ANNUAL REPORT FOR YEAR ENDED 31/12/22

Challenger Energy Group PLC

29 June 2023

Challenger Energy Group PLC

("Challenger Energy" or the "Company")

ANNUAL REPORT AND FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2022

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 2022.

The 2022 Annual Report and Financial Statements will be posted to shareholders by 30 June 2023. The Company's AGM will be held on 15 August 2023 at 11:00 GMT at The Engine House, Alexandra Road, Castletown, Isle of Man IM9 1TG. Notice of the AGM will also be posted to shareholders in due course.

The 2022 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: +44 (0) 1624 647 882

WH Ireland - Nomad and Joint Broker

Antonio Bossi / Darshan Patel / Enzo Aliaj

Tel: +44 (0) 20 7220 1666

Zeus - Joint Broker

Simon Johnson

Tel: +44 (0) 20 3829 5000

Gneiss Energy Limited - Financial Adviser

Jon Fitzpatrick / Paul Weidman / Doug Rycroft

Tel: +44 (0) 20 3983 9263

CAMARCO

Billy Clegg / Hugo Liddy / Sam Morris

Tel: +44 (0) 20 3757 4980

Notes to Editors

Challenger Energy is a Caribbean and Americas focused oil and gas company, with a range of oil production, development, appraisal, and exploration assets in the region. The Company's primary assets are located in Uruguay, where the Company holds high impact offshore exploration licences, and in Trinidad and Tobago, where the Company has a number of producing fields and earlier-stage exploration / appraisal projects.

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

https://www.cegplc.com

ENDS

Chairman's Letter to the Shareholders

Dear shareholders,

I am pleased to report to you as chairman of your Company.

In my last report I discussed the transition that the company was undertaking on several fronts: moving on from legacy issues, refocusing the Trinidad business, and pivoting longer term exploration towards Uruguay. Over the last year, we have delivered on each of these.

In relation to legacy issues, ﬁnal settlements of historic liabilities were agreed at the start of 2022, which, in tandem with a capital raising in March of 2022, allowed the company to clear its balance sheet and refocus its resources. The Company remains in discussions with the Bahamian government regarding the status of its licences there, and our rights to beneﬁt from the substantial work undertaken and cost incurred. However, this project no longer forms part of our immediate business focus.

In Trinidad, we made substantial changes to our business, resetting the basic operating philosophy away from "maximising production" to "efficiency and proﬁt". We strategically prioritised our main assets in south-east Trinidad, streamlined operations around those main assets, and began a process of divesting and monetising non-core assets. These measures have resulted in a more efficient and sustainable Trinidadian business.

In Uruguay, the Company has beneﬁtted from renewed global focus on energy security and exploration, following the Ukrainian invasion and loss of access to Russian production and reserves in Western energy markets. These developments, when coupled with recent exploration success in Namibia - the "other side" of the Atlantic conjugate margin on which our Uruguay assets sit - have seen Uruguay become a new hot zone in global exploration, as evidenced by the heavy presence of global majors in the country's recent licencing rounds.

Our AREA OFF-1 acreage has thus become more important for our Company. As Eytan describes more fully in his CEO report, in the past year we have rapidly advanced our AREA OFF-1 technical work program, to enhance the value we hope to realise when we farm-out the asset. The story has been further enhanced by the award of the OFF-3 licence to the Company, which grows our business in Uruguay even further.

In my last report, I noted my belief that oil will remain an important part of the energy mix for many years to come. The events of the last year, and the impact this has had on energy prices and the global energy industry, make these observations as relevant as ever. As the Western world searches for new and more secure sources of energy, we are well positioned to beneﬁt.

I would like to thank all our staff for their efforts over the course of the past year, the Board for their support in managing and guiding this process, and ﬁnally our shareholders for their continued support.

Iain McKendrick Chairman

28 June 2023

Chief Executive Officer's Report to the

Shareholders

Dear fellow Shareholders,

I am pleased to provide the following commentary on our business and operations during the period under review.

The 2022 ﬁnancial year (that is, from January to December 2022) was a time of considerable change and progress for our Company. In early 2022 we completed a comprehensive ﬁnancial and operational restructuring, along with a recapitalisation. Then, with the beneﬁt of legacy issues behind us, we were able to devote full attention to core operations: our production business in Trinidad and Tobago and developing a deeper insight as to the value of our exploration acreage in Uruguay. And, as the fundamentals and realities of our business and our assets shifted, we reshaped our strategies and priorities to match. The result is that both pillars of our business advanced such that we are now, in 2023, seeing results from the solid foundations laid in 2022.

Exploration Acreage in Uruguay

One of the key drivers of value for any junior E&P company is the ability to adapt rapidly to changes in circumstances. Nowhere was this more evident than in relation to Challenger Energy's Uruguayan business during 2022.

We were awarded the AREA OFF-1 licence block offshore Uruguay in 2020, but as at the start of 2022, Uruguay was not yet on the global industry's radar, and Challenger Energy was Uruguay's sole licence holder. Starting in early 2022, however, everything changed quite dramatically, and very quickly.

The catalyst for this was when two energy majors (TotalEnergies and Shell) each announced in February 2022 that they had made massive discoveries from independent wells drilled offshore Namibia. Those successful Namibian wells served to greatly de-risk the presence of a high-quality, oil-prone source rock and charge, not just in Namibia but on the other side of the South Atlantic conjugate margin - in particular Uruguay, which represents a geological "mirror" of the area where the new Namibian discoveries were made. And whilst in February 2022 the profound signiﬁcance of the Namibian discoveries for Uruguay may not have been immediately obvious to casual market observers, the industry knew exactly what it meant.

As a result, almost overnight we witnessed Uruguay become a global exploration "hotspot." Thus, in the ﬁrst Uruguayan bidding round after the Namibian discoveries (May 2022), three licences were bid on and awarded to majors Shell and APA (formerly Apache). Then, in November 2022, a further two licences were bid on and awarded, one to a consortium of Shell and APA, and the other to YPF, the Argentinian national oil company. Tellingly, the new entrants offered signiﬁcant work program to secure their licences (as compared to the very modest work program we had bid to secure AREA OFF-1), and a number of other energy majors also registered to bid in the two Uruguayan open rounds held in 2022, but were unsuccessful.

This step change in industry interest validated our ﬁrst-mover, low-cost entry into Uruguay, and conﬁrmed that we had secured highly prospective frontier acreage with potential for considerable near-term value uplift. And once we saw industry interest escalate, we rapidly shifted our strategy to match, prioritising our Uruguay business around three clear workstreams:

• First, we elected to accelerate our work program on the AREA OFF-1 block, with a view to generating proprietary intellectual property and upgrading technical knowledge of the area in light of the new conjugate margin discoveries, and in this way seek to increase the value of the AREA OFF-1 asset. The program of work undertaken included reprocessing of legacy 2D seismic data, advanced attribute variation with offset (AVO) analysis, seabed geochemical and satellite seep studies, full reinterpretation and remapping of all data, and an initial volumetric assessment. The result of this work, announced in early 2023, was the identiﬁcation of three technically robust primary prospects on AREA OFF-1, that in aggregate represent a prospect inventory of approximately 2 billion barrels (Pmean) and up to 5 billion barrels (P10) - establishing that AREA OFF-1 is a world-class asset of scale

• Second, we began preparing for a farm-out process. This is because taking AREA OFF-1 forward to 3D seismic acquisition and ultimately exploration well drilling, especially on an expedited basis, will be a technically demanding and costly undertaking, for which we ideally wish to have an industry and funding partner. Consequently, a formal farm-out process was launched in Q2 2023. The next step is to deliver a farm-out, which we are working diligently on.

• And third, we sought to expand our presence in Uruguay, given our developing knowledge base and energy understanding, the excellent working relationship established with ANCAP, and the attractive conditions in that country for hydrocarbon industry activity. The ﬁrst tangible result of this work came in June 2023, when Challenger Energy was awarded the AREA OFF-3 block - the last available offshore acreage in Uruguay - on attractive terms, subject to licence signing. Once this licence has been signed, our Company will be the 2nd largest acreage holder in Uruguay, with a signiﬁcant prospect inventory, and two high- quality assets in what has fast become a global exploration focus area.

In summary, therefore, through the course of 2022 our early entry into Uruguay was transformed from apparently being little more than "option value" to being a near-term opportunity for substantial value-creation. We are conﬁdent that eventually the equity market will pay attention and reward the value we are creating.

Production Operations in Trinidad and Tobago

It was not only in relation to Uruguay that pragmatic adaptation was required during 2022 - our business in Trinidad demanded a similar strategic reassessment during 2022.

At the start of 2022 our Trinidad and Tobago business was focused on a drive for material organic growth in production from our existing ﬁelds. Our goal was to achieve production growth from applying efficient mature oilﬁeld management practices, ﬁeld improvements, Enhanced Oil Recovery (EOR) initiatives, and targeted production enhancement activities. Yet despite doing all this, production growth proved elusive. The undeniable reality is that our oil ﬁelds are mature, and having produced oil for many decades they have depressurised reservoirs, where the rate at which the remaining resource is produced cannot easily be increased. That noted, no matter what we did the production from our existing ﬁelds was remarkably constant and predictable. That is, the same ﬁeld maturity that mitigates against organic production increase also mitigates against unreliable production performance. And based on this simple observation, we undertook a reassessment of our Trinidad operations in mid-2022, which resulted in the following revised business objectives:

• One - prioritise those areas where Challenger Energy has a competitive advantage.

