Interim Financial Statements

Predator Oil & Gas Holdings Plc / Index: LSE / Epic: PRD / Sector: Oil & Gas

Predator Oil & Gas Holdings Plc

("Predator" or the "Company" and together with its subsidiaries "the Group") Report and Interim Financial Statements for the 6 months to 30 June 2026

Financial highlights:

·  The Group has cash reserves as at 30 June 2026 of £6.6mil (31 December 2025 £1.5mil).

·  The Group also holds £1.5mil (31 December 2025: £1.5mil) in restricted cash balances (bank guarantees and performance bonds).

·  The Group generated £1.5mil in production revenues for the 6 months period ended 30 June 2026 (£66,815 for period to 30 June 2025).

·  Trinidad operations generated a gross profit of £283,041 for the 6 months period ended 30 June 2026 (£66,815 gross profit for the 6 months period ended 30 June 2025).

·  The Group reported an operating loss for the 6 months period ended 30 June 2026 of £0.9mil (£1.9mil for the 6 months period ended 30 June 2025).

·  The Group’s Intangible assets increased at 30 June 2026 to £27.3mil (31 December 2025: £26.2mil), mostly due to costs incurred to advance the drilling of two wells in the second half of 2026 (MOU-6 and Snowcap-3).

·  Administrative corporate costs for running the day-to-day business of the Company increased for the 6 months to 30 June 2026 to £1 .2mil (30 June 2025:

£821,277). The increase is attributable to the acquisition of a group of companies and the enlargement of the Trinidad office to oversee administration and accounting of the production revenues and to prepare for drilling operations and production facilities at Cory Moruga. Included in the aforesaid administrative expenses were £489,506 in non-cash items related to Trinidad companies which were first-time inclusions after the acquisition of the group of companies from the Challenger Energy Group. The administrative expense also includes a net positive change from foreign exchange losses for the six months to 30 June 2025 of

£341,563 to foreign exchange gains in the corresponding current period of £136,761.

·  Consultant fees for the 6 months to 30 June 2026 increased modestly to £145,223 (30 June 2025: £129,639), reflecting the addition of well planning activity in Trinidad.

·  128,571,419 shares issued to raise £4.5 mil in January at a placing price of 3.5pence; and 85,714,286 shares issued to raise £3.0 mil in May at a placing price of 3.5pence.

·  9,000,000 and 6,000,000 warrants granted at 3.5 pence per share, exercisable within 3 years from 23 January 2026 and from 20 May 2026 respectively.

·  Shares in issue increased to 900,602,100 at 30 June 2026 from 686,316,395 shares in issue at 31 December 2025.

·  Deployment of working capital focused on planning and preparation for Snowcap-3 (for Q1 2027 production) and MOU-6 (for Q1 2027 potential partial divestment prior to a possible development).

Post reporting date:

On 29 July 2026 the Company announced the execution of an amendment (the "Amendment") to the existing rig contract with Intrepid Drilling Limited (formerly Star Valley Drilling Limited) for Rig 101, which is currently stacked at the Company's MOU-5 well site. The Amendment to the existing drilling contract, dated 24 October 2022, allows for an extension to facilitate MOU-6 well operations for a period from 1 August 2026 to 1 October 2026.

On 12 August 2026 the Company announced the contract for the civil engineering works to prepare the Snowcap -3 drilling location to accommodate Star Valley drilling Rig 205 and the Production Facility Area has been awarded to NABI Construction (Trinidad and Tobago) Limited. Site works will commence immediately.

On 12 August 2026 the Company announced the execution of a drilling rig contract with Star Valley Drilling (Trinidad) Limited for Rig 205 and that SC-3 drilling and well testing operations will commence shortly after the completion of the MOU-6 well in Morocco. This will ensure optimum deployment of the Company's management team to efficiently supervise each individual operation in two different jurisdictions.

On 19 August 2026 the Company announced the settling of a £ 323,785 debt to Mr Paul Griffiths arising from the capitalisation of his loans in May 2023. Shares would be issued in lieu of cash to preserve the Company's cash resources and reduce the liability by the value of the Shares issued. Consequently it was agreed

a) 40% of the existing liability, being £129,514, be settled through the issue of Shares to Mr Griffiths at the closing mid-market price on 17 August 2026; and

b) The remaining 60%, being £194,271, will become payable upon the earlier of an announcement that either a stabilised flow rate of greater than 3 million cubic feet of gas per day has been achieved from MOU-6 or a stabilised oil rate of greater than 200 bopd has been achieved from Snowcap-3. Mr Griffiths was issued with 3,866,090 Shares at a price of 3.35 pence per Share.

