Interim Financial Statements

Predator Oil & Gas Holdings PLC

30 September 2026

 

30 September 2026

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.

In June 2026, for example, the monthly averaged Fair Market Value achieved by the Company was US$73.176/barrel compared with the WTI spot price of US$84.135/barrel, representing a discount of 13%.

The Fair Market Value discount is variable every month, depending on increases in logistical and export costs arising from the global freight and shipping market, which has been negatively impacted by the impasse in the Straits of Hormoz.

Another factor that has to now to be considered in 2026, and was not a key concern previously, is that when the price received for oil sales exceeds US$75/barrel,

then 18% Supplementary Petroleum Profit Tax (“SPPT”) becomes payable on all production. This cannot be offset against the Company’s legacy tax losses.

Therefore, any production increase must be sufficiently large and immediate to offset the negative impact on SPPT on revenues at this time of unforeseen high WTI spot prices and price volatility.

The Company’s revised strategy during 2026 has therefore been to stabilise production on existing fields and focus on the higher potential production targets for Snowcap-3 in the Cory Moruga Exploration and Production Licence. This is a direct Ministry licence free from the additional fiscal burdens of a Heritage EPSC. The forecast production levels are sufficient to offset any material impact from the imposition of SPPT on projected sales revenues whilst efficiently utilising the Company’s tax losses to reduce PPT liability to 12.5%.

Operational highlights

During June 2026, 21 well interventions were performed on in the fields with 13 wells restored to production, 6 wells moved f rom swabbing to pumping (reducing operating costs).

The overall active well base was increased to 100 wells (83 pumping oil, 13 swabbing oil and 4 wells flowing naturally).

Monthly production was 9,429 barrels in line with stabilizing the production profile in line with minimising operating costs and management of oil price volatility, royalties and taxes.

Operating efficiency was 83.8%, partly impacted by adverse weather, representing the monthly accumulation of 17,830 man hours for which the Company has no cost exposure.

In the Bonasse field, new shallow wells BON-18, BON-19 and BON-20 were drilled during the end of 2025 into early 2026 by NABI at no cost to the Company. These have all been placed on production and are pumping oil. The Company interprets there to be more potential to be realised by deepening at least one of these wells and recompleting an interval for enhanced production. It also identifies several opportunities for new drilling in un-evaluated areas. In order to realise any new potential, the Company would be required to use its own subsurface technical team to plan and operate the drilling and testing strategy. Currently this is not an immediate priority as the focus is on the potentially much higher reward offered by the Snowcap-3 appraisal and development well. A subsurface technical audit of the entire portfolio governed by the MSA will be initiated after the Snowcap-3 operations have been completed and potential sales production established.

Other projects: desk-top studies

1. Potential re-entry of the Jacobin-1, Snowcap-1, and Snowcap-2ST1 wells for heavy well workovers and SGN thermochemical wax treatment continues to be assessed. Key issues that have been considered during 2026 are as follows:

1. Snowcap-1 is now seen as an ideal location for a gas injector into the Herrera #8 Sand to utilise gas produced during later production for gas injection to boost oil recovery.

2. The Herrera #6 Sand was penetrated at the oil-water contact in Snowcap-1. There is potential for an updip appraisal well to access specifically this sand to target P50 recoverable oil resources of 1.91 MM barrels.

Any potential production from a Snowcap-3 heavy workover will reduce capacity for storage and sale of Snowcap-3 production. As a result, Snowcap-3 production might have to be scaled back, potentially increasing the risk of wax dropout.

On this basis a re-entry of Snowcap-1 does not warrant executing at this time.

3. The Snowcap-2ST1 well Herrera #8 Sand did not flow naturally on perforating and testing due to extensive formation damage whilst drilling by using high mud weights to over-control borehole stability.

The deeper Herrera #1 Sand reservoir likewise suffers from formation damage and borehole conditions dictated that no wireline logs could be run through this section.

The well is now a candidate to re-enter and run wireline logs over the Herrera #1 Sand interval and potentially perforate for well testing.

The operational risk versus reward versus cost of execution will be better understood is Snowcap-3 successfully flows oil at satisfactory rates from the Herrera #1 Sand.

On this basis a re-entry of Snowcap-1 does not warrant executing at this time.

4. The Company’s analysis of the Jacobin-1 well oil recovered after a fluid level survey indicated a significant wax content that may have influenced the poor results when the well was originally perforated.

On that basis the well was determined as potentially suitable for a pilot SGN thermochemical wax treatment.

The holders of the rights to use the patented SGN thermochemical wax treatment in Trinidad have been approached multiple times to demonstrate an ability to manufacture the quantities of wax treatment required, frequency of treatment and the optimum safe method of administering the wax treatment (most probably a coiled tubing unit). To date nothing of substance has been forthcoming to facilitate an economic analysis of the treatment to determine its commercial viability.

Re-entering Jacobin-1 at this time is not a priority for the Company as it focuses on delivering the Snowcap-3 drilling programme.

2. Desk-top studies are being considered to:

1. Evaluate the potential of poorer quality, claystone-laminated, oil reservoirs, currently not considered in the Snowcap Structure as a contribution to oil resources; for production based on analogues in the Moruga West field.

2. To re-assess the economics of CO2 EOR based on the successful application of the technique by the Company in the pilot CO2 EOR Inniss-Trinity project.

The ability of C02 EOR to break down wax and lower the viscosity of oil has been documented and is a possible alternative to SGN thermochemical wax treatment. Enhanced oil rates were recorded in the CO2 EOR Inniss-Trinity pilot project.

The technique may be applicable to the poorer quality, claystone-laminated, oil reservoirs in particular.

C02 purchase must be State-subsidised to improve project economics – this would be an appropriate use of the Green Levy Fund in Trinidad To reduce CO2 emissions from ammonia plants.

3. Assess the potential for deep Cretaceous gas in the Cory Moruga licence area.

Currently the database is poor and the concept is conceptual at this early stage. Well costs are likely to be very high and w ell beyond the financial capability of the Company.

All the above desktop activities are medium term in nature and not prioritised whilst focus is on the Snowcap-3 drilling project. There is no justification for increasing corporate, administrative and technical overheads to further mature these conceptual projects at this time. A further review in early 2027 is likely.

Forward plans

Sole focus for the remainder of 2026 is to execute the Snowcap-3 drilling and well testing programme.

Subject to satisfactory well results and regulatory approvals, the well will be put on production with the target of first oil sales for the earliest opportunity in Q1 2027.

Ireland

The Company is focussed on satisfying the financial criteria determined by the Geoscience Regulation Office of the Department of Climate, Energy and the Environment by 30 September 2026 to secure the award of a successor authorisation over its legacy Licensing Option 16/26 (Cor rib South). The potential award of a Frontier Exploration Licence involves no drilling commitment over the first 3-year phase of any licence (thereafter drill-or-drop within the next 3 years if going forward).

Satisfying the financial criteria only becomes a binding commitment if a successor authorisation is offered and accepted.

The regulatory process may continue for many months, therefore this should not be considered as a “near-term” project without a higher than normal level of

execution risk.

If offered a licence in the future, the Company would need to carefully consider the socio-economic-political climate in Ireland at the prevailing time of any award in order to make a considered judgement whether or not it can rely on the Irish Government support for any future operational commitments in Corrib South.

The Company believes that Corrib South is currently the only asset offshore Ireland that is still within the licensing regime umbrella that contains a structure with the highest chance of success to find gas in a structure very similar to that hosting the Corrib gas field. A single well tie-back 18 kms to the existing Corrib field, and via the pipeline to shore to the gas terminal, can prolong the life and economic viability of the infrastructure, thus reducing over-reliance on imported gas at times of peak gas and electricity demand. The lead-time to deliver the project is less than any other option the Irish government has, provided the project is treated as a strategic infrastructure project for fast-tracking.

Corrib South can deliver Ireland’s only gas storage facility quicker than any other option, subject to the proviso above.

Prolonging the life of the Corrib production facilities would enable a FSR LNG offshore import facility to be established and long-term LNG import contracts to be negotiated and executed which would lower the price of gas in Ireland and give security of gas supply.

The practical, pragmatic, strategic and economic advantages are obvious, however this is not always enough to sway the State in the decision-making processes.

GSRO within the DECC to secure the award of a successor authorisation. The Company received from the GSRO a request for furth er clarification of the financial information it provided to the GSRO on 24 December 2024, six months after submitting the supporting financial information.

The Company is considering its response to the GSRO’s request.

Financial review:

The Group reported an operating loss for the 6 months period of £0.9mil (£1.9mil for the 6 months period ended 30 June 2025). The operating loss is after incurring administrative expenses of £1.2mil (£0.8mil for the 6 months period ended 30 June 2025).

The total loss attributable to shareholders comprised £0.9mil (2025: £1.6mil)

Administrative expenses at the Trinidad subsidiaries’ level contributed to the overall increase in administrative expense over the 2025 level due to expansion of the local office to prepare for the Snowcap-3 well planning and drilling operations and the first-time inclusion of the Trinidad Energy Ministry penalties and taxes of

£208,616 due largely to historical operational debts assumed on the acquisition of the entirety of Challenger Energy Group Plc’s (the ”CEG Business”) St. Lucia-domiciled subsidiary company, Columbus Energy (St. Lucia) Limited (“CEG Trinidad”) and its business and operations in Trinidad and Tobago; and a decommissioning cost provision of £78,188, although no decommissioning of any production wells is envisaged in the medium-term.

Administrative expenses directly related to running the day-to-day business of the corporate entity reflect a significant increase in corporate activities in 2026 with the acquisition of producing assets in Trinidad and the resultant re-structuring of multiple subsidiary companies to retain legacy tax losses and enable future

potential flexible divestment of ring-fenced individual assets. Directors fees increased to £188,133 (2025: £93,966). Consultant fees increased to £145,223 (2025:

£129,639) reflecting greater activity within the Trinidad Group. Technical services are charged by key consultants and the executive director in providing technical support and reports that would otherwise have been outsourced to third parties at competitive market rates in circumstances where acquiring similarly skilled and experienced consultants would be potentially challenging. Administrative expenses at the corporate level are also attributabl e to brokers’ fees: £76,686 on the

£7.5mil fund raises. Brokers’ commissions were settled by the issue of shares and not with cash; At the corporate level forei gn exchange losses including translation effects amounted to £43,492 (£234,187 gain for the 6 months period ended 30 June 2025).

The Company raised £7.5mil. in two placings: 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.

As a result, the number of shares in issue increased to 900,602,100 at 30 June 2026 from 686,316,395 shares in issue at 31 December 2025.

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

The Group is finishing the reporting period with cash reserves as at 30 June 2026 of £6.6mil (31 December 2025 £1.5mil). The Group has no interest-bearing debt. In addition, the Group holds The Group also holds £1,480,440 (31 December 2025: £1,455,000) in restricted cash balances (bank guarantees and performance bonds). The restricted cash balance includes a US$1.5mil (£1,134,000) security deposit for the Guercif licence in the form of a bank guarantee held in favour of ONHYM. Restricted cash of £346,440 was held in Trinidad companies at 30 June 2026 as security in favour of Heritage for licence performance bonds.

The Group generated £1.5mil (£66,815 for the 6 months period ended 30 June 2025) in production revenues from operations in Trinidad following the acquisi tions of the CEG Business in 2025 and entering into a Master Services Agreement with NABI.

Trinidad operations incurred a gross operating profit before charging administrative expenses of £283,041 (2025: £66,815)

Share based payments were significantly reduced to £54,701 (a non-cash flow item) in the current period (£1,176,935 for the 6 months period ended 30 June 2025). The reduction is due mainly to there being no new share options awarded in the period to 30 June 2026.