In practical terms, this meant dividing our Trinidad portfolio into two parts: "core" - consisting of the Goudron and Inniss-Trinity assets in south-east Trinidad, and "non-core" - our assets in central and south-west Trinidad. The rationale for this division was simple: (i) our two assets in south-east Trinidad represent about 85% of our current production; (ii) almost all of our operations, staff and equipment are devoted to these two assets and we are one of the larger operators in that area of Trinidad; and (iii) operating conditions in south-east Trinidad are peculiar and difficult (remote locations, jungle, poor infrastructure, etc.), so we have unique local operational knowledge and capabilities that can be leveraged.

• Two - for core business operations, focus on keeping production constant, drive efficiencies, and match the operational footprint and cost to the production we know can be achieved.

Once core assets had been prioritised, we were better able to schedule equipment movements and workovers in support of those assets alone, and we were able to reshape our staff base, operations, and other costs to better "ﬁt" the needs of those speciﬁc assets. We also switched many of the smaller producing wells over to continuous swabbing - an operational approach that meant we would no longer be chasing increased production from those smaller wells, but at the same time also meant we could run those wells at a fraction of the cost of continually working the wells over. In terms of outcomes, this new focus saw production through 2022 holding constant, total operating expenses and G&A reduced, and positive net operating cashﬂow across 2022 (which represents a substantial improvement on 2021, where the Trinidad business had incurred a net operating cash deﬁcit).

• Three - exit or monetise non-core operations.

We made substantial progress in relation to this objective, and in the later part of 2022 succeeded in selling (i) the non- producing Cory Moruga asset, with the buyer committing to a substantial future work program, including EOR and new well drilling (completion of that sale remains pending regulatory approval in Trinidad), and (ii) the South Erin asset, with that sale fully completed in early 2023, resulting in not only an up-front cash payment, but the assumption by the buyer of our obligation to drill three new wells. In both cases, we have retained future back-in rights, such that if the work undertaken by the new owners (at their sole cost and risk) proves successful, we retain the option to "re-acquire" part of the asset. We continue to work on similar exit options for the remaining non-core assets we hold.

• Four - generate increased production from "new oil".

We continue to believe that the opportunity exists to create a proﬁtable and growing production business in Trinidad. But, as described previously, the key learning for us in 2022 was that growth in production will not come from our existing well stock. Rather, the path to growing production in Trinidad will be via accessing "new oil" - that is, either ﬁnding places within our existing ﬁelds that have not been drained effectively and drilling new wells, or by getting new licences. As such, we have been working diligently in the background to identify suitable "new oil" options, whether within our existing core operations, or in our broader geographic area of focus.

The ﬁrst tangible expression of this work become evident only recently, when in June 2023 we were nominated as the party invited to negotiate for the Guayaguayare block, located onshore in south-east Trinidad and thus strategically and operationally synergistic with our existing core assets (our bid was submitted in late 2022, following extensive due diligence and bid preparation through 2022). Guayaguayare is one of the largest onshore blocks in Trinidad, and amongst the largest remaining underexplored / undrained contiguous onshore areas, offering excellent upside. Additionally, the block contains over 60 historic wells, a few of which are active, but most of which are currently shut-in / suspended / abandoned, which can be cheaply reactivated and serviced from existing operations, thus offering the possibility of near-term production uplift.

In summary, insofar as our business in Trinidad is concerned, 2022 was a year where not everything worked out as we had initially hoped, but we learned from experience, reﬁned our strategy accordingly, and built from there. As a result, we are now seeing positive outcomes - continuing improvements in ﬁnancial performance, wins on the business development front, and in overall context, progress toward our goal of building a proﬁtable and growing Trinidadian production business.

Corporate Restructuring & Recapitalisation

As I noted at the start of this report, at the beginning of 2022 we completed a comprehensive ﬁnancial and operational restructuring, along with a recapitalisation. This process had begun in mid-2021, and so I had opportunity to comment at length on it in the 2021 Annual Report. I will thus not repeat the details again here, other than to note that the successful conclusion of this process resulted in a signiﬁcantly reduced overhead cost, streamlined operations, a refreshed board and executive, and a cleaned up balance sheet that put the Company into a position where it was free of ﬁnancial debts and able to fund planned activities during 2022. Many people worked tirelessly in difficult circumstances to achieve this outcome, and on behalf of all shareholders I wish to express my gratitude.

Legacy Assets

Insofar as our "legacy" asset portfolio is concerned, through 2022 we continued to manage those with a view to retaining title in good order, ensuring minimal cost, and seeking means of ultimately monetising the assets. In relation to the Company's licences in The Bahamas we maintained ongoing dialogue with the Government of The Bahamas on two parallel options: (i) the renewal of the licences into a third exploration period, given that we still see considerable long-term exploration potential in those licences, or (ii) a joint initiative seeking to monetise those assets via an alternative approach based around carbon credits. Meanwhile in Suriname there was no ﬁeld activity during 2022 in relation to the WNZ block, but we were granted an initial 6-month extension of the licence, so that we could undertake a further review of the project, focussing on well design options and the long-term commerciality of the ﬁeld. This work has recently been completed, and we are now in discussion with the Surinamese regulator as to the future direction for this asset. I hope to be able to advise of progress in relation to both of these legacy assets in the not-too-distant future.

ESG

Finally, I would like to make a few comments in relation to the broad category of activities referred to nowadays generally as Environment, Social and Governance, or ESG. The fact that these comments come at the end of my report should not in any way be seen as diminishing the importance of this area, because it is absolutely central to everything we do. Not a day goes by at Challenger Energy where we do not devote a portion of our time to discussing, planning, and implementing a variety of programs and actions in support of a simple goal: to make sure that achieving our commercial objectives never comes at the expense of harm to people or the environment.

I am pleased to report that in 2022, our exemplary record in this all-important area was maintained. Across all our operations there were no incidents of note - whether personal injury, property damage or environmental, and all operations throughout 2022 took place without the occurrence of any Lost Time Incidents. Throughout the year we continued to invest in Company-wide training programs and ESG awareness activities, we continued to maintain productive and positive relationships with all relevant Governments and regulatory bodies, and we continued to make targeted social and welfare contributions in the communities where we operate.

Overall, shareholders should be pleased with the Company's ESG performance and track record in 2022, and we will continue to do our utmost to ensure this continues.

2023 Strategic Direction

Looking ahead, the 2023 focus for our business in Uruguay is unambiguously on securing a farm-out partner for the AREA OFF-1 block, such that we can expedite future technical work program on the block and in particular a 3D seismic acquisition - we see this as the path to signiﬁcant near-term value creation for shareholders. In Trinidad the 2023 focus will be to continue the work of the last two years: maintain current production, drive improved ﬁnancial performance, dispose of remaining non-core assets, and seek to strategically access "new oil" opportunities so as to expand the production base.

I would like to take this opportunity to thank our staff, whose hard work and dedication is at the heart of everything we do. And collectively, all of us who work at Challenger Energy wish to express our deep appreciation for the support we receive from our Board, stakeholders, regulators, suppliers, contractors and especially our shareholders. In 2023 and beyond, we will do everything we can to reward your conﬁdence in us.

Eytan Uliel

Chief Executive Officer

28 June 2023

Challenger Energy Overview

Challenger Energy is a Caribbean and Americas focused oil and gas company, with a range of onshore and offshore oil and gas assets in the region. The Company's primary focus is on its Uruguay exploration acreage and its Trinidad production business.

Uruguay

Challenger Energy is the holder of two offshore exploration licences in Uruguay - the AREA OFF-1 and AREA OFF-3 blocks. Together the two blocks represent a total of approximately 28,000 km2 - the second largest offshore acreage holding in Uruguay.

OFFSHORE LICENCE HOLDERS - URUGUAY (JUNE 2023)

Source: ANCAP

Uruguay is located in South America, bordering Brazil and Argentina, and with a broad Atlantic Ocean coastline. The country has a relatively high income per-capita in the region, and represents an advantaged operating regime, frequently ranking ﬁrst in Latin America in measures such as democracy, anti-corruption, and ease of doing business.

Since 2022, and following on from successful exploration drilling in the conjugate margin offshore southwest Africa, the region has seen a signiﬁcant increase in licencing and operational activity, and has become an emerging industry "hot spot". All blocks offshore Uruguay have been licenced in the last 24 months, and with the exception of the two licences awarded to Challenger Energy, all have been awarded to international oil and gas majors. The collective work program of other Uruguay licence holders is estimated to be in excess of $230 million over the next four years. Licence holders in adjacent northern Argentina are also undertaking or expected to be undertaking technical work over the coming two years, including 3D seismic acquisition and deepwater drilling.

AREA OFF-1

The Group has a 100% working interest in and is the operator of, the 14,557 km2 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 Group's initial four-year exploration period work commitment (ending September 2026) is to licence and reprocess 2,000 kms of legacy 2D seismic, and undertake two G&G studies. Given the strong emerging interest in Uruguay, and to facilitate a farm-out, this work program has been expanded and accelerated, with the work largely complete as at the date of this report, and with the full program on schedule to be completed in Q3 2023.