On 19 September the Company announced that drilling operations had commenced on the MOU-6 well in Morocco.

Operational highlights:

Trinidad

·  Snowcap-3 will target independently validated 2P unrisked net recoverable oil resources of 8.73 MM.

·  Undiscounted net-back of US$32.6/barrel at WTI spot price US$60/barrel.

·  Based on offset test rates for Rochard-1 and Snowcap-1 initial production guidance is 300 bopd potentially increasing to 459 bopd when reservoirs can be commingled.

·  Snowcap-3 re-located between Snowcap-1 and Rochard-1 where the target reservoirs flowed oil on testing.

·  Improved seismic understanding supports reservoir continuity between these wells and lack of fault compartmentalisation.

·  Well to be drilled to 5,450 feet to evaluate up to 650 feet of gross reservoir interval.

·  Well planning and well inventory build continuing.

·  Site suitable for drilling and establishment of production facilities identified.

·  Regulatory approvals progressing to target first oil sales in early Q1 2027.

Morocco

·  MOU-6 will target independently validated 2P unrisked net recoverable gas resources of 72.4 BCF.

·  Well to be drilled to 950 metres to test approximately 51 metres of gross reservoir interval encountered in MOU-3, 600 metres to the SW.

·  Well planning and well inventory build continuing as scheduled.

·  41/2” perforating guns available for the first time – ordered for import with 6 months delivery schedule.

·  New well design, well engineering, and drilling mud and fluids programme completed to address and de-risk historical drilling practices that led to reservoir formation damage.

·  Extensive wireline logging and testing programme being prepared.

·  MOU-6 is being designed specifically to de-risk the potential for stable and sustainable gas flow at commercial rates. Unlike Trinidad, there are no analogue reservoirs in any offset wells to assess potential gas flow rates pre-drill.

·  A successful and satisfactory gas flow test will potentially transform the Company’s ability to conclude an ongoing partial divestment transaction early in Q1 2027 that will support a Declaration of Commerciality and an application for an Exploitation Concession in 2027, subject to regulatory approvals.

Chairman’s Statement:

On behalf of the Board of Directors, I am pleased to present the unaudited interim results for Predator Oil & Gas Holdings plc (“the Group”, “Predator” or the “Company”) for the six-month period ended 30 June 2026.

The price environment for oil and gas remains very strong, with the continuation of conflict in the Middle East remaining unresolved. At the time of writing the Brent Oil price remains close to $90/bbl.

The first half of this year has, once again, been a period of intense activity.

In Trinidad the onshore producing properties acquired from Challenger Energy have been integrated into the Company’s pre-existing portfolio. This has involved considerable administrative and financial work, which has been completed.

Also in Trinidad, there has been a great deal of operational activity of workovers and new wells in the oilfields acquired from Challenger, carried out by NABI, an experienced local service contractor at no cost to Predator. This work has managed production to a sustainable level consistent with delivering stable cash flow for financial projections. The work has importantly reduced outstanding work commitments on the Enhanced Production Services Contracts administered by Heritage Petroleum. Equally it has improved environmental performance and added infrastructure to assist future operations and marketability of the assets should there be a point in the future where an attractive divestment opportunity arises.

The highlight of operations in Trinidad this year will be the drilling of the Snowcap-3 development/appraisal well on the Cory Moruga concession, which has the potential to transform the Company’s production profile and generate truly significant cashflow.

In Morocco, planning has advanced to drill the MOU-6 well, in parallel with ongoing discussions with a preferred joint venture partner that, subject to a successful and satisfactory well test for MOU-6, would be capable supporting a Declaration of Commerciality, subject to regulatory approvals. All long-lead items for MOU-6 have been sourced and are on a schedule for delivery into Morocco, even against a background of very difficult logistical challenges as a result of the constriction of movement of cargoes through the Straits of Hormuz.

Offshore Ireland, whilst material progress to obtain a successor authorisation on Licensing Option 16/26, containing the Corrib South gas satellite prospect, has not yet been achieved prior updating our financial credentials by 30 September 2026, we remain optimistic that concerns regarding Ireland’s security of gas supply may finally provide a path forward.