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

No new share options were issued and 3,000,000 share options exercisable at 10p expired during the period to 30 June 2026. The Company has no interest-bearing loans nor outstanding directors’ loans.

The Company is well-capitalised for its immediate work programmes. The situation remains under review as early drilling success in either Morocco or Trinidad will enhance the Company’s portfolio of early stage development assets, with possible early production and cashflow, and potentially partial divestment. Maintaining a prudent level of cash reserves, through considering all the diverse financing options available to the Company, will be necessary to maintain momentum towards achieving the production objectives. This is particularly relevant in the case of Trinidad where the Snowcap-3 well can potentially be placed on production relatively quickly. The Company is maintaining its undiluted equity in its key Trinidad and Moroccan projects through the initial higher risk stage of discovery and appraisal to maximise its opportunity to retain all production revenues and to demonstrate a position of operational control and undiluted ownership in future potential

divestment negotiations. This allows the Company’s assets to potentially have sufficient materiality to impact the Moroccan downstream gas market and Trinidad onshore oil production. This potentially enhances the strategic value and materiality of the Company’s assets.

Paul Griffiths

Chief Executive Officer

Paul Griffiths, Chief Executive Officer of Predator, commented:

“The Interim Financial Statements for the period to 30 June 2026 demonstrate that we are generating an operating profit in Trinidad that is set to increase significantly in early 2027 with the anticipated quantum of early production, subject to regulatory approvals, from the Snowcap-3 well.

The acquisition of our producing assets in Trinidad in 2025 laid the foundation for developing the internal structures necessary to be a technical operator of future production in our own right and to establish the commercial framework required for the sale of oil and generation of production revenues.

Snowcap-3 will be our first operated well in Trinidad and therefore much rides on the success of this eagerly anticipated well.

In Morocco we have spent considerable time on understanding and resolving the challenging issues inherent in our earlier drilling and well testing programmes that failed to deliver our expected results in this part of the Guercif Basin, which had never previously been drilled. We are confident that our pre-drill well re-design and re-engineering has reduced significantly operational risk to align with anticipated reservoir geology and formation pressures. The remaining technical and commercial risk is to demonstrate a gas flow capable of supporting a future development, subject to regulatory approvals. In this respect we are very encouraged to have progressed discussions that in an MOU-6 success case will lead to the conclusion of a partial divestment opportunity. It demonstrates that the Guercif Project has never lost the interest of those who are familiar with and understand the attractiveness of the risk-reward proposition for the biogenic gas sampled in the previous drilling campaigns.

MOU-6 will be the only well to be drilled in Morocco this year. Logistical challenges in sourcing and importing well inventory following the closure of the Strait of Hormoz should not be under-estimated. The Company’s well delivery team and management have worked tirelessly together to ensure that we have secured all of our required specialist well logging tools and even the larger 41/2” perforating guns to create the best opportunity for a successful result for the MOU-6 well.

In order to deliver the 2026 drilling programme, we have taken the necessary steps to ensure that we are adequately capitalised for the forecast eventualities in the coming months before production revenues reach a sufficient level to fund our operations. We have continued to adopt a strategy of not entering into interest-bearing loans in the early, higher risk, stage of early project development. Neither have we diluted project equity at a premature stage of value enhancement for an “easy win” that might have reduced our control over our assets and our ability to offer an attractive material entry position into the Moroccan gas market or the Trinidad onshore oil sales market.

The immediate outlook for the rest of the year is positive with not one but two potentially transformational wells being drilled over a 3-month period in two different jurisdictions – one for gas and one for oil. Risk is diversified and reward is consummate with the effort required this year to achieve this position. I would like to thank our small operations, technical and financial team for their collective efforts. Only they would know what it has taken to achieve this position.”

Paul Griffiths

Chief Executive Officer ( ) September 2026

For further information visit www.predatoroilandgas.com

Follow the Company on X @PredatorOilGas.

This announcement contains inside information for the purposes of Article 7 of the Regulation (EU) No 596/2014 on market abuse.

For more information please visit the Company's website at www.predatoroilandgas.com:

Enquiries:

Predator Oil & Gas Holdings Plc

Paul Griffiths Chief Executive Officer

Tel: [phone]

[e-mail]

AlbR Capital Limited

David Coffman / Jon Belliss

Oak Securities

Jerry Keen

Tel: [phone]

Tel: [phone]

[e-mail]

Flagstaff Strategic and Investor Communications

Tim Thompson Mark Edwards Fergus Mellon

Tel: [phone]

[e-mail]

Notes to Editors:

Predator is an oil & gas company with a diversified portfolio of assets including unique and highly prospective onshore Moroc can gas exposure and production, appraisal and exploration projects onshore Trinidad.

Morocco offers a potentially faster route to commercialisation of shallow biogenic gas through a CNG or micro-LNG development.

The structure penetrated by the MOU-1 and MOU-3 wells is currently defined as having the best potential for an application for an Exploitation Concession in 2026. The Company is committed to partnering with entities capable of supporting a future development decision and who have already identified the opportunity as one warranting the execution of a Collaboration Agreement and a Memorandum of Understanding. Moroccan gas prices are high, and the fiscal terms are some of the best in the world. The presence of gas export infrastructure adjacent to the MOU-1 and MOU-3 structure allows for a scalable gas development after initial CNG or micro-LNG gas production over time establishes the extent of connected gas volumes and the capability of reservoirs to deliver at plateau rates over time.

Moroccan gas prices are high, and the fiscal terms are some of the best in the world.

Trinidad offers the security of a mature onshore oil province that has been producing hydrocarbons for over 50 years. Predator has assembled a portfolio of onshore producing fields with opportunities for production enhancement and additional infill development and appraisal drilling. Significant legacy tax losses, economies of scale and the application of new low-cost technologies are factors that can improve profit margins per barrel of oil produced. A Master Services Agreement with local operator NABI Construction relieves the Company of the burden and costs of operating the fields and executing drilling and heavy well workov ers. In return the Company receives 30% of gross sales revenues for which it can use its acquired tax losses to substantially reduce Petroleum Profit Tax from 50% to an effective rate of 12.5%.

Predator has an experienced management team with particular knowledge of the Moroccan and Trinidad sub- surface and operations.

Predator Oil & Gas Holdings plc is listed on the Equity Shares (transition) category of the Official List of the London Stock Exchange's main market for listed securities (symbol: PRD).

For further information, visit www.predatoroilandgas.com

Going Concern

The Group's cash flow projections indicate that the Group should have sufficient resources to continue as a going concern in a minimum committed expenditure case.

As at 30 June 2026 the Group had cash of £6.6m and no interest-bearing debt and was receiving cash flow from production in Trinidad, which, if necessary, can be re-purposed for a short period to support working capital.

Licence work programme commitments in the second half of 2026 relate to the drilling of the MOU-6 well in Morocco and the Snowcap-3 well in Trinidad. Pre-drill budget estimates for drilling have been satisfied by two placings completed in January 2026 and May 2026 raising £4.5mil and £3.0mil respectively before expenses. As a result, the Group is not expected to require funding to execute the drilling programs in Trinidad and Morocco based on current budget estimates and which have been scheduled for second half of 2026.

The April 2026 forecast for production revenues from Trinidad have had to be revised to take into account the day-to-day volatility of oil prices and the significant rises in WTI spot price, which can trigger a Supplementary Petroleum Profit Tax (“SPPT”) of 18% that is not capable of being offset against legacy tax losses, and the increase in oil export tanker costs, which impact the Fair Market Value paid by Heritage Petroleum Ltd. (“Heritage”) at the Sales Point. Under these prevailing fiscal conditions, significant increases in production must be achieved very quickly to offset the impact of 18% SPPT on the entire production output. Increasing production in the onshore fields, particularly those with the less attractive net-back due to additional Heritage royalties and First Tranche Oil terms, with modest well deliverability rates and higher operating costs does not increase cash flow by a quantum that justifies the operational effort. Therefore, the fields are being managed to support a stable and consistent monthly revenue net-back for the Company under the Master Services Agreement with NABI until oil price stabilises. Net cash flow is the key financial metric at present, not production output from the onshore fields, which is being maintaine d at an optimum level. The Company has no exposure to investment and operating costs for these assets.

During the second quarter of 2027 there is a forecast shortfall in required funding after Group overheads are taken into acco unt. There are currently no firm work programme licence obligations for 2027. All forecast operations are discretional.

Snowcap-3 in Trinidad is a development well in the Cory Moruga Exploration and Production Licence, which is expected to be producing oil, subject to a successful discretionary well testing programme, and significant monthly positive cash flow in Q1 2027 from a quantum of daily production at a sufficiently high enough sustainable level to offset any impact of SPPT as a result of high oil prices.

MOU-6 in Morocco is an appraisal well, which subject to a successful discretionary well testing programme, will satisfy a condition precedent for a partial

divestment of interest in the Moroccan asset, subject to regulatory approval, under terms that may include a staged repayment of 100% of past costs, commencing as early as Q1 2027. The Company, subject to a successful MOU-6 well, is confident that a commercial transaction will be concluded within, for guidance purposes only, the time framework forecast above.

The above are sources of additional funding by the second quarter of 2027 that are potentially available to meet working capi tal requirements and also discretionary operational commitments for the period May 2027 to September 2027.

The Group’s subsidiaries are funded by inter-company loans advanced by Predator Oil & Gas Holdings plc (the Company’). The recoverability of the inter-company loans advanced depends also on the subsidiaries realising their cash flow projections and will depend on raising either equity, and/or bank debt finance, and/or licence and/or joint venture partnerships, and/or potential partial or complete divestment of its assets in Morocco, if an attractive opportunity to monetise is presented to finance the Group’s projects to maturity and revenue generation.

The Company is well-capitalised for its immediate work programmes based on budget estimates as of 30 June 2026. The situation remains under review as early drilling success in either Morocco or Trinidad will enhance the Company’s portfolio of early stage development assets, with possible early production and cashflow, and potentially partial divestment. Maintaining a prudent level of cash reserves, through considering all the diverse financi ng options available to the Company, will be necessary to maintain momentum towards achieving the production objectives. This is particularly relevant in the case of Trinidad where the Snowcap-3 well can potentially be placed on production relatively quickly. The Company is maintaining its undiluted equity in its key Trinidad and Moroccan projects through the initial higher risk stage of discovery and appraisal to maximise its opportunity to retain all production revenues and to demonstrate a position of operational control and undiluted ownership in future potential divestment negotiations. This allows the Company’s assets to potentially have sufficient materiality to impact the Moroccan downstream gas market and Trinidad onshore oil production. This potentially enhances the strategic value and materiality of the Company’s assets.

The Board have reviewed a range of potential cash flow forecasts for the period to 30 September 2027, including reasonable possible downside scenarios. Going forward the Group has a number of different options, independent of also being able to reduce corp orate costs, by apportioning operating and administrative costs over a larger portfolio of producing assets, raise equity funds (as it has shown to be consistently capable of doing since li sting as a public company in 2018), and

accessing reserves-based lending, to potentially increase its working capital if required as follows: The existing Trinidad oil fields and licence and IPSC commitments are self-funding under the NABI Master Services Agreement. The Cory Moruga Exploration and Production Licence and Snowcap-3 oil development are expected to become self-funding when production commences in the course of the early part of 2027. Cash resources held at 30 June 2026 will be applied to drilling and testing Snowcap-3 ("SC-3") appraisal and development well. The well is scheduled for Q4 2026 and is expected to take up to 20 days to drill and log to a depth of approximately 5,450 feet. It is intended to put the well into production in Q1 2027 after drilling and testing is complete. SC-3 will potentially unlock the

independently assessed 2P resources of 8.73MM for the Herrera #1, #2, #3 and #8 Sands (previously designated #7 Sand). for the Herrera #1, #2 #3 and #4 Sands of

56.9MM barrels of oil. The cash flow forecasts for total expected Trinidad production are robust and are sufficient to cover any Working Capital Forecast shortfall during the second half of 2027.