As a result of this technical work program, three prospects have been identiﬁed from a range of play types. Prospects are seismically-derived, supported / further de-risked by AVO analysis, and their robustness corroborated by geochemical seabed sampling and satellite seep analysis. These are summarized as follows:

PROSPECT	DEPOSITIONAL ENVIRONMENT	STRATIGRAPHIC AGE	AREAL EXTENT	WATER DEPTH	RESERVOIR DEPTH	ESTIMATED EUR (mmboe) P10/Pmean/P50/P90
TERU TERU	Onlap slope turbidite to shelf margin wave delta AVO supported - Class II	Mid to Upper Creataceous Albian to Campanian	360/210/106 km²	~ 800m	3,925 m	1,647/740/547/158
TERU TERU		Mid to Upper Creataceous Albian to Campanian	360/210/106 km²	~ 800m	3,925 m	1,647/740/547/158
ANAPERO	Outer shelf margin stacked sands AVO supported - Class III	Upper Cretaceous Campanian	304/214/101 km²	~ 750m	3,400 m	1,627/670/445/88
LENTEJA	Lacustrine alluvial syn-rift fan sealed by regional uncomformity	Lower Cretaceous Neocomian	248/85/14 km²	~ 85m	4,500 m	1,666/576/198/17

The overall AREA OFF-1 prospect inventory of approximately 2 billion barrels recoverable resource (Pmean, unrisked), and over

4.9 billion barrels in an upside case (P10, unrisked), is summarized as follows:

ESTIMATED OIL-IN-PLACE, AREA OFF-1, URUGUAY (MAY 2023)

PROSPECT	P10	Pmean	P50	P90
TERU TERU	5116	2334	1777	527
ANAPERO	5267	2190	1493	304
LENTEJA	5730	1969	690	59
TOTAL	16113	6493	3960	890

ESTIMATED ULTIMATE RECOVERABLE (EUR), AREA OFF-1, URUGUAY (MAY 2023)

PROSPECT	P10	Pmean	P50	P90
TERU TERU	1647	740	547	158
ANAPERO	1627	670	445	88
LENTEJA	1666	576	198	17
TOTAL	4940	1986	1190	263

The Group's forward strategy for AREA OFF-1 is (i) to complete the low-cost minimum work obligations by the end of 2023, (ii) to introduce a partner by the end of 2023 - a formal adviser-led farm-out process initiated, and (iii) proceed to a 3D acquisition on the licence, expedited into the ﬁrst licence exploration period. The Company considers that conjugate margin exploration success, competitive recent licensing rounds in Uruguay, and technical uplift from CEG's 2023 work will drive a successful farm-out process.

AREA OFF-3

The Group was awarded the AREA OFF-3 licence, offshore Uruguay, in June 2023. The award of the licence is pending formal signing of the licence agreement (anticipated within 2023).

Once signed, the licence will provide for a 30-year tenure with the ﬁrst four-year exploration period commencing on signing. The Group's initial four-year exploration period work commitment will be to licence and reprocess 1,000 kms of legacy 2D seismic, and undertake two G&G studies. CEG will hold a 100% working interest in and will be the operator of the 13,252 km2 block.

There has been considerable prior seismic activity and interest on and adjacent to the OFF-3 block, comprising ~4,000 kms legacy 2D (various vintages) and ~7,000 kms legacy 3D (2012 proprietary acquisition). The block was previously held by BP, but was relinquished in 2016. There are no prior wells on the block.

Based on prior technical work, two material-sized prospects have previously been identiﬁed and mapped on AREA OFF-3, as follows:

• Amalia: resource estimate (EUR mmbbl, gross): P10/50/90 (ANCAP) 2,189 / 980 / 392 - the Amalia prospect straddles the boundary with Shell's AREA OFF-2, with an estimated 25% of Amalia contained within AREA OFF-3; and

• Morpheus: resource Estimate (EUR TCF, gross): P10/50/90 (ANCAP) - 8.96 / 2.69 / 0.84 - the Morpheus prospect is entirely contained with AREA OFF-3.

During the initial 4-year exploration period, CEG's technical focus will be on the re-evaluation of the existing 2D and 3D seismic data on the block, given the renewed interest in the types of plays present in Uruguay occasioned by the recent conjugate margin discoveries offshore south-west Africa. In particular, the data and enhanced technical understanding provided from recent activities in Namibia provides greater conﬁdence that the regional petroleum system charging Venus and Graff (offshore Namibia) is likely to be present offshore Uruguay. As a result, traps that exhibit effective sealing mechanisms, and which may previously have been overlooked or not considered viable, are now potential exploration targets.

Moreover, AREA OFF-3 has the advantage of having the majority of the block covered by relatively recent 3D (2012 vintage) that could be reassessed and subjected to advanced analysis techniques, both in terms of reviewing existing known prospects / plays and identifying potential new prospects / plays. In addition, with the Amalia prospect straddling the border with AREA OFF-2, it potentially facilitates a joint exploration assessment with Shell (since May 2022 the licence AREA OFF-2 licence holder).

Trinidad and Tobago

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

The Group has four producing ﬁelds, all onshore Trinidad. Across these ﬁelds there are a total of approximately 250 wells, of which approximately 75 are in production at any given time. The Group also has a large exploration licence position in the South-West Peninsula of Trinidad (SWP).

The Company's strategy in Trinidad is to focus on its core operations, being the Goudron and Inniss-Trinity ﬁelds in the south-east of Trinidad, from which most of the Company's production is derived and where almost all equipment / resources are deployed.

Various options to expand activity in this core area are being considered, including new licence applications, M&A, and joint programs with neighbouring operators. In line with this strategy, in late 2022 the Company had submitted a bid for the Guayaguayare block under the Trinidadian 2022 Onshore Nearshore Competitive Bid Round. Guayaguayare is a large block covering a 306km2 area in the south-east of Trinidad and the Company's Goudron ﬁeld lies within the Guayaguayare block (see map further below). In June 2023 the Company was nominated as the party with whom the Trinidadian Ministry of Energy and Energy Industries ("MEEI") should negotiate the award of Guayaguayare, a precursor step to formal award of the licence.

In parallel, the Company is seeking to monetise non-core assets, so as to maximise cash and offset risk and work program commitments, but at the same time retain upside exposure. In line with this approach on 20 December 2022 the Company announced the conditional disposal of the Cory Moruga licence (presently pending MEEI consent), and, subsequent to the year- end, on 14 February 2023 completed the disposal of the South Erin licence (in both cases, with back-in rights retained). The disposal of these non-core assets represented less than 10% of then current production.

Trinidad Asset Map

Production assets

Goudron

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 term 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

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 June 2023 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 continues to undertake a comprehensive well optimisation and swabbing programme with the objective of achieving production stability, growth and longevity, and reduced ﬁeld operating costs.

Exploration assets

Guayaguayare

The Group, via its wholly owned subsidiary, CEG Goudron Trinidad Limited ("CGTL"), had submitted a bid for the Guayaguayare block onshore Trinidad under the 2022 Onshore and Nearshore Competitive Bid Round. On 12 June 2023, the Group was advised by MEEI that the Government of Trinidad has authorised MEEI to enter into negotiations with CGTL for the grant of an Exploration and Production (Public Petroleum Licence) for the Guayaguayare block (the "Licence"), following a successful bid for that Licence by CGTL. Formal grant of the Licence presently remains subject to negotiations and ﬁnalisation of Licence terms with MEEI.

The Guayaguayare block is located in South-East Trinidad. It is one of the largest onshore exploration and production blocks in Trinidad (approximately 306 km2), and is strategically and operationally synergistic with the Group's core Trinidadian production business, in that the Licence wholly encloses the Company's Goudron licence area, and is adjacent to the Company's Inniss-Trinity licence area.

The Group considers the Guayaguayare block to be highly prospective, being amongst the largest remaining underexplored / undrained contiguous onshore areas in Trinidad. Additionally, the block contains over 60 historic wells (1970s vintage and earlier), most of which are currently shut-in/suspended/abandoned, and some of which the Company believes can be reactivated and serviced from its existing operations, offering the opportunity for near-term production uplift at minimal incremental cost.

"Option" and non-core assets

Cory Moruga

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).

On 20 December 2022, the Company announced entering into binding heads of terms in relation to the sale of T-Rex Resources Trinidad Limited ("T-Rex"), a subsidiary that holds the Group's interest in the Cory Moruga licence, to Predator Oil & Gas Holdings Limited ("Predator") for a cash consideration of US$2 million (US$1 million payable upfront and US$1 million in six months from completion) and a further US$1 million contingent consideration payable once 100 barrels per day production is achieved from the Cory Moruga ﬁeld. Further, the Company has the option to buy back 25% of Predator's share in T-Rex (and thus representing a 20.95% interest in the underlying Cory Moruga asset).

Subsequently, in March 2023, The Company and Predator completed fully termed legal documentation and jointly submitted a written request to MEEI to seek consent on the basis of a committed forward work programme and restructuring certain licence terms including the settlement of past dues and rebasing annual licence fees to an appropriate level. Discussions with MEEI are ongoing and the completion of sale of Cory Moruga presently remains subject to MEEI consent.