The Company has continued to run a very tight ship, keeping administrative costs to a minimum, despite the addition and enlargement of the Trinidad operation, so that funds can flow through to the drill-bit.

I would again like to thank our shareholders for their continued support through the fund raisings carried out this year required to deliver the 2026 drilling programmes.

Finally, I would like to pay tribute to the tremendous efforts of the team at Predator, whose efforts have allowed the Company to move forward and drill two potentially transformational wells in the second half of the year.

Stephen Boldy

Non-Executive Chairman Operational review MOROCCO

Activities in the Guercif Licence onshore Morocco have focussed on designing, planning and executing an operational programme designed to flow gas from what is now designated as the TGB-6 Submarine Fan, which covers an area of 81 km² and has a gross interval thickness of 51 metres. In MOU-3 there are 8 sands that would form the basis of a well perforating and testing programme. The presence of biogenic gas in MOU-3 was confirmed post-drilling based on laboratory analysis of formation gas shows whilst drilling. Gas composition was 98 to 99% pure methane, which requires very little processing to achieve the necessary quality and compositional specifications to support gas sales.

Independent Technical Resources Report by Scorpion Geoscience Ltd. dated 20 February 2026 (the “ITR”) The ITR specifically focussed on the TGB-6 Submarine Fan interval only.

For the MOU-3 structural closure only within the TGB-6 Submarine Fan interval (11 km²) 2C (contingent) recoverable gas resources net to the Company’s 75% interest are assessed to be 72.4 BCF. The MOU-1 well also tested the TGB-6 Submarine Fan interval and similarly encountered formation gas shows whilst drilling. The MOU-1 structure covers 6 km². Technical studies completed in 2026 to date indicate that the MOU-1 and MOU-3 structures are linked to form a single common structure. This supports the 3C (contingent) recoverable gas resources net to the Company’s 75% interest of 151 BCF.

The TGB-6 Submarine Fan interval potential gas resources are sufficient to support a gross 10-year gas sales plateau production forecast of 10 MM cubic feet/day

(7.5 MM cubic feet/day), representing 37.8% only of the Company’s 75% interest of 2C (contingent) recoverable gas resources of 72.4 BCF.

Scope to increase the gross 10-year gas sales plateau production forecast to 20 MM cubic feet/day (15 MM cubic feet/day) is achievable based on the Company’s 75% interest of 3C (contingent) recoverable gas resources of 151 BCF, representing only 48.3% of this figure.

The ITR economic modelling yielded a gross undiscounted sales revenue net to the Company’s 75% interest of US$456 MM at an average gas sales price assumption of US$9/Mcf. The development model adopted for the purposes of estimating net cash flow is a Compressed Natural Gas (“CNG”) option. However, a Micro-LNG development option is also being considered and evaluated. The 20 MM cubic feet/day 10-year plateau production profile yields an undiscounted

EBITDA in respect of the Company’s 75% interest of 3C (contingent) recoverable gas resources of 151 BCF of US$245 MM after taxes, royalties, capital and operating costs for a Company IRR of 74%).

Larger volumes of gas would be suitable for a different development concept focussed on gas off-take into the Maghreb Gas Pipeline, which lies less than 10 kilometres from the core area of biogenic gas potential.

Conclusion

Technical studies and economic modelling carried out to date in 2026 have confirmed that the structure tested previously by the Company’s wells MOU-1 and MOU-3, and which encountered formation gas shows in the TGB-6 Submarine Fan interval, is the primary initial candidate for a Declaration of Commerciality, leading to an application for an Exploitation Concession and ultimately monetisation of the gas resources.

To achieve this objective a new well (“MOU-6”) was determined as being necessary and which is engineered to overcome the historical issues of excessively high

mud weights whilst drilling, leading to reservoir formation damage, and drilling fluids that reacted with the unusual mineralogy of the reservoir sands.

MOU-6 well planning

A surface location for the proposed MOU-6 well, 600 metres NW of the MOU-3 well, was selected. An Environmental Impact Study was completed and the well permitted in consultation with local landowners.

The pre-drill geological programme has been submitted to evaluate all horizons which exhibited formation gas shows seen in MOU-3 between approximately 300 and 900 metres depth.

