uliel (appointed 1 June 2021)	365	-	6	220	591
Non-Executive Directors
William Schrader (resigned 5 March 2022)	44	-	1	46	91
James Smith (resigned 5 March 2022)	44	-	1	15	60
Adrian Collins (resigned 25 May 2021)	19	-	-	10	29
Ross McDonald (resigned 1 June 2021)	27	-	-	2	29
Stephen Bizzell (appointed 1 June 2021)	33	-	-	-	33
Leo Koot (resigned 22 January 2021)	4	-	-	-	4
	789	7	9	506	1,311

* 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 24 for further details.

Directors' remuneration - 2020	Cash payments $ 000's	Other $ 000's	Share based payments $ 000's	*Share-settled payments $ 000's	Total $ 000's
Executive Directors
Simon Potter	450	24	40	739	1,253
Non-Executive Directors
William Schrader (resigned 5 March 2022)	27	-	28	80	135
James Smith (resigned 5 March 2022)	18	-	18	52	88
Adrian Collins (resigned 25 May 2021)	21	-	22	61	104
Ross McDonald (resigned 1 June 2021)	18	-	18	52	88
Leo Koot (resigned 22 January 2021)	17	-	-	8	25
	551	24	126	992	1,693

*  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 24 for further details.

8  Loss per share - Group

The calculation of loss per share is based on the loss after taxation divided by the weighted average number of shares in issue during the year:

	2021	2020
Loss for the year attributable to equity holders of the parent company ($ 000's)	23,697	13,992
Weighted average number of ordinary shares used in calculating basic loss per share (millions)	667	2,895
Basic loss per share (expressed in cents)	3.6	0.5

Diluted

Diluted loss per share is calculated by adjusting the weighted average number of ordinary shares outstanding to assume conversion of all dilutive potential ordinary shares. The Company had one category of dilutive potential ordinary shares: share options/warrants. For these share options/warrants, a calculation is performed to determine the number of shares that could have been acquired at fair value (determined as the average annual market share price of the Company's shares) based on the monetary value of the subscription rights attached to outstanding share options/warrants. The number of shares calculated as above is compared with the number of shares that would have been issued assuming the exercise of the share options/warrants. Share options/warrants outstanding at the reporting date were as follows:

2021  2020

Total share options and warrants in issue (number) (see note 24)  96,797,894  486,159,599

As the inclusion of potentially issuable ordinary shares would result in a decrease in the loss per share, they are considered to be anti-dilutive and as such, a diluted loss per share is not included.

9  Finance costs/(income) - Group

	2021	2020
	$ 000's	$ 000's
Finance costs*	(5630)	(628)
Finance income - Interest received	7	202

* Included in this balance is a $5,000,000 finance charge derived from direct well funding financial instruments which were utilised by the Group to finance the drilling

of the Perseverance 1 well in Q1 2022. A final reconciliation "make good" payment of £371,000 (US$518,000) was charged in respect of the sale of shares held by the investor with a downside protection clause on the subscription value of shares originally placed in late 2020. An additional make good payment was also payable to the same investor following their exercise of a 187,500,000 share (£3.75 million) put option in early 2021, resulting in a final reconciliation payment payable in April 2021 of £3,300,000 (US$4,482,000) following the sale of these shares.

10  Intangible assets - Group	Goodwill $ 000's	2021 Exploration & evaluation assets $ 000's
Cost	7,045 - -	75,372 21,489 (29)
At 1 January 2021 Additions Foreign exchange difference on translation
At 31 December 2021	7,045	96,832
Accumulated amortisation and impairment	2,435	113
At 1 January 2021
Amortisation	-	263
Impairment	-	2,069
Foreign exchange difference on translation	-	(18)
At 31 December 2021	2,435	2,427
Net book value
At 31 December 2021	4,610	94,405
At 31 December 2020	4,610	75,259
Intangible assets - Group
		2020
		Exploration &
	Goodwill	evaluation assets
	$ 000's	$ 000's
Cost	-	50,570
At 1 January 2020
Acquisition of Columbus Energy Resources PLC (note 15)	7,045	2,492
Additions	-	22,310
At 31 December 2020	7,045	75,372
Accumulated amortisation and impairment	-	-
At 1 January 2020
Amortisation	-	113
Impairment	2,435	-
At 31 December 2020	2,435	113
Net book value
At 31 December 2020	4,610	75,259
At 31 December 2019	-	50,570

11 Tangible assets

	Oil and gas assets $ 000's	Property, plant and equipment (*) $ 000's	Decom- missioning costs $ 000's	Group Total $ 000's	2021 Company Property, plant and equipment (*) $ 000's
Cost or Valuation
At 1 January 2021	23,398	2,258	1,995	27,651	177
Additions	5,065	79	241	5,385	3
Disposals	-	(117)	-	(117)	(2)
Foreign exchange difference on translation	(160)	(207)	(11)	(378)	-
At 31 December 2021	28,303	2,013	2,225	32,541	178
Accumulated depreciation and Impairment	1,115	616	137	1,868	99
At 1 January 2021
Depreciation	2,330	346	268	2,944	22
Disposals	-	(83)	-	(83)	(2)
Impairment	3,933	68	1,346	5,347	-
Foreign exchange difference on translation	(84)	(196)	(3)	(283)	-
At 31 December 2021	7,294	751	1,748	9,793	119
Net book value
At 31 December 2021	21,009	1,262	477	22,748	59
At 31 December 2020	22,283	1,642	1,858	25,783	78

(*)  Property, plant and equipment includes leasehold improvements.

Tangible assets

	Oil and gas assets $ 000's	Property, plant and equipment (*) $ 000's	Decom- missioning costs $ 000's	Group Total $ 000's	2020 Company Property, plant and equipment (*) $ 000's
Cost or Valuation At 1 January 2020 Acquisition of Columbus Energy Resources PLC (note 15) Additions Disposals Foreign exchange difference on translation	- 23,412 59 (72) (1)	450 1,671 169 (33) 1	- 1,994 - - 1	450 27,077 228 (105) 1	100 - 78 (1) -
At 31 December 2020	23,398	2,258	1,995	27,651	177
Accumulated depreciation and Impairment	-	419	-	419	84
At 1 January 2020
Depreciation	1,113	197	136	1,446	16
Disposals	-	(1)	-	(1)	(1)
Foreign exchange difference on translation	2	1	1	4
At 31 December 2020	1,115	616	137	1,868	99
Net book value
At 31 December 2020	22,283	1,642	1,858	25,783	78
At 31 December 2019	-	31	-	31	16

 

END

 

 

FR DGGDCUBDDGDC