South Erin

The Group owned and operated 100% of the South Erin ﬁeld by way of a farm-out agreement with Heritage. The farm-out agreement had been renewed until 31 December 2023 and is extendable up to 30 September 2031 subject to completion of a work programme comprising drilling of 3 new wells by 31 December 2023. On 14 February 2023, the Group announced the sale of Caribbean Rex Limited, a subsidiary that held interest in the South Erin licence through interposed subsidiaries, for a consideration of US$1.5 million comprising US$1.2 million cash consideration (fully received by the Company) and US$0.3 million in the form of assumption of third-party liabilities. The Company has retained a back-in option, granting the Company the right to repurchase a 49% non-operating interest in the South Erin ﬁeld exercisable at the Company's election, at any time in 18 months from the transaction date for a ﬁxed cash amount of US$1 million, plus 49% of all amounts spent by the buyer on South Erin ﬁeld activities and new well drilling.

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. In parallel, the Group is seeking to monetise SWP by way of either a sale or joint venture / farm-in with a view to retaining upside exposure as with the sale of the Cory Moruga and South Erin licences.

Legacy Assets

The Bahamas

The Group is the 100% holder of four conjoined exploration licences offshore The Bahamas. The Perseverance-1 exploration well was drilled in the licence area in early 2021, and did not result in a commercial discovery at the drill location. However, 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. In March 2021, the Group notiﬁed the Government of The Bahamas of its intent to renew the licences into a third 3-year exploration period - this renewal remains pending, and the Group is engaging with the Government on the renewal process. At the same time, the Group is engaging with the Government and various third-party consultants on a joint initiative seeking to monetise the asset via an alternative approach based around carbon credits.

Suriname

During 2022, the Group held 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"). During 2022 the Group was granted an initial 6-month extension of the licence, during which time the group undertook a review of the project, focussing on well design options and the long-term commerciality of the ﬁeld. This work has recently been completed, and the Group is in discussion with the Surinamese regulator as to the future direction for this asset.

People and Operations

The Group's registered office is in the Isle of Man. In addition, the Group maintains three operational offices, in London (United Kingdom), Montevideo (Uruguay) and San Fernando (Trinidad). Across its operations the business has a total staff of

approximately 75 employees, the majority being operating staff in Trinidad. In support of its active ﬁeld operations in Trinidad, the Group owns and operates two workover rigs, one swabbing rig, and assorted heavy ﬁeld equipment.

The Company's Board, management team and staff base have a broad range of skills as well as deep technical and industry experience. Company takes great pride in its exemplary HSE&S track record, and constantly aims to be an employer and partner of choice, making a valued contribution to the communities and nations in which it operates.

Governance

Set out below are details of Challenger Energy's approach to Environmental, Social and Corporate Governance ("ESG") ESG related activities and areas.

ESG Philosophy and Management

At Challenger Energy, we believe that pursuit of our 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. 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.

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. 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 always committed to the responsible stewardship of the environment and we seek to operate safely and responsibly. 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, which were substantially revised and updated in 2021, with Company-wide application, designed to promote and foster excellence in all relevant areas of HSES.

Corporate Governance

Challenger Energy operates in the energy sector, which is regulated by strict laws and rules imposed by host Governments and international regulators, as well as being subject to intense public scrutiny. 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.

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 and divestments. The Board currently consists of the Chairman (Iain McKendrick), the Chief Executive Officer (Eytan Uliel), and two Non-executive Directors (Stephen Bizzell and Simon Potter). Iain McKendrick (Chairman) was independent on appointment to the Board. All Directors have access to the Company Secretary and the Group's professional advisers.

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

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

Stephen Bizzell has over 25 years' corporate ﬁnance and public company management experience in the resources sector in Australia and Canada with various public companies. He is the Chairman of boutique corporate advisory and funds management group Bizzell Capital Partners Pty Ltd., a ﬁrm which over the last 15 years has raised more than A$1.5 billion in equity capital for its associated entities. He is also the Chairman of ASX listed MAAS Group Holdings Ltd and Laneway Resources and a Non-executive Director of ASX listed Armour Energy Ltd, Renascor Resources Limited and Chairman of Strike Energy Ltd. He was an Executive Director of ASX listed Arrow Energy Ltd from 1999 until its acquisition in 2010 by Shell and PetroChina for A$3.5 billion. Stephen qualiﬁed as a Chartered Accountant and early in his career was employed in the Corporate Finance division of Ernst & Young and the Corporate Tax division of Coopers & Lybrand. He has had considerable experience and success in the ﬁelds of corporate restructuring, debt and equity ﬁnancing, and mergers and acquisitions. Stephen is also the Chairman of Challenger Energy Audit Committee.

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

Records of the board meetings

There were 7 meetings of the board of the parent entity in the period 1 January 2022 to 31 December 2022.

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 direct access to the Group's auditor. The Audit Committee meets on a regular basis, and in 2022 met on two 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 2022 met on one occasion, with all members being present for that meeting.

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 2022 the HSES Committee met on four occasions, with all members being present for all meetings.

Company Secretary

All Directors have access to the Company Secretary for advice and services. The appointment and removal of the Company Secretary is a decision for the Board as a whole. Directors also have access to independent professional advice at the Company's expense and receive appropriate training where necessary.

Internal Control

The Directors acknowledge their responsibility for the Group's system of internal control and for reviewing its effectiveness. The system of internal control is designed to manage the risk of failure to achieve the Group's strategic objectives. It cannot totally eliminate the risk of failure but will provide reasonable, although not absolute, assurance against material misstatement or loss.

Going Concern

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

The Group had incurred an operating loss of $4.2 million for the ﬁnancial year ended 31 December 2022 and the Group's current liabilities exceeded current assets by approximately $2.0 million as of 31 December 2022. At 31 December 2022, the Group had approximately $2.5 million in unrestricted cash funding and at the date of authorisation of these ﬁnancial statements, the Group had approximately $1.3 million in unrestricted cash funding. In addition, the Group had approximately $0.5m in restricted cash holdings in support of minimum work obligations in Uruguay, for which the work has been substantially completed as at the date of this report. In addition, the Group has several high-probability sources of cash inﬂows expected over the next 12 months to enable the Group to continue as a going concern for the foreseeable future. These include:

1. Contracted proceeds from sale of Cory Moruga licence in Trinidad.

In December 2022, the Group announced the sale of Cory Moruga licence onshore Trinidad and Tobago for a consideration of up to US$3 million of which US$1 million is payable upon completion, US$1 million in six months from completion and a further US$1 million contingent upon Cory Moruga ﬁeld achieving 100 barrels of oil per day production. Cory Moruga licence is presently a dormant licence with previously discovered and tested oil resource. The sale is fully documented and not subject to any conditions to completion other than consent from the Trinidadian Ministry of Energy and Energy Industries ("MEEI"), which remains outstanding. The Group, in conjunction with the acquirer, have been in discussions with MEEI and anticipates consent being obtained and completion of the sale transaction within 3Q 2023. A successful completion would result in the Group receiving US$2 million in cash consideration within six months from completion.

2. Potential inﬂows from successful farm-out of the AREA OFF-1 licence in Uruguay.

The Group had been in discussions with various industry participants in relation to potential farm-out / partnership options for the AREA OFF-1 licence in Uruguay. In June 2023, a formal adviser-led process was commenced with the objective of securing an industry partner to farm-out the AREA OFF-1 licence by the end of 2023. In the event of a successful farm-out, the Group expects signiﬁcant upfront cash consideration, consistent with typical transactions of this nature in the international oil and gas industry. The Group is conﬁdent that a farm-out transaction can be successfully achieved in this timeframe, because (i) multiple high-quality energy majors are presently engaged in the farm-out process, undertaking due diligence as at the date of this report; (ii) the Group's technical work to-date has resulted in identiﬁcation and deﬁnition of three prospects with an estimated recoverable resource of approximately 2 billion barrels (Pmean) and up to 5 billion barrels in an upside case (P10) establishing that AREA OFF-1 is a high-quality asset of scale, material to any player in the global industry, and (iii) the Directors consider successful completion of the farm-out process to be highly probable in light of the recent industry developments - namely signiﬁcant offshore discoveries in Namibia (Uruguay is considered to be geological mirror of the offshore Namibia basins), and substantial industry interest in offshore Uruguay acreage in the past 12 months, evidenced by licencing activity in the recent Uruguayan licencing rounds that has resulted in all available acreage now having been awarded to industry majors (Shell, APA Corporation and YPF) along with several other interested global oil majors not securing any acreage.

3. Sale of other non-core assets

The Group is also in discussions in relation to the potential sale of other non-core assets in its portfolio. A successful completion of any transaction of this nature would result in the Group receiving cash consideration, thus increasing its available cash reserves.