The pre-drill location targets the same structure and seismic amplitude anomaly in MOU-3 (tied to the formation gas shows between 815.5 and 866.5 metres depth in the TGB-6 Submarine Fan interval). Reservoir thickness and/or quality may be further enhanced at the MOU-6 pre-drill location based on seismic modelling studies.

MOU-6 will also potentially confirm the presence of a thick (11-13 metres) sand seen at 339 metres in MOU-3, which had formation gas shows and is likely to be moderately over-pressured. The “A” Sand, as it is now designated, lies within a structural closure of 6 km² with 2C (contingent) recoverable gas resources net to the Company’s 75% interest of 21.1 BCF.

The MOU-6 well design has been re-engineered compared to previous designs for the Company’s earlier wells to allow for the following:

1. Set intermediate casing above the primary TGB-6 Submarine Fan target interval to protect the “A” Sand and any other shallow sands from formation damage; run wireline logs over the interval (not previously attempted); and preserve the interval for perforating and well testing in isolation from the primary deeper targets.
2. Drill to 950 metres total depth to leave no more than 250 metres open hole through the primary objective, the TGB-6 Submarine Fan interval. This will reduce the risk of formation damage caused previously by increasing mud weight through the mobile, increasingly over-pressured claystones, below 950 metres that are characterised by swelling clay minerals.

3. The new well design has greater flexibility and facilitates using TCP perforating guns allowing for the well to be tested immediately after well completion using the rig before demobilisation (stacked at no cost at the MOU-6 well site. This will eliminate the previous delays in having to perform rigless testing long after the completion of the well.

4. The MOU-6 well design also accommodates the ability, when required, to re-enter the well and test the “A” Sand; test other sands; deepen the well; and/or

sidetrack the well.

The well is planned to be retained as a future production well and therefore the ability to re-enter the well later in production life to comingle lower pressure sands for enhancing and prolonging production life is an important consideration.

The MOU-6 drilling programme has been prepared and submitted. The new features of the programme relative to previous drilling programmes are as follows:

1. Drilling mud and drilling fluids designed not to impact the formation mineralogy.

2. Calcium carbonate (which is soluble) and not barite (which is reactive) used to increase the weight of the mud.

3. Mud weight carefully managed to be as near as in balance with expected formation pressures to reduce the potential for formation damage.

Well testing programme designed for:

1. Using the largest 41/2” perforating guns for the first time – 6-month long lead time to import.
2. TCP well testing will allow the reservoirs to be perforated under-balanced for the first time to promote and enhance potential gas flow.

3. As a consequence, drawdown pressure can be optimised for a stabilised gas flow without production of unconsolidated sands.

All the required well inventory and well services are projected to be in Morocco ahead of anticipated mobilisation of the Sta r Valley Rig 101 (re-named by the rig owner Intrepid 11), stacked on the MOU-5 well site, within a window from August to October 2026.

Commercial activities

Alongside the planning of the MOU-6 well, the Company is engaged in commercial discussions to finance an initial gas development and the off-take and sale of the gas to end users.

Subject to a satisfactory gas test result for MOU-6 and a period of technical, commercial and legal due diligence, the Company expects to announce a binding legal agreement for the future monetisation of the gas early in Q1 2027.

Key technical and commercial risks

Currently it is not possible to predict gas flow rate from MOU-6 as there are no analogue reservoirs to give an appropriate range of possible flow rates. Therefore, although there is a gross sequence of 51 metres of potential gas the deliverability from individual sands may vary.

For guidance purposes only a stabilised gas flow rate from MOU-6 in the range 5 to 10 MM cubic feet g/d, combined with no evidence of significant reservoir pressure depletion during the conduct of the well test, will be seen by the Company as a result that would support an initial gas development.

The commercial risk is only attributable to the inability to flow gas from MOU-6 within the above guidance rates.

Other prospectivity: desk-top studies

Additional biogenic gas targets have been re-evaluated. Of significance is the potential for biogenic gas in up to 800 metres of section penetrated in MOU-1. This comprises a very finely laminated section that cannot be resolved by conventional wireline logs. The Company has been preparing a scope of work for an independent contractor with experience in producing biogenic gas in a similar setting and from an analogue section in Romania and Ukraine. The objective will be to determine if there is a basis for developing a work programme to further evaluate potential to produce from this interval. The Company has identified a core area of 120 km² where this potential biogenic gas play is developed.