The Group is progressing a potential partial divestment for the Guercif gas asset, which will include the principles for financing a Phase 1 CNG or Micro-LNG development, outline terms for a Gas Sales Agreement, all contingent on regulatory approvals and the award of an Exploitation Concession in 2027. Additional

principles to be included are expected to include joint venture participation in future exploration of the biogenic gas play, and Jurassic and Triassic prospectivity on the Guercif Licence. Predator Gas Ventures Limited will remain operator of the Guercif Petroleum Agreement and any future Exploitation Concession.

Predator Oil & Gas Holdings Plc

Interim financial statements for the Six months to 30 June 2026

Financial highlights

for the six months to 30 June 2026

Financial highlights:

• Fully funded to execute the drilling and testing of the two wells, one in Morocco and one in Trinidad, in the second half of 2026.
• A total of £7.5mil, before expenses, raised in two placings completed in January 2026 and May 2026. As a result, the number of shares in issue rose to 900,602,100 at 30 June 2026 from 686,316,395 shares in issue at 31 December 2025.
• The Group generated £1.5mil (£66,815 for the 6 months period ended 30 June 2025) in production revenues from operations in Trinidad following the acquisitions of the CEG business in 2025 and a MSA arrangement concluded with NABI.
• Trinidad operations incurred a gross profit before charging administrative expenses of £283,041 (2025: £66,815)
• The Group incurred a loss from operations for the 6 months period of £0.9mil (2025: £1.9mil). The loss is after incurring administrative expenses of

£1.2mil (2025: £0.8mil).

• Administrative expenses directly related to running the day-to-day business of the corporate entity have been prudently managed despite a significant increase in corporate activities in 2026. The increase in administrative expenses at the corporate level is attributable to brokers’ expenses: £76,686 on the

£7.5mil fund raises. Brokers’ commissions were settled by the issue of shares and not with cash; At the corporate level foreign exchange losses on balance sheet translation of £94,614 (£252,077 gain for the 6 months period ended 30 June 2025); and directors and technical fees £188,133 (2025: £93,966) contributed to the increase in the current period. The addition to permanent personnel of a General Manager for the Trinidad Group added to the increased level of fees in the current period. Technical services are charged by key consultants and the executive directors providing technical support and reports that would otherwise would have been outsourced to third parties at competitive market rates in circumstances where acquiring similarly skilled and experienced consultants would be potentially challenging.

• Administrative expenses at the Trinidad subsidiaries’ level contributed significantly to the overall increase in administrative expense over the 2025 level due to the first-time inclusion of the Trinidad Energy Ministry penalties and taxes of £208,616 due largely to historical operational debts assumed on the acquisition from CEG; and decommissioning costs of £78,188;
• Share based payments significantly reduced to £54,701 (a non-cash flow item) in the current period from the £1.2m (a non-cash flow item) incurred in the 6 months period ended 30 June 2025. Thereduction is duetoissuance of share options in the 6 months period ended 30 June 2025, which was notrepeated in the current reporting period.
• The total loss attributable to shareholders comprised £0.9mil (2025: £1.6mil).
• Intangible assets rose to £27.3mil (2025: £26.2mil) at 30 June 2026 mostly due to costs incurred to advance the drilling of two wells in the second half of 2026.
• The Group is finishing the reporting period with cash reserves as at 30 June 2026 of £6.6m (31 December 2025 £1.5m). The Group has no interest-bearing debt. In addition, the Group holds £1.5mil (2025: £1.4mil) in restricted cash balances. The restricted cash balance includes a US$1.5mil security deposit for the Guercif licence in the form of a bank guarantee held in favour of ONHYM. Restricted cash of £346,440 was held in Trinidad companies at 30 June 2026 as security in favour of Heritage for licence performance bonds.
• No fresh share options were issued during the reporting period and 3,000,000 share options exercisable at 10p expired during the reporting period.
• 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.
• 5,030,795 brokers’ warrants exercisable at 10.5p expired during the reporting period.

Predator Oil & Gas Holdings PLC

Condensed consolidated statement of profit or loss for the six months to 30 June 2026

		30/06/2026 (unaudited)	30/06/2025 (unaudited)
	Notes	£	£
Continuing operations
Sales Income	1	1,522,877	66,815
Cost of Sales	3	(1,239,836)	-
Gross profit		283,041	66,815
Other operating income		3,698	-
Administrative and overhead expenses	6	(1,166,126)	(821,277)
Share based payments	23	(54,701)	(1,176,935)
Operating loss		(934,088)	(1,931,397)
Finance costs	8	(43,787)	-
Financeincome	5	15,626	28,578
Loss for the period before taxation Taxation		(962,249) -	(1,902,819) -
Loss for the period after taxation		(962,249)	(1,902,819)
Loss for the period		(962,249)	(1,650,743)
Other comprehensive income
Exchange differences on translation		(94,614)	252,076
Loss for the period		(1,056,863)	(1,650,743)
Loss for the period attributable to:
Non-controlling interest		(148,280)	(15,853)
Owners of the parent		(908,583)	(1,634,890)
		(1,056,863)	(1,650,743)
Loss per share basic and diluted (pence)	11	(0.101)	(0.250)

17

Predator Oil & Gas Holdings PLC (Registered number: 125419)

Condensed consolidated statement of financial position As at 30 June 2026
		30/06/2026	31/12/2025
		(unaudited)	(audited)
	Notes	£	£
Non-current assets
Tangible fixed assets	14	2,720,626	2,920,020
Intangible asset	13	27,271,212	26,182,664
Trade and other receivables	16	2,474,599	2,407,002
		32,466,437	31,509,686
Current assets
Inventories	15	128,770	124,376
Trade and other receivables	16	1,400,608	1,540,317
Cash and cash equivalents	17	6,648,192	1,518,874
		8,177,570	3,183,567
Total assets		40,644,007	34,693,253
Equity attributable to the owner of the parent Share capital	18	46,207,586	38,707,584
Reconstruction reserve	21	(417,291)	283,734
Share based payments reserve	21	3,757,488	4,168,645
Warrants issuance cost	21	(908,183)	(1,374,041)
Foreign exchange reserve		(94,614)	-
Retained deficit		(18,226,924)	(17,412,955)
Total equity attributable to the owner of the parent		30,318,062	24,372,967
Non-controlling interest		(407,913)	(259,633)
Total Equity		29,910,149	24,113,334
Current liabilities
Trade and other payables	19	7,815,363	7,793,539
Non-Current liabilities
Provisions	20	2,918,495	2,786,380
Total liabilities		10,733,858	10,579,919
Total liabilities and equity		40,644,007	34,693,253

Predator Oil & Gas Holdings PLC (Registered number: 125419) Condensed consolidated statement of changes in equity for the six months to 30 June 2026

	Share Capital	Retained deficit Owner of the parent	Reconstruction reserve	Share based payments	Warrants issuance cost reserve	Foreign exchange reserve	Total	Retained deficit Non- Controlling Interest	Total
	£	£	£	£	£		£	£	£
Balance at 1 January 2026	38,707,584	(17,412,955)	283,734	4,168,645	(1,374,041)	-	24,372,967	(259,633)	24,113,334
Issue of ordinary share capital	7,500,002	-	-	-	-	-	7,500,002	-	7,500,002
Transaction costs	-	-	(701,025)	-	-	-	(701,025)	-	(701,025)
Cancelled options	-	-	-	-	-	-	-	-	-
Exercised warrants	-	-	-	-	-	-	-	-	-
Fair value of share options	-	-	-	-	-	-	-	-	-
Share based payments	-	-	-	(411,157)	465,858	-	54,701	-	54,701
Total transactions with owners	7,500,002	-	(701,025)	(411,157)	465,858	-	6,853,678	-	6,853,678
Loss for the period	-	(813,969)	-	-	-	(94,614)	(908,583)	(148,280)	(1,056,863)
Total comprehensive loss for the period	-	(813,969)	-	-	-	(94,614)	(908,583)	(148,280)	(1,056,863)
Balance at 30 June 2026	46,207,586	(18,226,924)	(417,291)	3,757,488	(908,183)	(94,614)	30,318,062	(407,913)	29,910,149
Balance at 1 January 2025	35,509,502	(14,677,868)	403,734	2,473,910	(1,374,041)	-	22,335,237	-	22,335,237
Issue of ordinary share capital	3,198,082	-	-	-	-	-	3,198,082	-	3,198,082
Transaction costs	-	-	(120,000)	-	-	-	(120,000)	-	(120,000)
Cancelled options	-	-	-	-	-	-	-	-	-
Exercised warrants	-	-	-	-	-	-	-	-	-
Share based payments	-	-	-	1,694,735	-	-	1,694,735	-	1,694,735
Total transactions with owners	3,198,082	-	(120,000)	1,694,735	-	-	4,772,817	-	4,772,817
Loss for the period		(2,735,087)				-	(2,735,087)	(259,633)	(2,994,720)
Total comprehensive loss for the period	-	(2,735,087)	-	-	-	-	(2,735,087)	(259,633)	(2,994,720)
Balance at 31 December 2025	38,707,584	(17,412,955)	283,734	4,168,645	(1,374,041)	-	24,372,967	(259,633)	24,113,334

Predator Oil & Gas Holdings PLC

Condensed statement of cash flows for the six months to 30 June 2026
	30/06/2026 (unaudited)	30/06/2025 (unaudited)
	£	£
Cash flows from operating activities
Loss for the period before taxation	(962,249)	(1,902,819)
Adjustments for:
Share based payment expense	54,701	1,176,935
Finance expense	43,787	-
Financeincome	(15,626)	(28,578)
Intangible asset amortisation	9,446	-
Depreciation	258,433	318
Foreign exchange	(136,761)	445,850
Equity-settled transaction	76,686	-
Decommissioning provision	78,188	-
Increase in inventories	(4,394)	-
Decrease in trade and other receivables	72,112	56,203
Increase in trade and other payables	153,939	256,569
Net cash generated (used in) / from operating activities	(371,738)	4,478
Cash flow from investing activities
Capitalised costs - Project Guercif - Morocco	(643,048)	(2,310,317)
Capitalised costs - Cory Moruga - Trinidad	(416,069)	(47,495)
Addition of fixed assets	(59,039)	(6,544)
Intangible asset on acquisition of CRex	-	(692,158)
Net cash used in investing activities	(1,118,156)	(3,056,514)
Cash flows from financing activities
Proceeds from issuance of shares, net of issue costs	6,722,288	1,880,000
Finance expense	(43,787)	-
Finance Income received	13,346	28,578

Netcash generated from financing activities 6,691,847 1,908,578

Effect of exchange rates on cash

(72,635) (91,823)

Net increase/(decrease) in cash and cash equivalents 5,129,318 (1,235,281)

Cash and cash equivalents at the beginning of the period 1,518,874 3,813,371

Cash and cash equivalents at the end of the period 6,648,192 2,578,090

General information

Predator Oil & Gas Holdings Plc (“the Company”) and its subsidiaries (together “the Group”) are engaged principally in the operation of an oil and gas development business in the Republic of Trinidad and Tobago and an exploration and appraisal portfolio in Ireland and Morocco. The Company’s ordinary shares are on the Official List of the UK Listing Authority in the standard listing section of the London Stock Exchange.

Statutory information

Predator Oil & Gas Holdings plc was incorporated in 2017 as a public limited company under Companies (Jersey) Law 1991 with registered number 125419. It is domiciled and registered at 3rd Floor, One The Esplanade, St Helier, Jersey, JE2 3QA.