In addition to the above, the Directors note that the Company is a publicly listed company on a recognised stock exchange, thus affording the Company the ability to raise capital equity, debt and/or hybrid ﬁnancing alternatives as and when the need arises. The Company has a robust track record in this regard, having raised in excess of US$100 million in equity and alternative ﬁnancing in the past ﬁve years. Based on the Company's attractive asset portfolio and history of capital raising, the Directors are of the view that if required (i.e., in the event sources of cash inﬂows discussed above do not materialise as and when expected) the Company will be able to source fresh capital on short notice. As such, the Directors have prepared the ﬁnancial statements on a going concern basis and consider it to be reasonable.

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 2022, 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 exercises the utmost vigilance wherever its operations are taking place in order to ﬁght these threats. 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 2022, 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.

Risk Management

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

The Board's Responsibility for Risk Management

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

Principal risks and uncertainties

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

RISKS THAT WE CAN INFLUENCE

1. Health, safety and environment (HSE)

Oil and gas exploration, development and production activities can be complex and are physical in nature. HSE risks cover many areas including major accidents, personal health and safety, compliance with regulations and potential environmental harm.

Potential impact: High Probability: Low

Risk Appetite

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

Mitigation

The Group strives to ensure the safety of its employees, contractors and visitors. We are very conscious of the natural environment that we operate in and seek to minimise our environmental impact and footprint.

2. Exploration, development and production

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

Potential impact: High Probability: Moderate

Risk appetite

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

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

Mitigation

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

3. Reserves and resources

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

Potential impact: Medium Probability: Low

Risk appetite

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

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

Mitigation

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

4. Portfolio concentration

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

Potential impact: Medium Probability: High

Risk appetite

The principal location of the Group's producing assets and their age proﬁle places emphasis on the Group's ability to successfully maintain existing production in Trinidad. The Group has a moderate appetite for this risk.

Mitigation

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

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

5. Financing

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

Potential impact: High Probability: Moderate

Risk appetite

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

Mitigation

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

6. Bribery and corruption

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

Jurisdiction	2022 (2021) Rank	2023 (2021) score
Uruguay	14 (18)	74 (73)
Trinidad and Tobago	77 (82)	42 (41)
The Bahamas	-30 (30)	64 (64)
Suriname	85 (87)	40 (39)
United Kingdom	18 (11)	73 (78)

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

Mitigation

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

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

8. Demand/ limited sales routes

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

Potential impact: High Probability: Low

Risk appetite

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

Mitigation

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

9. Fiscal and political

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

Potential impact: High Probability: Moderate

Appetite

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

Mitigation

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

Directors' Report

The Company's Directors present their report and audited ﬁnancial statements of the Company and the consolidated group consisting of Challenger Energy Group PLC ("Challenger Energy" or "the Company") and the entities it controlled (the "Group") at the end of, or during, the ﬁnancial year ended 31 December 2022.

Directors

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

Iain McKendrick (appointed 5 March 2022) Stephen Bizzell

Simon Potter Eytan Uliel

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

William Schrader (resigned 5 March 2022)

James Smith (resigned 5 March 2022)

Principal Activity

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

Results and dividends

The results of the Group for the year are set out on page 26 and show a proﬁt for the year ended 31 December 2022 of $4,382,000 (2021: loss of $23,697,000). The total comprehensive loss for the year of $1,360,000 (2021: loss of $23,845,000) has been transferred to the retained deﬁcit.

The Directors do not recommend payment of a dividend (2021: nil).

Signiﬁcant Shareholders

The following tables represent shareholdings of 3% or more notiﬁed to the Company at 31 December 2022:

Top shareholders (by parent company)
Shareholder	31-Dec-22	%
Hargreaves Lansdown Asset Management	935,028,940	9.72
Bizzell Capital Partners	914,633,600	9.51
Choice Investments (Dubbo) Pty Ltd	837,000,000	8.7
Jarvis Investment Management	562,454,613	5.85
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
Merseyside Pension Fund	417,350,000	4.34
GP (Jersey) Ltd	390,000,000	4.05
RAB Capital	365,900,000	3.8
Interactive Investor	318,545,525	3.31
Maybank Kim Eng Securities	300,000,000	3.12
TOTAL	6,674,286,640	69.38

Directors' Shareholding and Options

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

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Statement of Directors' Responsibilities in respect of the ﬁnancial statements

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

Company law requires the Directors to prepare ﬁnancial statements for each ﬁnancial year. The Directors have elected to prepare the Group and Company ﬁnancial statements in accordance with International Financial Reporting Standards ("IFRSs"). The ﬁnancial statements are required by law to give a true and fair view of the state of affairs of the Group and the Company and of the proﬁt or loss of the Group for that period.

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

• select suitable accounting policies and then apply them consistently;

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

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

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

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

On behalf of the Board

Eytan Uliel Director

28 June 2023

Independent auditor's report to the members

of Challenger Energy Group PLC

Opinion

We have audited the ﬁnancial statements of Challenger Energy Group PLC (the "Company") and its subsidiaries (the "Group''), which comprise the Consolidated Statement of Comprehensive Income, Consolidated and Company Statements of Financial Position, Consolidated and Company Statements of Cash Flows and Statement of Changes in Equity for the year ended 31 December 2022, and the related notes to the ﬁnancial statements, including a summary of signiﬁcant accounting policies.

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

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

• give a true and fair view in accordance with IFRS of the ﬁnancial position of the Group and Company as at 31 December 2022, and of the Group's ﬁnancial performance and the Group and Company cash ﬂows for the year then ended; and

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

Basis for opinion

We conducted our audit in accordance with International Standards on Auditing (UK) ('ISAs (UK)') and applicable law. Our responsibilities under those standards are further described in the 'Responsibilities of the auditor for the audit of the ﬁnancial statements' section of our report. We are independent of the Group and Company in accordance with the ethical requirements that are relevant to our audit of the ﬁnancial statements in the Isle of Man, including the FRC's Ethical Standard and the ethical pronouncements established by Chartered Accountants Ireland, applied as determined to be appropriate in the circumstances for the entity. We have fulﬁlled our other ethical responsibilities in accordance with these requirements. We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Conclusions relating to going concern

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

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

• assessing management's underlying cash ﬂow projections for the Group for the period to December 2024 and evaluating the assumptions including production, prices, operating expenditure and capital expenditure. In doing so we compared production forecasts to historical trends and considered the price assumptions against consensus market prices and historical prices. We compared forecast costs with historical expenditure and to other external and internal sources, including the impairment assessments, where appropriate;

• assessing and validating the impact of post year end cash inﬂow sources and commitments, including contractual proceeds from sale of Cory Moruga licence in Trinidad and Tobago and potential inﬂows from farm-out of Area OFF-1 license in Uruguay;

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

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

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

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

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

Other matter

The ﬁnancial statements of Challenger Energy Group PLC and its subsidiaries for the year ended 31 December 2021, were audited by PwC who expressed an unmodiﬁed opinion on those ﬁnancial statements on 29 September 2022.

Key audit matters

Key audit matters are those matters that, in our professional judgement, were of most signiﬁcance in our audit of the ﬁnancial statements of the current ﬁnancial period and include the most signiﬁcant assessed risks of material misstatement (whether or not due to fraud) we identiﬁed, including those which had the greatest effect on: the overall audit strategy, the allocation of resources in the audit, and the directing of efforts of the engagement team. These matters were addressed in the context of our audit of the ﬁnancial statements as a whole, and in forming our opinion thereon, and therefore we do not provide a separate opinion on these matters.

Overall audit strategy

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

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

• Going concern;

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

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

How we tailored the audit scope

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

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

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

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

Materiality and audit approach

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

Based on our professional judgement, we determined materiality for the Group and Company at 0.75% of total assets at 31 December 2022. We have applied this benchmark because the main objective of the Group is to utilise its existing oil and gas assets and exploration and evaluation assets to provide investors with returns on their investments.

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

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

Signiﬁcant matters identiﬁed

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

Other information

Other information comprises information included in the annual report, other than the ﬁnancial statements and our auditor's report thereon. The directors are responsible for the other information. Our opinion on the ﬁnancial statements does not cover the other information and, except to the extent otherwise explicitly stated in our report, we do not express any form of assurance conclusion thereon.

In connection with our audit of the ﬁnancial statements, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the ﬁnancial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated. If we identify such material inconsistencies in the ﬁnancial statements, we are required to determine whether there is a material misstatement in the ﬁnancial statements or a material misstatement of the other information. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact.

We have nothing to report in this regard.

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

As explained more fully in the Statement of Directors' Responsibilities, management is responsible for the preparation of the

ﬁnancial statements which give a true and fair view in accordance with IFRS, and for such internal control as directors determine necessary to enable the preparation of ﬁnancial statements are free from material misstatement, whether due to fraud or error.

In preparing the ﬁnancial statements, management is responsible for assessing the Group and Company's ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Group or Company or to cease operations, or has no realistic alternative but to do so.

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

Responsibilities of the auditor for the audit of the ﬁnancial statements

The objectives of an auditor are to obtain reasonable assurance about whether the ﬁnancial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor's report that includes their opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with ISAs (UK) will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to inﬂuence the economic decisions of users taken on the basis of these ﬁnancial statements.