Studies have progressed to assess the appropriate work programmes to evaluate Jurassic and Triassic prospectivity for the large structural closure drilled by the MOU-5 exploration well in 2025. An option to deepen the well to the Trias will be considered in the future.

A high-level scoping study for the potential to create caverns in the Triassic salt interpreted to be present below the present depth reached by MOU-5 has been completed. The site is favourably located within 3 kilometres of the Maghreb Gas Pipeline to support gas storage economics.

The model for helium generation and the origins of helium gas in MOU-3 and MOU-5 has been supported by further geophysical studies.

Guercif Licence terms

An extension of the First Extension Period of the Guercif Licence to 5 November 2026 was applied for and approved.

A further extension to 5 February 2027 is being applied for and is expected to be approved before the end of 2026. This will enable the results of the MOU-6 well to be fully evaluated by all parties.

All parties to the Guercif Licence agree that the results of the MOU-6 well, with the potential de-risking of gas flow at commercial rates, will have a material impact on the scope of the future work programmes for the Guercif Licence. This may include, for example, a separate application for an Exploitation Concession and a new work programme for the remaining area of the Guercif Licence to be delivered within an extended timeline that reflects th e multiple prospects created by the Company through the drilling of six wells in the exploration phase to date. Of significance is that there is currently no legislation in place in Morocco for the extraction of helium.

TRINIDAD

Activities onshore Trinidad have focussed on:

Cory Moruga Exploration and Production Licence – Snowcap Structure

Designing, planning and executing an operational programme designed to flow oil at material rates from what are defined as the Gr7a Karamat Herrera and Cipero Herrera sands Herrera sands. These span a gross interval varying from 509 to 650 feet in thickness. The interval contains 8 separate, independently sealed, reservoir intervals. All the intervals have produced oil in the former BP Moruga West field approximately 1.25 kms. to the WSW, where approximately 23 million barrels of oil has been recovered over nearly 70 years.

Goudron, Inniss-Trinity, Icacos and Bonasse producing fields

Monitoring production data from these fields, which are under the operational management of NABI Construction (Trinidad and Tobago) Limited ("NABI”), and from which the Company receives 30% of gross sales revenues after deduction of royalty and taxes from production resulting from well-workovers of the existing wells in the field. For new wells drilled by NABI the Company receives 15% of gross sales revenues less royalty and taxes increasing to 30% after NABI has recovered its invested drilling costs.

NABI’s operations are performed under the terms of a Master Services Agreement (“MSA”) with the Company.

In its capacity as non-operator, the Company monitors monthly the performance of NABI under the terms of the MSA to assess stabilised production rates and growth potential; completion of licence commitments; new investment in maintaining and upgrading infrastructure and subsurface geological and reservoir engineering competence.

Cory Moruga Exploration and Production Licence – Snowcap Structure

Independent Technical Resources Report by Scorpion Geoscience Ltd. dated 20 February 2026 (the “ITR2”)

ITR2 addresses the pre-drill oil resources being targeted by the proposed Snowcap-3 appraisal/development well.

Snowcap-3 will be testing an area of structural closure for the top of the Herrera #8 Sand of 2.51 km². 2P recoverable oil resources net to the Company’s 100%

interest are assessed to be 8.73 MM barrels. This is based on only the Herrera #1, #2, #3 and #7 (now re-correlated as #8) Sands.

The ITR2 economic modelling assumed a 10-year production profile for the Herrera #1 and #2 Sands with an unescalated WTI spot price of US$60 per barrel. This yielded an undiscounted net-back of US$32.6 per barrel produced.

The Company’s later updated project economics are based on an initial oil rate of 300 bopd from the Herrera #1 Sand to be tested by Snowcap-3. The Herera #1 Sand is the basal sand in the gross Herrera interval. The topmost sand, Herrera #8, has an assumed initial oil rate also of 300 bopd but is only produced when the Herrera #1 Sand reservoir pressure has fallen after up to 12 months of production so as to enable comingling of production at a common pressure at an initial combined rate of 459 bopd. A 10-year production forecast for the single Snowcap-3 well cumulatively recovers 489,336 barrels of oil (80,229 barrels in the first year of production at an average of 220 bopd).