Basis of preparation

The condensed consolidated interim financial statements are prepared under the historical cost convention and on a going concern basis and in accordance with UK adopted International Financial Reporting Standards ("IFRS") and interpretations issued by the International Financial Reporting Interpretations Committee ("IFRIC") adopted for use in the United Kingdom.

The principal accounting policies adopted in the preparation of the financial information are set out below. The policies have been consistently applied throughout The consolidated financial statements incorporate the results of Predator Oil & Gas Holdings Plc and its subsidiary undertakings as at 31 December 2025.

The financial statements of the subsidiaries are prepared for the same reporting period as the parent company, using consistent accounting policies. All intra-group balances, transactions, income and expenses and profits and losses resulting from intra-group transactions that are recognised in assets, are eliminated in full.

Subsidiaries are fully consolidated from the date of acquisition, being the date on which the Group obtains control, and continue to be consolidated until the date that such control ceases.

The condensed consolidated interim financial statements contained in this document do not constitute statutory accounts under Companies (Jersey) Law 1991. In the opinion of the directors, the condensed consolidated interim financial statements for this period fairly presents the financial position, result of operations and cash flows for this period.

Statutory financial statements for the year ended 31 December 2025 were approved by the Board of Directors on 30 April 2026. The report of the auditors on those financial statements was unqualified with the capitalisation and valuation of intangible assets being considered the key audit matter.

The Board of Directors approved this Interim Financial Report on XX September 2026.

Statement of compliance

The Interim Report includes the consolidated interim financial statements which have been prepared in accordance with International Accounting Standard 34 ‘Interim Financial Reporting’. The condensed interim financial statements should be read in conjunction with the annual financial statements for the year ended 31 December 2025, which have been prepared in accordance with UK-adopted International accounting standards.

Going concern

The Group's cash flow projections indicate that the Group should have sufficient resources to continue as a going concern. Projections assume a fund raise in 2027 will need to be resorted to. As at 30 June 2026 the Group had cash of £6.6m and no interest-bearing debt. Licence commitments in the second half of 2026 have been satisfied by two placings completed in January 2026 and May 2026 raising £4.5mil and £3.0mil respectively. As a result, the Group will not require funding to execute the drilling program in Trinidad and Morocco scheduled for second half of 2026. The April 2026 forecast for production revenues from Trinidad has not met expectations giving rise to a forecast shortfall in required funding during the second quarter of 2027 after Group overheads are taken into consi deration. Additional funding will need to be raised through placings in the second quarter of 2027 in order to meet all firm operational commitments for period May 2027 to September 2027.

The Group is generating production revenues from operations from Trinidad following the 2025 acquisition of the CEG Business and entering into a MSA with NABI. The teething problems encountered with NABI MSA arrangement are expected to be ameliorated during the second half of 2026 resulting in an increase in production revenues during 2027.

The Group’s subsidiaries are funded by inter-company loans advanced by Predator Oil & Gas Holdings plc (the Company’). The recoverability of the inter-company loans advanced depends also on the subsidiaries realising their cash flow projections and will depend on raising equity, debt finance, licence and/or joint venture partnerships, and potential partial or complete divestment of its assets in Morocco, if an attractive opportunity to monetise is presented to finance the Group’s projects to maturity and revenue generation.

The Board have reviewed a range of potential cash flow forecasts for the period to 30 September 2027, including reasonable possible downside scenarios. Going forward the Group has a number of different options, independent of also being able to reduce corporate costs, raise equity funds (as it has shown to be consistently capable of doing since listing as a public company in 2018), and accessing reserves-based lending, to potentially increase its working capital if required as follows: The existing Trinidad licenses are expected to become self-funding when production commences in the course of 2027. Cash resources held at 30 June2026 will be applied to drilling and testing Snowcap-3 ("SC-3") appraisal and development well. The well is scheduled for Q4 2026 and is expected to take up to 20 days to drill and log to a depth of approximately 5,300 feet. It is intended to put the well in production in Q1 2027 after drilling and testing is complete SC-3 will potentially unlock the 3P resources for the Herrera #1, #2 #3 and #4 Sands of 56.9MM barrels of oil. The cash flow forecasts for Trinidad indicate a Working Capital Forecast s hortfall commencing the first quarter of 2027. Cash Resources will be supplemented with fund raises by the parent company.

Costs in maintaining the operations in the existing fields ('workovers') will be funded from existing cash flows.

The Group will progress joint venture partnering for the Guercif gas asset to agree principles for funding the drilling and testing of the MOU-6 well and a Phase 1 gas development contingent on the application in 2026 for an Exploitation Concession.

Any intention to pursue various incremental activities in Trinidad and Morocco are likely to be funded through a farm down of some project equity interest or fresh equity raises if need be. Significant cost savings are forecast for the Group by apportioning operating costs and administrative costs over a larger portfolio of producing assets.

In Ireland, if awarded, the Corrib South licence may require funding in 2026 or 2027. Potential funding partners have been approached and an in-principle facility is being negotiated.

Directors are confident that the Group will be able to meet requirements over the course of the foreseeable future.

1. Trinidad – Cory Moruga licence

For Predator Oil & Gas Trinidad Ltd., where production revenues from its wholly Trinidad owned subsidiary, T-Rex Resources (Trinidad) Limited (TRex’) are forecast to be generated in 2027 following the drilling of the Snowcap-3 appraisal/development well. The Cory Moruga Production Licence provides the Group with the potential to generate strongly positive cashflows so as possibly to contribute organically towards further development of the Group’s assets. Capital required for a staged field development in 2027 could be funded from operating profits generated from an increasing level of accrued gross production net profits following the Snowcap-3 well. The Group may resort to the option of raising equity funding to accelerate this development if this proves to be commercially advantageous. The Group also has the option to seek a partial or complete divestment of any of its rehabilitated producing assets to indigenous local companies, where the Group’s ability to offer CO2 EOR services and expertise, accrued tax losses and the application of a patented chemical wax treatment new to Trinidad potentially enhances the value of the Group’s assets.

The Initial Work Programme agreed by TRex with the MEEI will be conducted in 2026 with the completion of the drilling of Snowcap-3.

2. Morocco – Guercif licence

In the case of Predator Gas Ventures Ltd., recovery of inter-company loans is dependent upon the Guercif drilling and rigless testing programmes successfully recovering commercial quantities of gas that can be developed and brought to market. Following significant gas discoveries in 2021 and 2023 a programme of rigless testing was undertaken in 2024 and 2025. Information gained from these work programmes has enabled the Group to enter into substantive discussions for third-party funding for the drilling of an appraisal/development well (MOU-6) as a prelude to an application for an Exploitation Concession and a fully-funded LNG development.

If an application for an Exploitation Concession is submitted in Q4 2026, the Group has until Q1 2027 to elect whether or not to carry out further exploration on the Guercif Licence in the area outside the limits of any Exploitation Concession. Electing whether or not to enter the Second Extension Period of the Guercif Petroleum Agreement, which involves committing to 3D seismic and the drilling of one well, will depend upon a final review of exploration prospects and the potential availability of funds arising from any repayment of past costs related to the ongoing joint venture partnering negotiations.

If electing not to go forward into the First Extension Period, the Group will have satisfied all its exploration licence commitments and will be entitled to the return of its USD1.5m bank guarantee.

3. Ireland

In the case of Predator Oil and Gas Ventures Ltd., the quantum of inter-company loan is relatively small and no material current expenditures are anticipated going forward in 2026. The Group is awaiting the outcome of an application for a successor authorisation to Licensing Option 16/26 (Corrib South) which is under active consideration as confirmed by the Department of the Environment, Climate and Communications (“DECC”). Acceptance of any licence award would be at the Group’s sole discretion. There are not likely to be any significant funding implications emerging from this process in 2026. In the future, the potential exists for the Company, as promoters of an LNG project to receive introduction and service providers’ fees and a free minority equity position in a joint venture vehicle to move to the project development stage. Under these circumstances the inter-company loan would constitute past costs contributing to the level of free equity. Recovery of the relatively modest inter-company loan therefore has a variety of ways of being repaid. A potential award of the Corrib South successor licence and a closing of a farm down to one of the Corrib gas field owners would potentially grant the Group access rights to the Corrib infrastructure with which to re-purpose the Mag Mell FSRU project to deliver LNG to the Corrib pipeline and for potential gas storage at Corrib South. The change in the Irish Government coalition and the deteriorating situation with relation to gas supplies and gas storage in Europe provides an incentive for a new government policy in relation to security of energy and gas supply. The proposed non-commercial Gas Networks Ireland Strategic Gas Reserve, based on a FSRU moored in the Shannon Estuary, does not address the current demands for gas for peak-time electricity generation, when renewables are weather dependent, and for subsurface gas storage as in other European countries.

Change in Accounting Standards

At the date of approval of these financial statements, certain new standards, amendments and interpretations have been published by the International Accounting Standards Board but are not as yet effective and have not been adopted early by the Group. All relevant standards, amendments and interpretations will be adopted in the Group's accounting policies in the first period beginning on or after the effective date of the relevant pronouncement.

At the date of authorisation of these financial statements, a number of Standards and Interpretations were in issue but were not yet effective. The Directors do not anticipate that the adoption of these standards and interpretations, or any of the amendments made to existing standards as a result of the annual improvements cycle, will have a material effect on the financial statements in the year of initial application.

New Standards, amendments and interpretations effective after 1 January 2026 and have not been early adopted

The Group does not believe that the standards not yet effective, will have a material impact on the consolidated financial statements.

Areas of estimates and judgement

The preparation of the group financial statements in conformity with generally accepted accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Although these estimates are based on management's best knowledge of current events and actions, actual results may ultimately differ from those estimates.

Provisions

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event and 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. Where the Group expects some or all of a provision to be reimbursed, 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. If the effect of the time value of money is material, provisions are discounted using a current pre-tax rate that reflects, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as a borrowing cost.

Share-based payments

The Group has applied the requirements of IFRS 2 Share-based Payment for all grants of equity instruments. The Group operates an equity settled share option scheme for directors. The increase in equity is measured by reference to the fair value of equity instruments at the date of grant. The liabilities incurred under these arrangements are assumed to be converted into shares in the parent company, under an option arrangement. The fair value of the service received in exchange for the grant of options and warrants is recognised as an expense. Equity-settled share-based payments are measured at fair value (excluding the effect of non-market based vesting conditions) at the date of grant. The fair value determined at the grant date of equity-settled share-based payment is expensed over the vesting period, based on the Group's estimate of shares that will eventually vest and adjusted for the effect of non-market based vesting conditions.

During the year, the Company issued warrants in lieu of fees to stockbrokers and as part of a placing ordinary shares. The warrant agreements do not contain vesting conditions and therefore the full share-based payment charge, being the fair value of the warrants using the Black-Scholes model, has been recorded immediately. The charge is recognised within the statement of changes in equity. The valuation of these warrants involves making a number of estimates relating to price volatility, future dividend yields and continuous growth rates (see Note 23).

The fair value of the share options is estimated by using the Black Scholes model on the date of grant based on certain assumptions. Those assumptions are described in note 23 and include, among others, the expected volatility and expected life of the options. The expected life used in the model has been adjusted, based on management's best estimate, for the effects of non-transferability exercise restrictions and behavioural considerations. The market price used in the model is the market price at the date of the issue of the options. Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to profit or loss over the remaining vesting period.

Where equity instruments are granted to persons or entities other than staff, the fair value of goods and services received is charged to profit or loss, except where it is in respect to costs associated with the issue of shares, in which case, it is charged to the share premium account.

The fair values calculated are inherently subjective and uncertain due to the assumptions made and the limitation of the calculations used. Further details of the specific amounts concerned are given in note 23.

Business combinations

Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the fair value of the assets given, equity instruments issued, and liabilities incurred or assumed at the acquisition date.