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

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

Irregularities, including fraud, are instances of non-compliance with laws and regulations. We design procedures in line with our responsibilities, outlined above, to detect material misstatements in respect of irregularities, including fraud. Owing to the inherent limitations of an audit, there is an unavoidable risk that material misstatement in the ﬁnancial statements may not be detected, even though the audit is properly planned and performed in accordance with the ISAs (UK). The extent to which our procedures are capable of detecting irregularities, including fraud is detailed below.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

This report is made solely to the company's members, as a body, in accordance with the terms of our engagement letter. Our audit work has been undertaken so that we might state to the company's members those matters we are required to state to them in an auditor's report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company's members as a body, for our audit work, for this report, or for the opinions we have formed.

Cathal Kelly

(Senior Statutory Auditor)

For and on behalf of Grant Thornton

Chartered Accountants & Statutory Auditors 13-18 City Quay

Dublin 2 Ireland

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Notes to the ﬁnancial statements for the year ended 31 December 2022

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 holders of several oil & gas exploration and production licences located in Uruguay, Trinidad & Tobago, Suriname and The Bahamas.

The Company is a limited liability company incorporated and domiciled in the Isle of Man. The address of its registered office is The Engine House, Alexandra Road, Castletown, Isle of Man IM9 1TG. The Company's review of operations and principal activities is set out in the Directors' Report. See note 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). The Company's ﬁnancial statements have been prepared in accordance with IFRS and as applied in accordance with the provisions of the Isle of Man Companies Acts 1931 to 2004. As permitted by part 1 Section 3(5) of the Isle of Man Companies Act 1982, the Company has elected not to present its own Statement of Comprehensive Income for the year. The principal accounting policies adopted by the Group and Company are set out below.

Some accounting pronouncements which have become effective from 1 January 2022 and have therefore been adopted do not have a signiﬁcant impact on the Group's ﬁnancial results or position.

New and revised standards and interpretations not applied

Certain new accounting standards and interpretations have been published that are not mandatory for 31 December 2022 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 1.29 for more details.

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

1.04 Basis of consolidation

The ﬁnancial statements incorporate the results of the Company and its subsidiaries (collectively, the "Group") using the acquisition method. Control is achieved where the Company 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.

1.05 Business combinations

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

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

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

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

1.06 Intangible assets - exploration and evaluation assets

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

1.07 Oil and gas development/producing assets and commercial reserves

If the ﬁeld is determined to be commercially viable, the attributable costs are transferred to development/production assets within tangible assets in single ﬁeld cost centres.

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

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

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

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

1.08 Depletion and amortisation

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

1.09 Decommissioning

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

1.10 Property, plant and equipment

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

• Furniture, ﬁttings and equipment 1 - 4 years

• Motor vehicles 5 years

• Leasehold improvements Over the life of the lease

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

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

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

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

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

A discontinued operation represents a separate major line of the business. Proﬁt or loss from discontinued operations comprises the post-tax proﬁt or loss of discontinued operations and the post-tax gain or loss recognised on the measurement to fair value less costs to sell or on the disposal group(s) constituting the discontinued operation.

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

Any proﬁt or loss arising from the sale of a discontinued operation or its remeasurement to fair value less costs to sell is presented as part of a single line item, proﬁt or loss from discontinued operations. See Note 15 for further details.

1.12 Inventories

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

1.13 Revenue recognition

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

1.14 Foreign currencies

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

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

1.15 Leases

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

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

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

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

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

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

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

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

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

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.

1.15 Leases continued

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

• the amount of the initial measurement of lease liability;

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

• any initial direct costs; and

• restoration costs.

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

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

1.16 Financial instruments Financial assets

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

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

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

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

Measurement

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

Impairment of ﬁnancial assets

The Group assesses, on a forward-looking basis, the expected credit losses associated with its ﬁnancial assets held at amortised cost. The impairment methodology applied depends on whether there has been a signiﬁcant increase in credit risk.

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

Financial liabilities

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

30 days of recognition.

Fair value measurement

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

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

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

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

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

1.17 Cash and cash equivalents

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

1.18 Share capital

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

1.19 Finance costs

Borrowing costs are recognised as an expense when incurred.

1.20 Borrowings

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

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

Convertible loans

Loans with certain conversion rights 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 within the convertible debt option reserve. Transaction costs are apportioned between the liability and the equity components of the instrument based on the amounts initially recognised. The liability component is subsequently measured at amortised cost using the effective interest rate method, in line with other ﬁnancial liabilities. The equity component is not remeasured. On conversion of the instrument, equity is issued and the liability component is derecognised. The original equity component recognised at inception remains in equity. No gain or loss is recognised on conversion.

1.21 Provisions

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

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

1.22 Dividends

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

1.23 Taxation

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

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

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

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

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

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

1.24 Impairment of assets

At each balance sheet date, the Group assesses whether there is any indication that its tangible and intangible assets have become impaired. 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 consolidated statement of comprehensive income.

Impairment of goodwill

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

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

1.25 Employee beneﬁts

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

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

Bonuses

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

Pension obligations

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

1.25 Employee beneﬁts continued

Termination beneﬁts

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

1.26 Segmental reporting

Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating

decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identiﬁed as the Board of Directors that makes strategic decisions. The performance of operating segments is assessed on the basis of key metrics applicable, such as barrels of oil produced per day, "netbacks" per barrel, revenue and operating proﬁt.

The Board has determined there is a single operating segment: oil and gas exploration, development and production. However, there are four geographical segments: Trinidad and Tobago and Suriname, the Bahamas, Uruguay 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.

1.27 Share issue expenses and share premium account

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

1.28 Share based payments reserve

This reserve is used to record the value of equity beneﬁts provided to employees and Directors as part of their remuneration and provided to consultants and advisors hired by the Group from time to time as part of the consideration paid.

1.29 Critical accounting estimates, judgements and assumptions

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

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

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

The Directors carried out an impairment review of the Group's tangible 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. Consequently, an impairment of related tangible assets of $2,289,000 (2021: $5,347,000) within this CGU has been recognised at balance sheet date. No impairment has been recognised to goodwill of $4,610,000 (2021: no impairment) at the balance sheet date. Refer to note 10 (intangible assets) and note 11 (tangible assets).

For continuing operations, calculation of the value in use is determined by covering a detailed three-year forecast approved by management, followed by an extrapolation of expected cashﬂows for the remaining useful lives using a declining growth rate determined by management. The present value of expected cashﬂow of each cash generating unit is determined by applying a pre-tax discount rate of 10% reﬂecting market assessment of the time value of money and forward oil price of

$65 per barrel. Applying this methodology an impairment was identiﬁed in a CGU as described above primarily due to lower expected future production and lower expected future oil price assumed compared to the prior year.

Further sensitivity analysis determined the following:

- A $5 per barrel decrease in the oil prices would increase the overall impairment charge to $2,700,000;

- A 10% decrease in production would increase the overall impairment charge to $2,600,000; and

- A 5% increase in the pre-tax discount rate would increase the overall impairment charge to $5,900,000

1.29 Critical accounting estimates, judgements and assumptions continued

Carrying value of capitalised exploration costs

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

The carrying value of exploration costs at 31 December 2022 is $93,963,000 (2021: $93,952,000) relating to the cost of exploration licences, geological and geophysical consultancy, seismic data acquisition and interpretation and the drilling of exploration wells in the Bahamian offshore licences. The Group's exploration activities are subject to a number of signiﬁcant and potential risks including:

- licence obligations;

- requirement for further funding;

- geological and development risks; and

- political risk.

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

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 needed to be extended beyond 31 December 2020 commensurate with the duration of the force majeure event. In November 2020 the Group received notiﬁcation per the Government of The Bahamas agreeing to an extension of these licences to 30 June 2021 as a result of the force majeure event.

On 20 December 2020, the Group commenced drilling of the Perseverance-1 exploration well on its offshore licence area in The Bahamas, with drilling activity ceasing on 7 February 2021. Whilst the well demonstrated presence of hydrocarbons, commercial volumes of movable hydrocarbons were not present at this drilling location. Subsequently the Group undertook an extensive review of the data gathered from the Perseverance-1 well to determine the extent to which this data indicates remaining prospectivity in deeper, untested horizons, as well as horizons of interest at other locations along the B and C structures. The results of this review indicate that substantial prospectivity remains in sufficient potential volumes such that further exploration activity on these licences is merited. On the basis of the revised prospect volume inventory for these untested horizons and structures, the Group undertook an exercise to determine whether the present value of any future economic beneﬁt which may be derived from hydrocarbon extraction from these licences is sufficient to support the carrying value of the capitalised costs at 31 December 2022. 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 up to 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. Following the licence renewal, the Group 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.

1.29 Critical accounting estimates, judgements and assumptions continued

(ii) Going concern

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

$0.5m in restricted cash holdings in support of minimum work obligations in Uruguay, for which the work has been substantially completed as at the date of this report. In addition, The Group has several high-probability sources of cash inﬂows expected over the next 12 months to enable the Group to continue as a going concern for the foreseeable future. These include:

1. Contracted proceeds from sale of Cory Moruga licence in Trinidad.

2. Potential inﬂows from successful farm-out of the AREA OFF-1 licence in Uruguay.

2 billion barrels (Pmean) and up to 5 billion barrels in an upside case (P10) establishing that AREA OFF-1 is a high-quality asset of scale, material to any player in the global industry, and (iii) the Directors consider successful completion of the farm-out process to be highly probable in light of the recent industry developments - namely signiﬁcant offshore discoveries in Namibia (Uruguay is considered to be geological mirror of the offshore Namibia basins), and substantial industry interest in offshore Uruguay acreage in the past 12 months, evidenced by licencing activity in the recent Uruguayan licencing rounds that has resulted in all available acreage now having been awarded to industry majors (Shell, APA Corporation and YPF) along with several other interested global oil majors not securing any acreage.