At an unescalated WTI spot price of US$75 per barrel this gives an undiscounted net-back of US$41.02 per barrel produced and net undiscounted revenues to the Company’s 100% interest of US$2,564,320 for the first 12 months of production. These post-tax revenues are after Petroleum Profit Tax (“PPT”), which is reduced from 50% to an effective rate of 12.5% by utilising legacy material tax losses when the Company acquired the entity holding the Cory Moruga Licence interest.

The Company’s initial production rates are based on comparison with offset wells on the Snowcap Structure. Snowcap-1, to the NE of the proposed Snowcap-3 well location, tested the Herrera #8 Sand at a stabilised rate of 500 bopd of light oil. Rochard-1, SW of the proposed Snowcap-3 well location, tested the Herrera #1 Sand at an initial rate of 312 bopd of light oil.

The proposed Snowcap-3 well is being designed to be retained as a production well. The wireline logging, perforating and well testing programme will be sufficiently comprehensive to potentially validate the pre-drill forecast production rates and reservoir pressure depletion profile.

Snowcap-3 well planning

Following new geological and geophysical studies the original surface location for the proposed Snowcap-3 well has been moved approximately 1700 metres to the SW of the original surface location, which lay to the NE of Snowcap-1. A legacy Certificate of Environmental Clearance already exists for seven wells in the Cory Moruga Exploration and Production Licence. This will be updated specific to the new Snowcap-3 proposed well location and to include the establishment of production facilities at the site.

The rationale for moving the location was as follows:

1. Seismic re-mapping of a newly acquired legacy version of the re-processed 3D seismic indicated that the area around the original location was defined by poorer seismic data quality, possibly attributable to fracturing and the presence of gas.

2. The original location on the crest of the Snowcap Structure is structurally higher than Snowcap-3. A gas cap may therefore be developed at this location.

3. At the original location the thrust fault defining the Snowcap structural trap is relatively flat-lying and hard to seismically image. There is a greater risk therefore of missing key Herrera reservoir sands (as historically in Snowcap-1) if the fault position is poorly constrained.

4. The revised well location for Snowcap-3 is now located between the Rochard-1 well to the SW and the Snowcap-1 well to the NE – that is between two wells that have tested oil at good initial rates from the Herrera reservoirs. The new location is favourably positioned well below any potential gas cap, expansion of which can also provide the mechanism for primary oil recovery.

5. Much improved seismic correlation of Snowcap-1 with Rochard-1 and an improved seismic tie of the deviated Snowcap-1 well, which historically had been mis-tied by previous operators, has identified the Herrera #8 Sand in Rochard-1, which tested oil at an initial rate of 720 bopd, as the same Herrera #8 Sand as in Snowcap-1, which tested oil at a stabilised rate of 500 bopd.

Based on a revised Herrera #8 Sand reservoir map the new Snowcap-3 well location is optimally located for well-developed oil sands, whereas the interval is not likely to be well-developed at the original well location.

The new sand trend is mirrored at the deeper Herrera #1 Sand target level and the expectation is for well-developed Herrera #1 Sands to be present at this depth too.

6. Seismic imagining of the fault defining the Snowcap Structure at the new Snowcap-3 location is unambiguous. Therefore the risk of missing key Herrera sand intervals that are faulted out is eliminated.

The new surface location allows for the drilling of a vertical well adjacent to a main road, thereby dismissing any requirement for a deviated well at extra cost and improving site access to production facilities and oil storage tanks.

Conclusion

The new Snowcap-3 location is optimal for reservoir development, structural integrity, cost savings, and logistical planning. Commercial and technical risk of failure are greatly reduced.

The pre-drill geological programme has been submitted to evaluate all horizons which both flowed on test in Rochard-1 and Snowcap-1 and which have produced oil in the nearby Moruga West field between approximately 4,700 and 5,400 feet depth.

The pre-drill location targets the same structure as was tested by Rochard-1 and Snowcap-1. The Snowcap-3 well design has been engineered based on the tried and tested Snowcap-1:

1. Four strings of casing – 20”, 133/8”, 95/8“ and 7” Completion liner.

2. Drill to 5,450 feet total depth and set intermediate 95/8“ casing at 4,200 feet depth, to leave no more than 1,250 feet open hole through the primary objective, the Herrera sands interval. This will reduce the risk of formation damage if mud weight has to be increased through mobile, potentially over-pressured claystones, above 4,200 feet depth that are characterised by swelling clay minerals.