Identifiable assets acquired and liabilities assumed are measured and recognized at their fair value at the date of the acquisition, with the exception of income taxes, and lease liabilities. Any deferred tax asset or liability arising from a business combination is recognized at the acquisition date. Transaction costs associated with a business combination are expensed as incurred. Results of acquisitions are included in the financial statements from the closing date of the acquisition. If the consideration of the acquisition is less than the fair value of the net assets received, the difference is recognized immediately in the statements of comprehensive income. If the consideration of the acquisition is greater than the fair value of the net assets received, the difference is recognised as goodwill on the consolidated balance sheet.

The directors have included provisional fair values within the business combination note as presented above, which represent their best estimates using information available at the year end. Under IFRS 3, there is a measurement period which shall not exceed one year from the acquisition date, during which the company can, if necessary, retrospectively adjust the provisional amounts recognised at the acquisition date to reflect new information obtained about facts and circumstances that existed as of the acquisition date.

Basis of consolidation

Where the Group has control over an investee, it is classified as a subsidiary. The Group controls an investee if all three of the following elements are present: power over the investee, exposure to variable returns from the investee, and the ability of the investor to use its power to affect those variable returns. Control is reassessed whenever facts and circumstances indicate that there may be a change in any of these elements of control.

The consolidated financial statements present the results of the Company and its subsidiaries ("the Group") as if they formed a single entity. Inter-company transactions and balances between Group companies are therefore eliminated in full. Uniform accounting policies are applied across the Group.

The consolidated financial statements incorporate the results of business combinations using the acquisition method. In the statement of financial position, the acquirer's identifiable assets, liabilities and contingent liabilities are initially recognised at their fair values at the acquisition date. The results of acquired operations are included in the consolidated statement of comprehensive income from the date on which control is obtained. They are deconsolidated from the date on which control ceases.

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. Direct costs incurred in the exploration and evaluation of potential resources include exploration licences, researching and analysing historical exploration data, exploratory drilling, trenching, sampling and the costs of pre-feasibility studies.

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:

1. the costs are expected to be recouped through successful development and exploitation of the area of interest, or alternatively by its sale; or
2. 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:

1. 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;
2. substantive expenditure on further exploration for and evaluation of hydrocarbon resources in the specific area is neither budgeted nor planned;
3. 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; or
4. 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.

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.

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.

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.

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 - 5 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.

Financial assets

The Financial assets currently held by the Group are classified as loans and receivables and cash and cash equivalents. These assets are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are initially recognised at fair value plus transaction costs that are directly attributable to their acquisition or issue and are subsequently carried at amortised cost using the effective interest rate method less provision for impairment.

Impairment provisions are recognised when there is objective evidence (such as significant financial difficulties on the part of the counterparty or default or significant delay in payment) that the Group will be unable to collect all of the amounts due under the terms receivable, the amount of such a provision being the difference between the net carrying amount and the present value of the future expected cash flows associated with the impaired receivable. For receivables, which are reported net, such provisions are recorded in a separate allowance account with the loss being recognised within administrative expenses in the statement of comprehensive income. On confirmation that the receivable will not be collectable, the gross carrying value of the asset is written off against the associated provision.

Cash and cash equivalents

These amounts comprise cash on hand and balances with banks. Cash equivalents are short term, highly liquid accounts that are readily converted to known amounts of cash. They include short-term bank deposits and short-term investments.

Any cash or bank balances that are subject to any restrictive conditions, such as cash held in escrow pending the conclusion of conditions precedent to completion of a contract, are disclosed separately as "Restricted cash". The security deposit is recognised within trade and other receivables in note 16.

There is no significant difference between the carrying value and fair value of receivables.

Derecognition

The Group derecognises a financial asset when the contractual rights to the cash flow from the asset expire, or it transfers the asset and substantially all the risk and rewards of ownership of the asset to another entity.

Financial liabilities

The Group's financial liabilities consist of trade and other payables (including short terms loans) and long term secured borrowings. These are initially recognised at fair value and subsequently carried at amortised cost, using the effective interest method. All interest and other borrowing costs incurred in connection with the above are expensed as incurred and reported as part of financing costs in profit or loss. Where any liability carries a right to convertibility into shares in the Group, the fair value of the equity and liability portions of the liability is determined at the date that the convertible instrument is issued, by use of appropriate discount factors.

Derecognition

The Group derecognises a financial liability when the obligations are discharged, cancelled or they expire.

Foreign currency

The functional currency of the Group is the British Pound Sterling. Subsidiaries in the Group have the following functional currencies: United States Dollars, British Pound Sterling, and Trinidad & Tobago Dollars. 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.

31 December 2025 - £1: £1 : US$ 1.345 , £1 : Euro1.145 , £1 : MAD12.266 and £1: TT$ 9.122

30 June 2026- £1: £1 : US$1.3228, £1 : Euro1.1613 , £1 : MAD12.4319 and £1: TT$ 8.96246

Share options and Equity Instruments

Where the terms and conditions of options are modified before they vest, the increase in the fair value of the options, measured immediately before and after the modification, is also charged to profit or loss over the remaining vesting period. Where equity instruments are granted to persons other than consultants, the fair value of goods and services received is charged to profit or loss, except where it is in respect to costs associated with the issue of shares, in which case, it is charged to the share capital or share premium account.

Equity instruments

Share capital represents the amount subscribed for shares at each of the placings. The reconstruction reserve account represents premiums received on the share capital of subsidiaries and also includes directly related share issue costs.

Warrants issuance cost reserve includes any costs relating to warrants issued for services rendered accounted for in accordance with IFRS 2 - Equity-settled instruments.

The share-based payments reserve represents equity-settled shared-based employee remuneration for the fair value of the options issued. Retained earnings include all current and prior period results as disclosed in the Statement of comprehensive income, less dividends paid to the owners of the Company.

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.

Revenue recognition

Crude oil sales are recognised when control of the crude oil has transferred, being when the crude is delivered to the customer by means of a custody transfer ticket document, the customer has full discretion over the channel and price to sell the crude oil, and there is no unfulfilled obligation that could affect the customer’s acceptance of the crude oil. Revenue is recognised as this is the point in time that the consideration is unconditional becau se only the passage of time is required before the payment is due.

No element of financing is deemed present as typically, payment for the sale of the oil is received by the end of the month following the month in which the sale is recognised, which is consistent with market practice.

Taxation

The Company and all subsidiaries ('the Group') are registered in Jersey, Channel Islands and are taxed at the Jersey company standard rate of 0%. However, the Group's projects are situated in jurisdictions where taxation may become applicable to local operations.

The major components of income tax on the profit or loss include current and deferred tax.

Current tax

Current tax is based on the profit or loss adjusted for items that are non-assessable or disallowed and is calculated using tax rates that have been enacted or substantively enacted by the reporting date.

Tax is charged or credited to the statement of comprehensive income, except when the tax relates to items credited or charged directly to equity, in which case the tax is also dealt with in equity.

Deferred tax

Deferred tax assets and liabilities are recognised where the carrying amount of an asset or liability in the statement of financial position differs to its tax base, except for differences arising on:

1.     The initial recognition of an asset or liability in a transaction which is not a business combination and at the time of the transaction affects neither accounting or taxable profit; and
2.     Investments in subsidiaries and jointly controlled entities where the Group is able to control the timing of the reversal of the difference and it is probable that the differences will not reverse in the foreseeable future. Recognition of deferred tax assets is restricted to those instances where it is probable that taxable profit will be available against which the difference can be utilised.

The amount of the asset or liability is determined using tax rates that have been enacted or substantively enacted by the reporting date and are expected to apply when deferred tax liabilities/ (assets) are settled/ (recovered). Deferred tax balances are not discounted.

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 (refer to note 16 for details of restricted cash).

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.

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

Finance costs

Borrowing costs are recognised as an expense when incurred.

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 borrowing is accrued as applicable to that class of borrowing.

Financial risk management

The Board continually assesses and monitors the key risks of the business. The key risks that could affect the Group’s medium-term performance and the factors that mitigate those risks have not substantially changed from those set out in the Group’s 2025 Annual Report and Financial Statements, a copy of which is available from the Group’s website: www.predatoroilandgas.com. The key financial risks are market risk (including cash flow interest rate risk and foreign currency risk), credit risk and liquidity.

1   Revenue

The Group’s revenue was derived from crude oil to the state oil company in the Trinidad and Tobago, Heritage Petroleum Company Limited. All sales are made from the

Group’s own production. The Group does not engage in oil trading, nor does not buy or sell oil forwards, derivatives, or any other form of non-physical contract.

Total Revenue	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
Revenue from Oil sales	1,522,877	66,815
	1,522,877	66,815

2   Segmental analysis

The Group operates in the business segments: the exploration, appraisal and development of oil and gas assets and the related oil and gas production. The Group has interests in three geographical segments being Europe (Ireland), the Caribbean (Trinidad and Tobago) and Africa (Morocco).

The Group’s operations are reviewed by the Board (which is considered to be the Chief Operating Decision Maker (‘CODM’)) and split between oil and gas exploration and development and administration and corporate costs.

Operating segments are disclosed below on the basis of the split between exploration and development and administration and corporate.

Europe Caribbean			Africa	Corporate
For the 6 months to 30 June 2026 (unaudited)	£	£	£	£
Income	-	1,522,877	-	-
Cost of Sales	-	(1,239,836)	-	-
Gross profit	-	283,041	-	-
Other operating income	-	3,698	-	-
Administrative and overhead expenses	(53,776)	(607,676)	(74,604)	(429,135)
Share option and warrant expense	-	-	-	(54,701)
Finance costs	-	(43,787)	-	-
Finance Income	-	1,941	-	13,685
Taxation	-	-	(935)	-
(Loss) for the period from continuing operations	(53,776)	(362,783)	(75,539)	(470,151)
Total reportable segment intangible assets	-	7,232,046	20,039,166	-
Total reportable segment tangible assets	-	2,720,626	-	-
Total reportable segment non-current assets	-	1,340,625	1,133,974	-
Total reportable segment current assets	1,473	2,210,303	179,757	5,786,037
Total reportable segment assets	1,473	13,503,600	21,352,897	5,786,037
Total reportable segment liabilities	20,635	10,223,432	64,640	425,151

Notes to the condensed financial statements - continued for the six months to 30 June 2026
	Europe	Caribbean	Africa	Corporate
For the 6months to 30 June 2025 (unaudited)	£	£	£	£
Income Cost of Sales	-	66,815 -	-	-
Gross profit	-	66,815	-	-
Other operating income	-	-	-	-
Administrative and overhead expenses	(39,787)	251,037	724,292	(1,504,268)
Share option and warrant expense	-	-	-	(1,176,935)
Finance costs	-	-	-	-
Finance Income	-	6	-	28,571
Taxation	-	-	(476)	-
Profit/(loss) for the period from continuing operations	(39,787)	317,858	723,816	(2,652,632)
Total reportable segment intangible assets	-	5,924,688	18,748,676	-
Total reportable segment tangible assets	-	7,201	-	169
Total reportable segment non-current assets	-	-	-	1,093,425
Total reportable segment current assets	-	196,195	1,245,832	1,397,376
Total reportable segment assets	-	6,128,084	19,994,508	2,490,970
Total reportable segment liabilities	(10,000)	(3,409,311)	(873,548)	(381,192)

There are no non-current assets held in the Group’s country of domicile, being Jersey, Channel Islands (2025: £nil).