3. Sale of other non-core assets

1.29 Critical accounting estimates, judgements and assumptions continued

(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 2022 stood at $50,940,000 (2021: $50,940,000) and $113,600,000 (2021: $113,187,000) 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 2022 a loss allowance for expected credit losses of $14,737,000 (2021: $12,984,000) was held in respect of the recoverability of amounts due from subsidiary undertakings.

1.30 Earnings/(loss) per share

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

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

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

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

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

1.31 Investment in subsidiary in the Company statement of ﬁnancial position

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

2 Turnover and segmental analysis

Management has determined the operating segments based on the reports reviewed by the Board of Directors that are used to make strategic decisions. The Board has determined there is a single operating segment: oil and gas exploration, development and production. However, there are four geographical segments: Trinidad & Tobago & Suriname (including a single operating segment and a separate disposal group for the year ended 31 December 2022 (refer to note 15)), The Bahamas (operating), Uruguay (operating) and The Isle of Man, UK, 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 Uruguay segment includes the exploration licences and appraisal works which have commenced in 2022. The non-operating segment including the Isle of Man (the Group's parent), which provides management service to the Group and entities in 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. Their results are consolidated and reported on together as a single segment.

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Deferred tax assets arise on recognition of deferred tax liabilities which arise 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 2022, the Group had an unrecognised deferred tax asset of $49,000,000 (2021: $47,000,000) calculated at 46.1% (2021: 46.8%) (weighted average across taxable entities) in respect of an estimated $130,000,000 (2021: $123,100,000) 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 consolidated statement of comprehensive income for the year have given rise to a net deferred tax charge of $27,000 (2021: nil).

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15 Discontinued operations

At balance sheet date two asset sales were considered to be active and highly probable of taking place: the sale of T-Rex Resources (Trinidad) Limited, an indirectly wholly owned subsidiary of the Company holding the Group's 83.8% interest in the Cory Moruga licence onshore Trinidad, and the sale of Caribbean Rex Limited (CREX), an indirectly wholly owned subsidiary of the Company holding the Group's 100% interest in the South Erin licence via interposed subsidiaries. Accordingly, these entities form a separate disposal group and have been reclassiﬁed as assets held for sale at 31 December 2022.

Sale of T-Rex (Cory Moruga asset):

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

Subsequently, on 8 March 2023, the Company announced that the acquirer had completed its conﬁrmatory due diligence process and the parties had entered into fully termed long form legal documentation.

The completion of the Transaction is conditional on consent of the Trinidadian Ministry of Energy and Energy Industries ("MEEI") to a revised work programme for the Cory Moruga licence and restructuring of certain licence terms. The parties have agreed to work together to secure the required consents and agreements with MEEI and thus achieve completion of the Transaction as soon as reasonably practicable with a long stop date of 31 August 2023.

Sale of CREX (South Erin asset):

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

The results for the combined disposal group are presented below:

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The net cash ﬂows incurred by the combined disposal group are, as follows:

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*Included in the current trade and other payables are exploration and evaluation payables balances amounting to nil (2021: $7,916,000).

During the reporting period, the Group and Company completed a comprehensive restructuring and recapitalisation exercise ("Restructuring and Capital Raising") 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 as of 31 December 2021 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 during the reporting period; and

iii) the Company reducing its net current liability position from approximately $10.1 million at 31 December 2021 to a net current asset position of approximately $1.9 million at 31 December 2022 as a result of the settlements made during the reporting period.

Consequently, following the implementation of Restructuring and Capital Raising, the trade and other payables (including accruals) include dues, amounting to approximately $2.5 million in aggregate, that are considered to be of a routine working capital nature, and that are being settled in the ordinary course of business and / or under certain agreed payment plans. The remainder of trade and other payables (including accruals) include:

i) approximately $3.3 million is in respect of taxes owed in Trinidad and Tobago that the Group expects to settle by way of offset against tax refunds due to the Group in Trinidad and Tobago ($2.1 million, including under 'Trade and other receivables'). The balance amount relates to a notional estimate of penalties that apply in accordance with the tax laws in Trinidad and Tobago - as at the date of this report these are notional estimates only and have not been levied or assessed, and the Group does not expect that they will be levied or assessed and that ultimately no cash payment will be required as the Group had claimed the beneﬁt of a tax amnesty during the 2021 tax amnesty period implemented by the Trinidad and Tobago tax authorities, with the ﬁnal resolution of this matter remaining pending;

ii) approximately $2.3 million is in respect of various dues comprising, i) $0.5 million is in respect of accruals in relation to restructuring and recapitalisation costs, which are expected to be settled in shares without any cash cost to the Company,

ii) $0.5 million is in respect of potential insurance "top-up" exposure, due to the ultimate cost of the Perseverance-1 well in The Bahamas exceeding the initial estimated cost - however, as at the date of this report, the matter remains pending resolution with the insurers, iii) $0.6 million is in respect of accrued licence fee which the Group expects to offset against

$0.5 million refundable advances (included in trade and other receivables) resulting in no material incremental cash exposure to the Group, iv) $0.4 million in advances towards a work programme undertaken by a third-party a settlement agreement for which has been reached (pending completion of the sale of Cory Moruga asset) resulting in no cash exposure to the Group, and v) $0.3 million in relation to legacy accruals recognised in the ﬁnancial statements which the Group expects to be written-back following lapse of the relevant statute of limitation period.

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1 On 30 December 2020, the Company drew down £1,110,000 (US$1,511,000) of a £3,000,000 (US$4,084,000) ﬁrst tranche of a convertible loan previously agreed with Bizzell Capital Partners Pty Ltd. As part of this initial draw down in 2020, £287,000 (US$396,000) was recognised as the equity component. Tranche 1 had a total fair value, after deduction of all facility costs, of £2,800,000 (US$3,812,000). The term of the loan was 3 years from the date of draw-down. The holder had the right, at any time prior to maturity, to elect to convert the Notes (principal plus any accrued interest) into fully paid ordinary shares in the Company. Initially, the conversion price was set at a 25% premium to the price of the Company's next capital raising

(if any) or at 6p per share, whichever was the lower. Subsequently, in February 2021 the conversion price was amended by agreement to 0.8p per share. In May 2021 the balance of the £3,000,000 facility was drawn down in full, resulting in a further £370,000 (US$505,000) equity component being recognised. Thereafter £2,500,000 (US$3,496,000) of the facility amount was converted into ordinary shares resulting in a £579,000 (US$787,000) equity conversion, leaving a remaining principal outstanding of £342,000 (US$462,000) and residual equity component of £84,000 (US$114,000) at 31 December 2021. The remaining balance was converted into ordinary shares as part of the restructuring completed in March 2022.

2 The loan was issued by RBC Royal Bank Limited in June 2015 in respect of the Columbus Energy Resources Plc business. Repayments were over 7 years and the loan is denominated in Trinidad and Tobago Dollars.

3 The loan was issued by BNP Paribas in 2015 in respect of the Columbus Energy Resources Plc business. In December 2016, the outstanding balance of US$2.6m was reﬁnanced and retired, and all security was removed, leaving a ﬁnal unsecured payment of US$0.25m due on 31 December 2019. In November 2020 this loan balance was reﬁnanced with the outstanding balance to be repaid over one year commencing in February 2021. In November 2021 this loan balance was subject to a

re-settlement resulting in a reduced payment terms with ﬁnal settlement made in February 2022. The loan was denominated in US Dollars.

4 In July 2019, CEG South Erin Trinidad Limited drew down on a new working capital loan facility (New Sunchit Loan). Repayments are over 5 years with the ﬁnal payment due in June 2024. The loan is denominated in Trinidad and Tobago Dollars. This loan has been reclassiﬁed as part of Liabilities directly associated with the assets held for sale, see note 15 for details.

The carrying amounts of all the borrowings approximate to their fair value.

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* The provisions relate to the estimated costs of the removal of Trinidadian and Spanish production facilities and site restoration at the end of the production lives of the facilities. Decommissioning provisions in Trinidad and Tobago have been subject to a discount rate of 3.8%-4.98% (2021: 5%), expected cost inﬂation of 2.06%-3.22% (2021: 1.4%) and assumes an average expected year of cessation of production of 2032. Decommissioning provisions relating to facilities in Spain are undiscounted and uninﬂated as the ﬁeld is no longer operating. The Spanish subsidiary is currently in the process of being liquidated and management's expectation is that the provision for decommissioning relating to Spanish assets will be released on completion of this process.