3. The well design facilitates rigless testing of the Herrera reservoir interval immediately after well completion. This will eliminate delays in having to perform rigless testing long after the completion of the well.

The Rochard-1 and Snowcap-1 light oils are waxy in nature, therefore well planning is focussed on flow assurance from the tested reservoirs and placing them on production as early as possible after completion of the well to prevent any down-hole wax build-up that can restrict future production rates without well intervention and wax treatments.

Accordingly, the civil engineering scope of work for the Snowcap-3 well pad layout includes designating an area for the establishment of production facilities.

4. The Snowcap-3 well design also accommodates the ability, when required, to re-enter the well and test other Herrera sands (potentially #4, #5 and #6 Sands) if warranted after wireline logging results.

The well is planned to be retained as a future production well and therefore the ability to re-enter the well later in production life to comingle lower pressure sands for enhancing and prolonging production life is an important consideration.

An amendment to the well design is currently under consideration as follows:

1. The Herrera #1 and #2 Sands are separately sealed from the shallower Herrera sands and may be over-pressured based on old data from the Rochard-1 well (1955) requiring a potential significant increase in mud weight whilst drilling into this section.

2. In order to protect the shallower Herrera #8 Sand from potential formation damage, another string of casing may be set at approximately 5,100 feet depth before drilling into the Herrera #1 and #2 Sands.

The above option, if selected, will allow the flexibility for the Herrera #1 and #2 Sands to be tested and put on production first and for the well to be re-entered in the future to comingle the shallower Herrera #8 Sand when downhole reservoir pressures have equalised.

The Snowcap-3 drilling programme has been prepared based on:

1. Drilling mud and drilling fluids designed to address the presence of swelling clays.
2. Mud weight carefully managed to be as near as in balance with expected formation pressures to reduce the potential for formation damage.

Well testing programme designed for:

1. Using the largest 41/2” perforating guns.
2. Obtaining a stabilised oil flow rate and connected oil volume to the well-bore to assist with future development well planning.

3. Optimising drawdown pressure for a stabilised oil flow rate without production of unconsolidated sands.

4. Maintain oil production to prevent wax build-up.

Rig selection

Initial Snowcap-3 well planning focused on potentially re-activating a stacked rig with the capability of drilling to 5,500+/- feet depth. As the Snowcap-3 well design and drilling programme evolved, it became clear that significant operational and execution risk would be created by mobilizing a rig stacked for over 5 years to drill through the potentially over-pressured Herrera #1 and #2 Sands. The Company concluded that this was an unacceptable risk to bear given the importance of the Snowcap-3 well to its near-term business development strategy. An alternative option arose to use the Star Valley rig 205, which had a recent history of drilling high pressure wells for another operator near to Cory Moruga. Additionally, Star Valley is well-known to the Company having drilled 5 wells in the Guercif Licence. The new rig option was more cost effective and gave greater certainty of operational readiness. Accordingly, the rig reactivation programme was abandoned with no cost to the Company.

All the required well inventory and well services are projected to be in Trinidad ahead of an anticipated mobilisation of the Star Valley Rig 205 within a window

from August to October 2026 and/or following the completion of the Company’s planned MOU-6 drilling programme in the Guercif Licence in Morocco.

Commercial activities

Alongside the planning of the Snowcap-3 well, the Company is engaged in commercial discussions to secure options on several potential Sales Points for the Snowcap-3 oil, based on a trucking operation initially and a minimum amount of storage capacity available at the selected Sales Point.

Third-party funding of the Snowcap-3 production facilities, based on the pre-drill expectations of the production profile, is envisaged currently not to be necessary given the development costs are less than the 10% contingency allowed for the drilling and testing costs for Snowcap-3.

A full-field development plan will only be considered after 6 month of production from Snowcap-3 to allow for planning the required scaled up facilities and infield development wells.

Under the terms of the Sale and Purchase Agreement for the entirety of Challenger Energy Group Plc’s St. Lucia-domiciled subsidiary company, Columbus Energy (St. Lucia) Limited (“CEG Trinidad”) and its business and operations in Trinidad and Tobago effective 29 August 2025, a further instalment of the Consideration is scheduled for 29 August 2026. It is likely that this will be successfully renegotiated so as to have no impact on the available cash to the Company in 2026.