3 Cost of Sales	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
Cost of sales - production costs	11,889	-
Depreciation Expense	159,791	-
Diesel	1,737	-
Electricity	7,171	-
Financial Obligation	21,829	-
Health & safety	412	-
Inventory Adjustments	(2,179)	-
Rental Equipment	2,251	-
Repairs and maintenance	1,867	-
Royalties	110,539	-
Staff costs	11,457	-
Transportation	11,437	-
COS-Sub Operator Share of Revenue	901,635	-
	1,239,836	-

4 Auditors remuneration	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
Audit of the accounts of the Group	60,470	40,199
Review of interim financial statements	1,500	3,000
	64,970	43,199

Notes to the condensed financial statements - continued for the six months to 30 June 2026

5 Finance income	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
Deposit account interest	15,626	28,578
	15,626	28,578
	30/06/2026	30/06/2025
	(unaudited)	(unaudited)
6 Administrative expenses	£	£
Accretion expense - Abandonment	78,188	-
Accounting fees	17,707	-
Administration fees	71,116	80,715
Advisory fees	31,703	10,000
Annual Registration Fees	5,695	7,685
Audit fees	64,970	43,199
Bank charges	30,172	33,089
Bonus & incentive payments	-	(183,813)
Broker fees	76,686	-
Computer costs	-	19,644
Consultants Fees	145,223	129,639
Cory Moruga operating fees	-	48,341
D&O insurance	(13,957)	-
Depreciation	108,406	318
Director fees	188,133	93,966
Foreign exchange	(131,460)	341,563
Foreign Tax	935	-
Insurance	8,781	7,959
Legal & professional fees	11,769	43,710
Listing costs	98,291	69,921
Office costs	22,775	13,143
Oil Impost	4,733	-
Operating foreign exchange gains/losses	(5,301)	-
Other taxes	108,388	-
Penalties, interest & Trinidad debts	100,228	-
Personnel Costs	58,065	-
Rental	25,798	-
Repairs and Maintenance	148	-
Sundry Expenses	11,761	5,297
Training	11,867	-
Travel expenses	35,306	56,225
WHT payable	-	676
	1,166,126	821,277

30/06/2026 (unaudited) £ 7 Performance and compensation bonus	30/06/2025 (unaudited) £
Deferred performance bonus -	(183,813)
-	(183,813)
30/06/2026	30/06/2025
(unaudited)	(unaudited)
8 Finance expense £	£
Decommissioning costs 43,787	-
43,787	-

The above costs relate to charges for decommissioning expenses for a Trinidad subsidiary.

9	Income tax	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
	Loss on ordinary activities before tax in Trinidad & Tobago	(803,969)	(1,650,745)
	Loss on ordinary activities at Jersey standard 0% tax	-	-
	Tax loss for the year	(803,969)	(1,650,745)

No charge to taxation arises due to the losses incurred in all jurisdictions and or in the case of Jersey a 0% rate of tax applies.

Predator Gas Ventures Limited is subject to tax in its operating jurisdiction of Morocco; however, the Company is loss making and has no taxable profits to date. There is a 10 year corporation tax holiday in Morocco commencing on the date of award of an Exploitation Concession.

TRex is subject to tax in its operating jurisdiction of Trinidad and Tobago the six month period to June 2026 the Company incurred costs of £1,844,161 (TTD 16,528,219) which are available to be carried forward against future taxable profits.

No deferred tax asset has been recognised on accumulated tax losses because of uncertainty over the timing of future taxable profits against which the losses may be offset.

No deferred tax asset or liability has been recognised as the Standard Jersey corporate tax rate is 0%.

Tax losses of £36.2m for the Group’s Trinidad and Tobago companies include losses confirmed (£36.0m) with the BIR up to and including 2024 and also estimates of (GBP0.2m) for 2025 based on computations.

10 Directors fees and share based compensation	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
Executive and non-executive directors	313,669	257,351
Share based payments - options	54,701	1,176,935
	368,370	1,434,286

11    Earningsper share

30/06/2026

(unaudited)

30/06/2025

(unaudited)

Weighted average number of shares	807,640,399	655,169,210
Loss attributable to ordinary equity holders of the company	(813,969)	(1,634,890)
Total basic and diluted loss per share attributable to the ordinary equity holders (pence)	(0.101)	(0.250)

Basic earnings per share is calculated by dividing the earnings attributable to ordinary shareholders by the weighted average number of ordinary shares outstanding during the period.

Diluted earnings per share is calculated using the weighted average number of shares adjusted to assume the conversion of all dilutive potential ordinary shares.

The effect of potential dilutive ordinary shares has not been shown, as the Group incurred a loss for the year and the inclusion of such shares would be anti-dilutive. Accordingly, diluted earnings per share has not been disclosed.

12   Loss for the financial year

The Group has adopted the exemption in terms of Companies (Jersey) law 1991 and has not presented its own separate individual income statement in these financial statements for the Parent Company.

13	Intangible asset	Project Guercif £	Cory Moruga £	Other Trinidad £	Total £
	Balance at 1 January 2026	19,396,118	5,197,428	1,595,154	26,188,700
	Additions	643,048	416,069	-	1,059,117
	Foreign exchange differences on		13,280	25,597	38,877
	translation
	At 30 June 2026	20,039,166	5,626,777	1,620,751	27,286,694
	Depletion
	Balance at 1 January 2026	-	-	(6,036)	(6,036)
	Charge in the year	-	-	(9,446)	(9,446)
	At 30 June 2026	-	-	(15,482)	(15,482)
	Carrying amount 30	20,039,166	5,626,777	1,605,269	27,271,212
	June 2026
	Carrying amount 31	19,396,118	5,197,428	1,589,118	26,182,664
	December 2025

Trinidad – Cory Moruga Licence

The Cory Moruga Exploration and Production Licence includes the Snowcap oil discovery where oil was previously produced on test from Snowcap-1 and oil was encountered in Snowcap-2 but inconclusively tested due to operational issues impacting a previous operator. The consideration comprised an immediate payment of $1m to Challenger Energy Group PLC (CEG) and $1m payment directly to the MEEI as well as resolution of various liabilities between T-Rex Resources (Trinidad) limited (Trex) and Predator and between TRex and MEEI.

The current capitalised value of the Cory Moruga licenceis £5,626,777 (31 December 2025: £5,197,428).

An appraisal well, Snowcap-3, is scheduled for the second half of 2026. Civil and drilling contracts have been issued.

The results of an Independent Technical Report ("ITR") by Scorpion Geosciences Ltd, dated 20 February 2026, for the Cory Moruga licence with project economics, supports a valuation of NPV @10% of £67m. The aforesaid appraisal well is intended to prove up the P90 resources case with an NPV @10% discount of £67 Million or 12 pence per share based on £159m undiscounted post-tax profits for the Base Case of approximately 8.33MMbbl recoverable using a 15-year production profile peaking at 3,500bopd which equates to c. 58.2% of available 2C + P50 (Unrisked) Prospective Resources .

In the ITR significant upside potential is now recognised with respect to deeper Cretaceous sand fairways which may be present within the Company’s acreage. Ongoing work seeks to confirm whether this observation is part of the World Class discovery trend currently being worked by likes of ExxonMobil along the coast of Guyana, Venezuela and Trinidad.

Cory Moruga Licence - Summary

The Company has considered the possible indicators of potential impairment under IFRS6, and none of these applies to the Company’s interest in the recently acquired Cory Moruga licence as at 30 June 2026, or currently.

Specifically –

• The licence is current and not due to expire - The Initial Work Program has been agreed with the MEEI for a period of three years to November 2026. An extension beyond this date is pending approval.
• The Company has outlined a Field Development Plan to the MEEI which includes up to 20 development wells as well as a longer-term CO2 EOR scheme. This will not be considered for implementation until after the Snowcap-3 appraisal well results in 2026.
• The current carrying value is well supported by the Scorpion Geoscience Independent Technical Report ("ITR").

Accordingly, the Directors believe that there are no indicators of impairment of the Company's Cory Moruga assets at the current time, and no impairment adjustment is appropriate.

Other Trinidad

The 29th August 2025 acquisitions that were concluded in Trinidad included the Goudron and Inniss-Trinity Enhanced Production Sharing Contracts with Heritage and the Icacos Exploration and Production Licence with MEEI. These acquisitions gave rise to intangible assets totalling £1,620,751 (31 December 2025: £1,591,745). This is shown in the above table under ‘Other Trinidad’.

This valuation was determined based an innovative Master Services Agreement with NABI Construction for a ‘cost-free to Predator’ production ramp-up and revenue generation.

NABI is an exceptionally cost-efficient local operator which has transformed the economics for rehabilitating mature oil fields.

Water flooding is projected to commence by end of 2026 which is expected to increase existing production in the Goudron Field. Further, the Company is engaged in negotiations with a third party for evaluation of an opportunity to exploit stranded gas in the Field.

Project Guercif

The total carrying amount of Project Guercif at 30 June 2026 of £20,039,166 (31 December 2025: £19,396,118) relates to costs incurred with wells MOU-1, MOU-2, MOU-3, MOU-4, MOU-5 and MOU-6.

Impairment Review Guercif

Predator Oil & Gas Plc ("The Company") accounts for its exploration and evaluation assets based on IFRS 6 (Exploration for an d Evaluation of Mineral Resources). The Company's policy is to follow the successful efforts method. Exploration and appraisal activities are initially capitalised as intangible assets, pending determination of the existence of commercial reserves in the licence area. Such costs are classified as intangible assets based on the nature of the underlying asset, which does not yet have any proven physical substance. Exploration and appraisal costs are held, un-depreciated, until such a time as the exploration phase on the licence area is complete or commercial reserves have been discovered.

If no commercial reserves exist, then that particular exploration/appraisal effort was "unsuccessful" and the costs are written off to the income statement in the period in which the evaluation is made. The success or failure of each exploration/appraisal effort is judged on a field-by-field basis.

Morocco - Guercif Licence

Predator has a 75% interest in the Guercif Licence together with its partner ONHYM, the State oil company. The capitalised value at 30 June 2026 of the Guercif licence costs is £20,039,166 (31 December 2025: £19,397,727).

Exploration and Appraisal activity on Guercif

The current focus of activity is the evaluation of a number of potential gas and helium reservoirs based on NuTech petrophysical interpretation from 339 to 1425 metres measured depth in MOU-1, MOU-3 and MOU-4 and gas and helium samples collected in MOU-3. The rigless testing programme completed in Q3 2025 established for the first time the extent of reservoir formation damage caused by over-balanced drilling with excessive mud weights. A re-engineered appraisal/development well (MOU-6) is being programmed for 2026. An application to extend the First Extension Period of the Guercif Petroleum Agreement to 5 November 2026 has been submitted to ONHYM and the Ministry. This will enable a potential application for an Exploitation Concession to be submitted by 5 October 2026 for a pilot CNG development. As a consequence of these positive actions, the Group has been able to commence negotiations with a potential joint venture partner willing to finance the MOU-6 drilling and the CNG pilot development. In addition, under the terms of the agreement being negotiated, up to USD24.6m in past costs will be refunded, subject to contract. These include the costs of MOU-1, MOU-3 and MOU-4 and additionally MOU-2 (which penetrated a much thicker section of the interval where helium was sampled in MOU-3) and MOU-5 (which discovered salt and which the potential joint venture partner wishes to consider as an area for potential gas storage in salt caverns).

The MOU-1 well drilled in 2021 was completed for rigless well testing on the basis of the presence of formation gas and petrophysical wireline log interpretation by NuTech indicating gas in the primary and secondary pre-drill reservoir targets.

The well remains a potential gas producer. MOU-6, when drilled, will potentially provide the information to engineer a small-scale frac job to reach beyond the zone of reservoir formation damage.

The MOU-2 well was drilled in January 2023. The Company announced on 25 January 2023 that the MOU-2 well had been suspended at 1,260 metres measured depth above the primary pre-drill reservoir target. Subsequent re-interpretation of the wireline log whilst drilling and correlation with the later MOU-4 well log confirmed that the primary target was penetrated and contained a thick sand sequence equivalent of the Moulouya Fan interval that sampled helium and biogenic gas in MOU-3.