Other provisions

In one of the Group's Trinidadian subsidiaries, there are licence fees and commitments relating to an exploration and production licence that the subsidiary is expecting to settle by way of negotiation with the Trinidadian Ministry of Energy and Energy Industries ("MEEI"). A provision has been recognised to reﬂect management's best estimate of its obligation at balance sheet date. However, the Group has formally written to MEEI proposing rebasing of this licence whereby all claimed past dues would be cancelled, the annual licence fees rebased to an appropriate level, and a new future work programme agreed. To the extent a suitable arrangement of this nature cannot be agreed with MEEI, the Company intended to surrender the licence, in which case the subsidiary company holding the licence will be placed into administration, and all liabilities claimed in respect of this licence will be eliminated, without recourse to the Company, as conﬁrmed by a legal opinion. This provision has been reclassiﬁed as part of liabilities directly associated with the assets held for sale, see note 15 for details.

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During the year, transaction costs for issued share capital totalled $598,000 (2021: $754,000) which were offset against the proceeds received from the issue of shares, with the balance settled through the issue of share capital, these amounts were allocated against share premium.

The total authorised number of ordinary shares at 31 December 2022 was 50,000,000,000 (2021: 2,000,000,000) with a par value of

0.02 pence per share. All issued shares of 0.02 pence are fully paid.

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* The merger reserve arose in 2010 as a result of the Group undergoing a Scheme of Arrangement which saw the shares in the then parent company BPC Limited replaced with shares in Challenger Energy Group PLC.

** In 2008, BPC Jersey Limited acquired Falkland Gold and Minerals Limited ('FGML') via a reverse acquisition, giving rise to the reverse acquisition reserve. BPC Jersey Limited was the acquirer of FGML although FGML became the legal parent of the Group on the acquisition date. FGML subsequently changed its name to BPC Limited.

In the Company Financial Statements, the Other Reserve balance of $29,535,463 (2021: $29,535,463) arises from the issue of shares in the Company as part of the Scheme of Arrangement undertaken in 2010, which saw the shares in the then parent company BPC Limited replaced with shares in Bahamas Petroleum Company PLC (then BPC PLC), which became the new parent company of the Group.

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1 Trinidad and Tobago

The Group has certain minimum work commitments under its licences in Trinidad and Tobago which generally include carrying out heavy work overs, drilling of exploration and / or development wells, undertaking enhanced oil recovery projects including water injection and / or carbon dioxide injection.

As of 31 December 2022, the term of one of the Group's licences was extended to 31 March 2022 (and, more recently, to 30 June 2023) to allow for ministerial approval required for the ﬁnalisation and execution of the agreed form documentation in relation to a fresh enhanced production service contract ("EPSC") with 30 September 2031 expiry. The EPSC will include certain minimum work obligations comprising CO2 pilot project, heavy workovers and the drilling of new wells.

2 Suriname

The Group holds an onshore licence for the exploration for and production of hydrocarbons in Suriname. Under the terms of this licence, the Group is obliged to undertake an extended well test in the licence area by October 2022. The Group was granted a

six-month extension till April 2023 by the Surinamese regulator to undertake further review of the project focusing on well design options and long-term commerciality of the ﬁeld. This work has been completed, and the Group is presently in discussions with the Surinamese regulator as to the future direction for this asset. As of the date of this report, extension of the licence beyond 2023 remains outstanding and uncertain.

3 Uruguay

In June 2020, the Group was notiﬁed by ANCAP, the Uruguayan state oil company, of the award of the Area OFF-1 block offshore Uruguay. At the balance sheet date, formal issuance of the licence remained outstanding, however, subsequent to the balance sheet date, the licence was formally signed on 25 May 2022. As a consequence, the Group will have a commitment to undertake various technical investigations over the licence block before the expiry of the four-year exploration period commencing 25 August 2022.

4 The Bahamas

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 Group commence an exploration well before the end of the extended term. In November 2020 the term of the licence period was extended to 30 June 2021 following the outbreak of the global Covid-19 pandemic and the declaration of the Group of force majeureunder the terms of its licences. On 20 December the Group commenced the drilling of its licence obligation well in the Bahamas, Perseverance 1, which was completed on 7 February 2021. As such, at present, the Group does not have any committed work obligations in The Bahamas. In March 2021 the Company notiﬁed the Government of the Bahamas that it was renewing the four southern offshore exploration licences for a further

three-year period, having discharged its obligations under the previous licence term. The Group remains in discussions with the Government over the terms of the renewal of these licences and, once renewed, will have the obligation to commence a further exploration well in the licence area before the expiry of the next three-year term.

Annual licence rental commitments

The Group is required under its Bahamian exploration licences to remit annual rentals in advance to the Government in respect of the licenced areas.

On 27 February 2020, the Company advised that, consequent on the granting of Environmental Authorisation for the Perseverance-1 well, the Company and the Government of The Bahamas had agreed a process seeking a ﬁnal agreement on the

amount of licence fees payable for the balance of the second exploration period (including the additional period of time to which the licence period was extended as a result of force majeure). At the time, the parties entered into discussions with a view to ﬁnalising this outstanding matter. This discussion has been delayed owing to the State of Emergency declared and ongoing business disruption caused by the national response to the Covid-19 outbreak in The Bahamas. However, subject to said conﬁrmation, the Company expects that an appropriate side-letter agreement will be ﬁnalised in due course.

In March 2021 the Company notiﬁed the Government of The Bahamas that it was renewing the four southern offshore exploration licences for a further three-year period, having discharged its obligations under the previous licence term. The Group remains in discussions with the Government over the terms of the renewal of these licences, which will include agreement on the level of annual rental fees payable over the renewed term.

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

27 Related party transactions - Group & Company

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

Remuneration of Key Management Personnel

The Directors of the Company are considered to be the Key Management Personnel. Details of the remuneration of the Directors of the Company are disclosed below, by each of the categories speciﬁed in IAS24 Related Party Disclosures.

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

See note 7 for further details of the Directors' remuneration and note 24 for details of the Directors' share-based payment beneﬁts. On 23 July 2021, share options were granted to key management personnel as follows.

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28 Events after the reporting period - Group & Company

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

As at the date of this report the completion of the Transaction is conditional on consent of the Trinidadian Ministry of Energy and Energy Industries ("MEEI") to a revised work programme for the Cory Moruga licence and restructuring of certain licence terms. The parties have agreed to work together to secure the required consents and agreements with MEEI and thus achieve completion of the Transaction as soon as reasonably practicable with a long stop date of 31 August 2023. Refer to note 15 for further details.

On 14 February 2023 the Company announced that it had entered into and completed a transaction for the sale of its St Lucia domiciled subsidiary company, Caribbean Rex Limited which included its associated assets and subsidiary entities. This includes (via interposed subsidiaries) CEG South Erin Trinidad Limited, a Trinidadian company that is party to a farm-out agreement for, and is the operator of, the South Erin ﬁeld, onshore Trinidad) and West Indian Energy Group Limited (a Trinidadian service company). Refer to note 15 for further details.

On 5 June 2023, ANCAP announced it has awarded the AREA OFF-3 block, offshore Uruguay, to the Company, subject to licence signing. The award of AREA OFF-3 will expand the Company's licence holding in Uruguay to two blocks, in the offshore Punta del Este and Pelotas sedimentary basins (AREA OFF-1 and AREA OFF-3) and will position the Company's acreage on either side of Shell's AREA OFF-2 block.

On 14 June 2023 the Company announced that CEG Goudron Trinidad Limited ("CGTL"), an indirectly wholly owned Trinidadian subsidiary, has been notiﬁed by the Trinidad and Tobago Ministry of Energy and Energy Industries ("MEEI") that the Government of Trinidad and Tobago has authorised MEEI to enter into negotiations with CGTL for the grant of an Exploration and Production (Public Petroleum Rights) Licence for the Guayaguayare block (the "Licence"), following a successful bid for that Licence by CGTL. The Guayaguayare block is located onshore in south-east Trinidad. It is one of the largest onshore exploration and production blocks in Trinidad (approximately 306 km2), and is strategically and operationally synergistic with the Company's core Trinidadian production business, in that the Licence wholly encloses the Company's Goudron licence area, and is adjacent to the Company's Inniss-Trinity licence area. At the date of this report, the formal award of the licence remains subject to negotiations and ﬁnalisation of the Licence terms with MEEI.

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

The Company's proﬁt after tax for the year was $1,330,000 (2021: loss of $15,515,000).

Corporate Directory

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

Current Directors Iain McKendrick Simon Potter

Non-Executive Chairman Non-Executive

Stephen Bizzell Eytan Uliel

Non-Executive Chief Executive Officer

Secretary Benjamin Proffitt

Registered Office and The Engine House

Corporate Headquarters Alexandra Road, Castletown

Isle of Man IM9 1TG

Registrar Link Market Services (IOM) Limited

PO Box 227

Peveril Buildings Peveril Square Douglas

Isle of Man IM99 1RZ

Auditor Grant Thornton

13-18 City Quay

Dublin 2 Ireland

Principal Legal Advisors Clyde & Co

St Botolph Building 138 Houndsditch London

EC3A 7AR

United Kingdom

Nominated Advisor WH Ireland plc 24 Martin Lane London

EC4R 0DR

United Kingdom

Brokers Arden Partners plc WH Ireland plc

125 Old Broad Street 24 Martin Lane

London London

EC2N 1AR EC4R 0DR

United Kingdom United Kingdom

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Challenger Energy Group (CEG)

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