Key technical and commercial risks

The primary risk is operational. This is the first well to be drilled by the Company in Trinidad as operator. Whilst many of the potential issues to be faced whilst drilling are manageable there remains a risk of an unforeseen and un-planned for event.

The gross Herrera reservoir sequence is 509 to 650 feet thick. Reliable offset production data for these reservoirs exist, including within the same structure as Snowcap-3 is re-appraising.

For guidance purposes only an initial oil flow rate of 300 bopd increasing to 459 bopd is potentially achievable. However, this may be impacted by factors such as wax drop out, gas content, water cut, oil decline rate and connected volume to the wellbore. These pre-drill variables can only be de-risked following the completion of a rigless well testing programme over a period of at least 3 days.

The commercial risk is attributable to the inability to flow oil from Snowcap-3 at less than, for guidance purposes only, 50 bopd.

Minimal production facilities are required to process oil to be trucked to a Sales Point. Should these costs escalate or require more infrastructure to handle larger than anticipated pre-drilling estimates of production, then development costs for Snowcap-3 may escalate. In such a scenario the potential to debt-finance if absolutely necessary the extra costs is an option should Snowcap-3 generate reserves capable of reserves-based lending given the robust cashflow projections for the independently assessed project economics.

Cory Moruga Licence terms

Cory Moruga is already an Exploration and Production Licence. There is no impediment to producing oil from Snowcap-3.

Goudron, Inniss-Trinity, Icacos and Bonasse producing fields

The Company has continued to monitor production data and, more importantly, its attributable sales revenues from these fields, which are under the operational management of NABI under an MSA.

The Company has no cost exposure to the investments made by NABI under the MSA in field infrastructure, heavy workovers and any potential new drilling. Neither has it any exposure to field operating costs.

Since the acquisition of these assets in 2025, the Company has benefited from the establishment of an administrative structure, operational “know-how” and regulatory procedures, and a network of service contractors necessary for it to establish its own production facilities for the Cory Moruga Licence and the proposed Snowcap-3 appraisal/development well. The acquisition of oil storage tanks at the Bonasse field was particularly significant as some will move to the Snowcap-3 production facilities site.

The throughput and services agreement with Steeldrum Oilfields South Erin Trinidad Limited (“Steeldrum”) that allows the Company to sell all crude oil from the Bonasse field via access to the existing crude oil sales arrangement and under the same commercial terms and conditions applicable to Steeldrum under the said arrangement. This agreement was important to have established as it defined the Company as an oil producer and provided inval uable commercially sensitive information to input into our Snowcap-3 project economics.

Since inception in 2025, implementation of the MSA for the acquired fields has resulted in:

1. Reduction of field operating costs such that the fields are now making an operating profit to offset against material tax losses.
2. Significant investment in infrastructure by NABI is providing new electrical infrastructure and access to formerly inaccessible wells for heavy workovers.
3. A programme of heavy workovers is being implemented to satisfy the licence work programme commitments.

GY-664 and GY-665 in the Goudron field are currently adding 34 and 18 bopd production respectively.

4. In the first 6 months of 2026, gross sales oil was 52,310 barrels realising net petroleum revenues of £1,522,877 (before cost s).

Under the MSA the Company’s cost-free share of petroleum revenues was £306,283.

For June 2026, reflecting increasing WTI spot prices, the Company’s monthly cost-free share of petroleum revenues was £71,690 (US$96,058 exchange rate 1.3399 on 30 June 2026).

A key objective of the Company that has evolved during the first six months of 2026 is to manage field operating costs and profitability to maintain and demonstrate a stabilised net revenue income.

The factors that impact the desired objective are as follows:

1. Operational efficiency – less focus on poorly performing, high-cost intervention, production wells and more focus on delivering a stable production profile.

2. Managing the production profile in combination with oil price volatility to hold back increasing rates until the global oil markets stabilise.

Factors that impact this strategy include:

1. Goudron and Inniss-Trinity fields are each operated under a separate Enhanced Production Services Contract (“EPSC”) with Heritage Petroleum Limited (“Heritage”).

These have commercially less attractive fiscal terms – including royalties to Heritage and a First Tranche Sales oil quota sold to Heritage at a very much reduced price to WTI spot price.

2. Fair Market Value for oil sold to Heritage from the EPSC is significantly below the WTI spot price, to reflect the Heritage handling cost in exporting and selling the oil.