A re-entry of MOU-2 to sidetrack to the deeper target can be considered if the re-engineered MOU-6 well is drilled without encountering previous drilling issues.

3 gas samples were collected whilst drilling MOU-2 in the shallow section above 700 metres which is likely an extension of the formation gas shows encountered in MOU-3 at shallower depths down to 950 metres and including the “A” Sand, Ma Sand and TGB-6 Sand.

The MOU-3 well was drilled in June 2023 to a depth of 1,509 metres (TVD MD) and encountered gas shows in multiple zones including the primary targets, the Moulouya Fan sands and the Ma and TGB-6 sands, and a new shallow “A” Sand reservoir interval.

The well was completed for rigless testing.

The well remains a potential gas producer. MOU-6, when drilled, will potentially provide the information to engineer a small-scale frac job to reach beyond the zone of reservoir formation damage.

The MOU-4 well was drilled in July 2023 and confirmed the extension of the Moulouya Fan further to the southeast than previously prognosed. Better reservoir quality was interpreted as a result of the NuTech petrophysical analysis of the wireline logs. NuTech also indicated good gas saturations beyond the zone of suspected reservoir formation damage.

The well remains a potential gas producer. MOU-6, when drilled, will potentially provide the information to engineer a small-scale frac job to reach beyond the zone of reservoir formation damage.

The MOU-5 well was drilled in February 2025 and suspended for a possible re-entry. The primary target, a Jurassic carbonate bank, was encountered deeper than prognosed due to the presence of allochthonous salt.

MOU-5 remains a candidate for re-entry and side-tracking updip to the Jurassic carbonate objective and deepening to an underlying potential TAGI Triassic reservoir with a thick salt seal. The thickness of the potential salt will determine whether or not the interval can be considered a candidate for gas storage.

Guercif Permit – Summary

The Company has considered the possible indicators of potential impairment under IFRS6, and none of these applies to the Company’s interest in the Guercif licence as at 31 December 2025, or currently, specifically –

• The Guercif licence has not expired. The permit was granted in 2019 and is valid until 2028, after a one-year force majeure extension due to COVID. An application has been made to extend the First Extension Period from 5 March 2026 to 5 November 2026. This would facilitate the drilling of the MOU-6 appraisal/development well and a subsequent application for an Exploitation Concession.

Property, plant & De-commissioning

14	Tangible fixed assets	Oil& gas assets	equipment	costs	Total
	Cost
	Balance at 1 January 2026	1,896,342	716,007	537,259	3,149,608
	Additions	-	59,039	-	59,039

Foreign exchange difference on translation	-	-	-	-
At 30 June 2026	1,896,342	775,046	537,259	3,208,647
Amortisation
Balance at 1 January 2026	(98,082)	(92,192)	(39,314)	(229,588)
Charge for the year	(152,744)	(76,761)	(28,928)	(258,433)
At 30 June 2026	(250,826)	(168,953)	(68,242)	(488,021)
Carrying amount	1,645,516	606,093	469,017	2,720,626
At 30 June 2026
Carrying amount	1,798,260	623,815	497,945	2,920,020
At 31 December 2025

15 Inventories	30/06/2026 (unaudited) £	31/12/2025 (audited) £
Crude Oil	56,182	53,058
Consumables	72,588	71,318
	128,770	124,376

30/06/2026 31/12/2025

(unaudited) (audited)

16.   Trade and other receivables £ £

Non Current
Security deposit (US$1,500,000) (i)	1,133,974	1,115,039
Escrow and abandonment funds (ii)	1,340,625	1,291,963
Current Prepayments and other receivables (iii)	1,400,608	1,540,317
	3,875,207	3,947,319

1.                     A security deposit of USD1,500,000 (2025: USD1,500,000) is held by Barclays Bank in respect of a guarantee provided to Office National des Hydrocarbures et des Mines (ONHYM) as a condition of being granted the Guercif exploration licence. These funds are refundable on the completion of the Minimum Work Programme set out in the terms of the Guercif Petroleum Agreement and Association Contract. Following ratification by a Joint Ministerial Order, the Bank Guarantee has been rolled over into the First Extension Period of the Guercif Licence.
2.                    Non-current prepayments are abandonment funds held for Trinidad and Tobago subsidiaries. Pursuant to certain production and exploration licences payments are remitted into an Escrow Fund and a separate Abandonment Fund. Payments are based on production, and amounts paid vary by licence: US$0.25 per barrel of crude oil sold (Escrow Fund), and between US$0.28 to US$1.00 varying by licence to the Abandonment Fund (with those funds to be used for the future abandonment of wells in the related licenced area).

3.                   Prepayments and other debtors include:
   1. £869,174 (31/12/2025: £841,000) for VAT receivable which is offsettable against VAT payable
   2. Restricted cash: £346,440 (31/12/2025: £311,908) in deposits held as collateral for performance bonds in respect of Inniss Trinity and Goudron licences and an environmental bond in respect of Bonasse licences.

There are no material differences between the fair value of trade and other receivables and their carrying value at the year end.

17.        Cash and cash equivalents

30/06/2026

(unaudited)

£

31/12/2025

(audited)

£

Barclays Bank Plc	5,765,014	878,087
Scotia Bank	9,546	18,237
Republic Bank	726,680	292,484
Société Générale	20,486	70,273
Bosil Bank	6,391	-
32 Day Notice Deposit	-	250,000
Bank of St Lucia	-	7,154
Unit Trust Corporation	117,552	-
RBC Royal Bank	2,430	2,407
Petty Cash	93	232
	6,648,192	1,518,874

18	Share capital		Number of shares	Nominalvalue
	Issued and fully paid
	Opening Balance	01/01/2026	686,316,395	38,707,584
	Share issue	30/01/2026	73,235,862	2,563,256
	Share issue	30/01/2026	142,857	5,000
	Share issue	04/02/2026	55,192,700	1,931,746
	Share issue	26/05/2026	42,857,143	1,500,000
	Share issue	02/06/2026	42,857,143	1,500,000
			900,602,100	46,207,586

1.         On 20 January 2026 the Company announced that it had conditionally placed 128,571,419 million new ordinary shares of no par value in the Company (the Placing Shares) at a placing price of 3.5 pence each (the Placing Price) to raise £4.5m (before expenses) (the Placing). To fund drilling and testing Snowcap-3 ( SC-3 ) appraisal and development well andto progress joint venture partnering for the Guercif gas asset to agree principles for funding the drilling and testing of the MOU-6 well.
2.         On 15 May 2026 the Company announced that it has conditionally placed 85,714,286 million new ordinary shares of no par value in the Company (the "Placing Shares") at a placing price of 3.5 pence each (the "Placing Price") to raise £3m (before expenses).
   1.      To deepen the proposed Snowcap-3 ("SC-3") well by 150 feet and add an additional testing programme for the Herrera #8 Sand, based on a revised reservoir correlation between Snowcap-1 and Rochard-1.2 . and reactive the Snowcap-2ST1 and Jacobin-1 wells and acquire information for a gas re-injection reservoir engineering study for Snowcap-1 and Snowcap-2ST1 to assess the potential to maintain higher production rates for longer.
   2.      To purchase Guercif MOU-6 long-lead well inventory to maintain the current drilling schedule given the impact on logistics of the Middle East conflict.

19 Trade and other payables	30/06/2026 (unaudited) £	31/12/2025 (audited) £
Current Trade payables	2,959,263	4,592,604
Accruals	4,856,100	3,200,935
Provisions	-	-
	7,815,363	7,793,539

Included in trade and other payables (including accruals) is £7.3million which relates to Trinidad & Tobago. Of these payables:

1.         approximately £2.2 million in aggregate are considered to be of a routine working capital nature, and that are either being settled in the ordinary course of business and / or under certain agreed payment plans or are in legal dispute;
2.         £2.7 million is payable to the Trinidadian Ministry of Energy and Energy Industries in respect of past dues on the Cory Moruga licence; These are repayable through an increased Ministry royalty on Snowcap-3 and Cory Moruga production - 7.5% up to 250 bopd and 12.5% > 250 bopd until the debt is recovered
3.         £2.4 million is due to BIR (Bureau for Inland Revenue), the Trinidad tax authority, for tax payable by Steeldrum Goudron Limited.

The Group does not expect to be required to settle the bulk of the aforesaid Trinidad & Tobago dues during the course of 2026. The Group expects to settle, over time, taxes liabilities by way of a partial offset against £869,174 in tax refunds due to the Group in Trinidad and Tobago, included under ‘Trade and other receivables’.

Non-Trinidad & Tobago payables includes an amount due to Paul Griffiths in respect of compensation for the capitalisation of the loans in the sum of £323,785. He will receive cash payments for 60% of the aforesaid sum from the company upon either a) a flow rate of 3 million cfg/day being achieved from any well of Guercif petroleum or b) a flow rate of 200 bopd being achieved from any well in Trinidad.

		30/06/2026 (unaudited)	31/12/2025 (audited)
20	Non-current liabilities	£	£
	Decommissioning provisions At 1 January	2,786,380	174,097
	Additions	-	2,220,057
	Unwinding of discount	-	140,036
	Accretion expense	78,188	-
	Revision to estimate	51,618	250,148
	Foreignexchange difference on translation	2,309	2,042
	At period end	2,918,495	2,786,380

The provisions relate to the estimated costs of the removal of Trinidadian production facilities and site restoration at the end of the production lives of certain facilities in each location.

Decommissioning provisions in Trinidad and Tobago have been subject to a discount rate of 5.27%-7%, expected cost inflation of 2.0% and assumes an average expected year of cessation of production of between 2032 and 2039.

21	Other reserves
			30/06/2026	31/12/2025
	Warrants issuance cost reserve		(unaudited)	(audited)
		No of warrants	£	£
	Balance brought forward	75,748,976	(1,374,040)	(1,374,041)
	Issue of warrants	15,000,000	-	-
	Exercised warrants at fair value	-	-	-
	Cancelled and/or expired warrants	(5,030,795)	465,858	-
	Balance carried forward	85,718,181	(908,182)	(1,374,041)
	Share based payments reserve		30/06/2026	31/12/2025
		No of share options	(unaudited)	(audited)
			£	£
	Balance brought forward	79,355,486	4,168,645	2,473,910
	Fair value of share options	-	-	1,694,735
	Share based payment charge for the year		121,777	-
	Cancelled options	(3,000,000)	(67,076)	-
	Cancelled and/or expired warrants	-	(465,858)	-
	Balance carried forward	76,355,486	3,757,488	4,168,645
			30/06/2026	31/12/2025
	Reconstruction reserve		(unaudited)	(audited)
			£	£
	Balance brought forward		283,734	403,734
	Brokers' commission on share issues		(701,025)	(120,000)
	Balance carried forward	-	(417,291)	283,734

Pursuant to two share placings, in January 2026 and May 2026, raising a total £7.5mil before costs, the associated broker’s commissions amounting to

£701,025 (2025: £120,000) were posted to the Reconstruction reserve in terms of IAS 32.

22         Non-controlling interest

On 1 January 2025 a Group subsidiary, TRex Resources Trinidad Limited acquired at an acquisition cost of USD1, 51% of the equity of Caribbean Rex Limited, later renamed to Steeldrum Ventures Group Limited, (‘SVG’) and its 100% owned subsidiary, CEG Bonasse Limited, later renamed to Steeldrum Cedros Limited. The remaining 49% of SVG’s equity is held by the West Indian Energy Group Limited.

On 1 September 2025 SVG, announced the purchase of the entire share capital of Challenger Energy Group Plc's St. Lucia-domiciled subsidiary company, Columbus Energy (St. Lucia) Limited and its subsidiaries' business and operations in Trinidad and Tobago and St Lucia at an acquisition cost of USD750,000.

For the reporting period SVG and its subsidiaries incurred a consolidated loss of £302,612.

The share of the aforesaid loss attributable to the non-controlling interest was £148,280 or 49% of the consolidated loss. The £148,280 has been shown under Non-

Controlling Interest in the Group’s balance sheet and statement of consolidated profit and loss.

23         Share based payments Share Options

The Group operates a share option plan for directors. Details of share options granted and exercised during the year below

	30/06/2026 (unaudited)		31/12/2025 (audited)
	Averageexercise	No. Options	Averageexercise	No. Options
At beginning of period	0.07	79,355,486	0.10	34,355,486
Expired	0.10	(3,000,000)	-	-
Cancelled	-	-	-	-
Granted	-	-	0.06	45,000,000
Exercised	-	-	-	-
At end of period	0.07	76,355,486	0.07	79,355,486

There have been no share options granted in the six months to 30 June 2026. The fair value of the options and warrants granted in the prior year financial statements was estimated using the Black Scholes model. The inputs and assumptions used in calculating the fair value of options granted in the year were as follows:

Share price:	£0.0445
Exercise price:	£0.0550
Term:	7 years
Expected volatility:	185.71%
Expected dividend yield:	0%
Risk free rate:	4.02%

The weighted average remaining contractual life of the options in issue at 30 June 2026 was 4.93 years (2025: 5.43 years) and the weighted average exercise price of these instruments was 7.35 pence per share (2025: 7.45 pence). The range of exercise prices for options outstanding at 30 June 2026 was 5.5 pence to 12.5 pence (2025: 5.5 pence to 12.5 pence).

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

Total expense arising from equity-settled share based transactions:

	30/06/2026 (unaudited) £	31/12/2025 (audited) £
Fair value of share options	-	1,694,735
Amount released Cancelled options	121,777 (67,076)	- -
	54,701	1,694,735

Warrants

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.

Party	Issue date	Expiry date	Number of warrants	Exercise Price
Novum Securities Ltd	01/08/2023	01/08/2026	2,863,636	0.11
Fox Davies Capital Ltd	01/08/2023	01/08/2028	5,454,545	0.11
Institutional Investor	04/11/2024	04/11/2027	40,000,000	0.08
Novum Securities Ltd	04/11/2024	04/11/2029	2,400,000	0.05
Novum Securities Ltd	19/12/2024	19/12/2029	10,000,000	0.06
Eva Pacific Pty Ltd	04/02/2025	04/02/2028	5,000,000	0.06
Cynosure Capital Pty Ltd	04/02/2025	04/02/2028	5,000,000	0.06
GHC Capital Market	23/01/2026	23/01/2029	9,000,000	0.04
Novum Securities Ltd	20/05/2026	20/05/2029	3,000,000	0.04
GHC Capital Market	20/05/2026	20/05/2029	3,000,000	0.04
			85,718,181	0.07 (weighted average)

24  Restructuring of Trinidad corporate structure

In January 2026 the grouping of the Trinidad and St Lucia companies were re-structured as follows:

1.        Steeldrum Icacos Trinidad limited (formerly CEG Icacos Trinidad Limited) was sold by CEG Energy St Lucia Limited to Steeldrum Petroleum Group Limited; and

2.        Steeldrum Cedros Trinidad Limited (formerly CEG Bonasse Trinidad Limited) was sold by Steeldrum Ventures Group Limited (formerly Caribbean Rex Limited) to Steeldrum Petroleum Group Limited; and

3.        Steeldrum Inniss-Trinity Trinidad Limited (formerly CEG Inniss-Trinity Trinidad Limited) was sold by Steeldrum Oil Company Limited to Columbus Energy St Lucia Limited

On a consolidated basis the restructuring did not impact the Group’s financial statements.

25      Investments

The principal subsidiaries of Predator Oil and Gas Holdings Plc, all of which are included in these consolidated Annual Financial Statements, are as follows:

Country of registration

Proportion held by Group

Nature of business

Direct

Predator Oil and Gas Ventures Limited Jersey 100% Licence options

Predator Gas Ventures Limited Jersey 100% Exploration licence

Mag Mell Energy Ireland Limited Jersey 100% FSRU Project

Predator Oil & Gas Trinidad Limited Jersey 100% Holding company The registered address of all of the Group’s companies is at 3rd Floor, One The Esplanade, St Helier, Jersey, JE2 3QA.

Indirect

T-Rex Resources (Trinidad) Limited Trinidad and Tobago 100% Exploration and Production Licence

Steeldrum Ventures Group Limited	St. Lucia	51%	Holding Company
Columbus Energy (St Lucia) Limited	St. Lucia	51%	Holding Company
Steeldrum Oil Company Inc.	St. Lucia	51%	Holding Company
Steeldrum Goudron Trinidad Limited	Trinidad and Tobago	51%	Exploration and Production Licence
Steeldrum Icacos Trinidad Limited	Trinidad and Tobago	51%	Exploration and Production Licence
Steeldrum Inniss-Trinity Trinidad Limited	Trinidad and Tobago	51%	Exploration and Production Licence
Steeldrum Cedros Trinidad Limited	Trinidad and Tobago	51%	Exploration and Production Licence
Steeldrum Well Services Trinidad Limited	Trinidad and Tobago	51%	Oil and Gas Services
Steeldrum Management Services Trinidad Limited	Trinidad and Tobago	51%	Management Services
Steeldrum Petroleum Group Limited	Trinidad and Tobago	51%	Holding Company

26         Financial instruments

Details of the significant accounting policies in respect of financial instruments are disclosed on pages 10 to 11. The Group's financial instruments comprise cash and items arising directly from its operations such as other receivables, trade payables and loans.

Financial risk management

The Board seeks to minimise its exposure to financial risk by reviewing and agreeing policies for managing each financial risk and monitoring them on a regular basis. No formal policies have been put in place in order to hedge the Group's activities to the exposure to currency risk or interest risk; however, the Board will consider this periodically.

The Group is exposed through its operations to the following financial risks:

o                       Credit risk

o                       Market risk (includes cash flow interest rate risk and foreign currency risk)

o                       Liquidity risk

The policy for each of the above risks is described in more detail below.

The principal financial instruments used by the Group, from which financial instruments risk arises are as follows:

o                       Receivables

o                       Cash and cash equivalents

o                       Trade and other payables (excluding other taxes and social security)

The table below sets out the carrying value of all financial instruments by category and where applicable shows the valuation level used to determine the fair value at each reporting date. The fair value of all financial assets and financial liabilities is not materially different to the book value.

Categorisation of financial instruments	30/06/2026 (unaudited) £	31/12/2025 (audited) £
Cash and trade receivables (at amortised cost)
Tradeandother receivables	3,875,207	3,947,317
Financial assets that are debt instruments measured at amortised cost:
Cash and cash equivalents	6,648,192	1,518,874
	10,523,399	5,466,191
Financial liabilities measured at amortised cost:
Trade and other payables (excluding short term loans)	(7,815,363)	(7,793,539)
	(7,815,363)	(7,793,539)

Credit risk

Financial assets, which potentially subject the Group to concentrations of credit risk, consist principally of cash, short-term deposits and other receivables. Cash balances are all held at recognised financial institutions. Other receivables are presented net of allowances for doubtful receivables. Other receivables currently form an insignificant part of the Group's business and therefore the credit risks associated with them are also insignificant to the Group as a whole.

Maximum exposure to credit risk

The Group's maximum exposure to credit risk by category of financial instrument is shown in the table below:

	30/06/2026	30/06/2026 Maximum	31/12/2025	31/12/2025 Maximum
	Carrying value	exposure	Carrying value	exposure
Cash and cash equivalents	6,648,192	7,277,283	1,518,874	5,515,473
Receivables	3,875,207	3,875,207	3,947,317	3,947,317

The holding company's maximum exposure to credit risk by class of financial instrument is shown in the table below:

	30/06/2026 Carrying value	30/06/2026 Maximum exposure	31/12/2025 Carrying value	31/12/2025 Maximum exposure
Cash and cash equivalents	5,759,994	6,129,760	1,100,769	5,018,546
Receivables	26,042	26,042	50,267	50,267

Market risk

Cash flow interest rate risk

The Group has adopted a non-speculative policy on managing interest rate risk. Only approved financial institutions with sound capital bases are used to borrow funds and for the investments of surplus funds. The Group seeks to obtain a favourable interest rate on its cash balances through the use of bank deposits. The Group's bank paid a total of £15,626 (year-ended 31 December 2025: £52,348) interest on cash balances during the period. At 30 June 2026, the Group had a cash balance of £6.648m (year-ended 31 December 2025: £1.519m) which was made up as follows:

	30/06/2026 £	31/12/2025 £
Sterling	4,181,378	1,050,929
United States Dollar	2,183,604	378,689
Euro	3,589	1,495
Moroccan Dirham	20,486	70,272
Trinidad& Tobago Dollar	259,135	17,489
	6,648,192	1,518,874

Foreign currency risk

Foreign exchange risk is inherent in the Group's activities and is accepted as such. The majority of the Group's expenses are denominated in Sterling and therefore foreign currency exchange risk arises where any balance is held, or costs incurred, in currencies other than Sterling. At 30 June 2026 and 31 December 2025, the currency exposure of the Group was as follows:

	Sterling £	US Dollar £	Other £	Total £
At 30 June 2026
Trade and other receivables	189,045	-	2,898,079	3,087,124
Cash and cash equivalents	4,181,378	2,183,604	283,210	6,648,192
Trade and other payables	332,096	4,686,097	5,715,665	10,733,858
At 31 December 2025
Trade and other receivables	58,114	-	2,774,165	2,832,279
Cash and cash equivalents	1,050,929	378,689	89,256	1,518,874
Trade and other payables	900,314	4,230,994	5,448,611	10,579,919

Liquidity risk

Any borrowing facilities are negotiated with approved financial institutions at acceptable interest rates. All assets and liabilities are at fixed and floating interest rate. The Group seeks to manage its financial risk to ensure that sufficient liquidity is available to meet the foreseeable needs both in the short and long term.

Capital

The objective of the directors is to maximise shareholder returns and minimise risks by keeping a reasonable balance between debt and equity. At 30 June 2026 all the Group's debt balances which related to Directors was fully repaid.

27         Related party transactions Transactions with key managementpersonnel

Key management of the Group are the executive members of the Company board of directors. Key management personnel remuneration includes the following expenses:

	30/06/2026 (unaudited) £	30/06/2025 (unaudited) £
Executive and non-executive directors	(313,669)	(257,351)
Share option scheme	(54,701)	(1,176,935)
	(368,370)	(1,434,286)
The average number of personnel (including directors) during the period was:
Management - (Executive directors)	1	1
Non-management - (Non-executive directors)	3	3
	4	4

Four Directors at the end of the period have share options receivable under long-term incentive schemes. The highest paid Director received an amount of

£177,106 (30/06/2025: £156,768) from executive directors and technical consultancy fees. The Company does not have employees. All personnel are engaged as service providers by the Group’s holding company Gelco, an entity controlled by, Mr Geofrey Leid, a related party, was paid a consultancy fee of £27,925 (30/06/2025: £61,939) in the period for the services of Mr Geofrey Leid to the Group’s Trinidad based companies.

On the 20 February 2025, share options were issued to the following directors.

No. of Shares

Paul Griffiths	18,500,000
Carl Kindinger	7,500,000
Alistar Jury	7,500,000
Stephen Boldy	7,500,000
Total number of directors shares issued in year	41,000,000

28         Subsequent events

1. 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.
2. 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.
3. 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.
4. 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.
5. On 19 September the Company announced that drilling operations had commenced on the MOU-6 well in Morocco.'

29         Ultimate controlling party

In the opinion of the Directors there is no ultimate controlling party as no one individual is deemed to satisfy this definition.

 

END