30September2026

PredatorOil&GasHoldingsPlc /Index:LSE/Epic:PRD/Sector:Oil&Gas

PredatorOil&GasHoldingsPlc

("Predator"orthe"Company"andtogetherwithitssubsidiaries "theGroup") Report and Interim Financial Statements for the 6 months to 30 June 2026

Financialhighlights:

·TheGrouphas cashreservesas at30June2026of£6.6mil(31December2025£1.5mil).

·TheGroupalsoholds£1.5mil(31December2025:£1.5mil)inrestrictedcashbalances (bankguarantees andperformancebonds).

·TheGroupgenerated£1.5milinproductionrevenuesforthe6months periodended30June2026(£66,815forperiodto30June2025).

·Trinidadoperations generatedagross profitof£283,041forthe6 monthsperiodended30June 2026(£66,815grossprofitforthe6 months period ended30June2025).

·TheGroupreportedanoperatingloss forthe6monthsperiodended30June2026of£0.9mil(£1.9milforthe6monthsperiodended30June2025).

·TheGroup’s Intangibleassetsincreasedat30 June2026 to£27.3mil(31 December2025:£26.2mil),mostly duetocosts incurredtoadvancethedrillingof twowells in the second half of 2026 (MOU-6 and Snowcap-3).

·Administrativecorporatecosts forrunningtheday-to-daybusiness oftheCompany increasedforthe6monthsto30June2026to£1.2mil(30June2025:

£821,277).Theincreaseis attributableto the acquisition of a group of companies andthe enlargement of theTrinidad officeto oversee administrationandaccounting of the production revenues andto prepare for drilling operations and production facilities at Cory Moruga. Includedin the aforesaidadministrativeexpenses were£489,506innon-cashitemsrelatedtoTrinidadcompanies whichwerefirst-timeinclusionsafter theacquisitionof thegroupof companiesfrom theChallenger Energy Group. Theadministrative expense also includes a net positivechangefrom foreign exchange losses for the six months to 30 June 2025 of

£341,563toforeignexchangegainsinthecorresponding currentperiodof£136,761.

·Consultant feesforthe6 monthsto30June2026increasedmodestly to£145,223(30June2025:£129,639),reflectingtheaddition ofwellplanningactivityinTrinidad.

·128,571,419sharesissuedtoraise£4.5 milinJanuary ata placing priceof 3.5pence; and 85,714,286shares issuedtoraise£3.0 milinMayata placingpriceof3.5pence.

·9,000,000and6,000,000warrantsgrantedat3.5pencepershare,exercisablewithin3yearsfrom23January2026andfrom20May2026respectively.

·Shares inissueincreasedto900,602,100at30June2026from686,316,395shares inissueat31December2025.

·Deploymentofworkingcapitalfocusedonplanningandpreparationfor Snowcap-3(for Q12027 production)andMOU-6 (for Q12027 potentialpartialdivestment prior to a possible development).

Postreportingdate:

On 29 July 2026 the Company announced the execution of an amendment (the "Amendment") to the existing rig contract with Intrepid Drilling Limited(formerlyStar Valley Drilling Limited) for Rig 101, which is currently stacked at the Company's MOU-5 well site. The Amendment to the existing drillingcontract, dated24October 2022, allows for an extension to facilitate MOU-6 well operations for a period from1 August 2026 to 1 October 2026.

On12 August 2026 the Company announced the contract for the civil engineering works to prepare the Snowcap-3 drilling location to accommodate StarValleydrilling Rig 205 and the Production Facility Area has been awarded to NABI Construction (Trinidad and Tobago) Limited. Site works will commenceimmediately.

On12August2026theCompanyannouncedtheexecutionofadrillingrigcontractwithStarValleyDrilling(Trinidad)LimitedforRig205andthatSC-3 drillingandwelltestingoperationswillcommenceshortlyafterthecompletionoftheMOU-6wellinMorocco.ThiswillensureoptimumdeploymentoftheCompany'smanagement team to efficiently supervise each individual operation in two different jurisdictions.

On19August2026theCompanyannouncedthesettlingofa£323,785debttoMrPaulGriffithsarisingfromthecapitalisationofhisloansinMay2023.ShareswouldbeissuedinlieuofcashtopreservetheCompany'scashresourcesandreducetheliabilitybythevalueoftheSharesissued.Consequentlyitwasagreed

a)40%oftheexistingliability, being£129,514,besettledthrough theissueof Shares toMrGriffiths attheclosingmid-marketpriceon 17August 2026;and

b)Theremaining60%, being£194,271,willbecomepayableupontheearlierofanannouncement thateithera stabilisedflow rateofgreaterthan3 millioncubicfeet ofgasperdayhas beenachievedfromMOU-6 orastabilisedoilrateofgreaterthan200bopdhas beenachievedfromSnowcap-3.MrGriffithswasissued with3,866,090 Shares at a price of 3.35 pence per Share.

On19 SeptembertheCompany announcedthatdrillingoperations hadcommencedontheMOU-6wellin Morocco.

Operationalhighlights:

Trinidad

·Snowcap-3willtargetindependentlyvalidated2Punriskednetrecoverableoilresources of8.73MM.

·Undiscountednet-backofUS$32.6/barrelatWTIspotpriceUS$60/barrel.

·Basedonoffsettestrates forRochard-1 andSnowcap-1 initialproduction guidanceis300 bopdpotentiallyincreasingto459 bopdwhenreservoirscanbecommingled.

·Snowcap-3re-locatedbetweenSnowcap-1andRochard-1wherethetargetreservoirsflowedoilontesting.

·Improvedseismicunderstandingsupportsreservoircontinuity betweenthesewellsandlackoffaultcompartmentalisation.

·Welltobedrilledto5,450feet toevaluateupto650feetof grossreservoir interval.

·Wellplanningandwellinventorybuildcontinuing.

·Sitesuitablefordrillingandestablishmentofproductionfacilitiesidentified.

·Regulatoryapprovalsprogressingtotarget first oilsalesinearlyQ12027.

Morocco

·MOU-6 willtargetindependentlyvalidated2Punriskednetrecoverablegasresourcesof72.4 BCF.

·Welltobedrilledto950 metrestotest approximately51 metres ofgrossreservoirinterval encounteredinMOU-3,600 metres totheSW.

·Wellplanningandwellinventorybuildcontinuingasscheduled.

·41/2”perforatingguns availableforthefirsttime–orderedforimportwith6months deliveryschedule.

·Newwelldesign,wellengineering,anddrillingmudandfluids programmecompletedtoaddressandde-risk historicaldrillingpractices that ledtoreservoirformationdamage.

·Extensivewirelineloggingandtesting programmebeingprepared.

·MOU-6 isbeing designedspecificallytode-riskthepotentialforstableandsustainablegasflow atcommercialrates.Unlike Trinidad, there are no analogue reservoirs in any offset wells to assess potential gas flow rates pre-drill.

·Asuccessfulandsatisfactory gasflow testwillpotentiallytransformtheCompany’sabilitytoconcludeanongoing partialdivestmenttransactionearlyinQ12027that will support a Declaration of Commerciality and an application for an Exploitation Concession in 2027, subject to regulatory approvals.

Chairman’sStatement:

OnbehalfoftheBoard ofDirectors,Iampleasedto presenttheunauditedinterimresultsforPredator Oil&GasHoldingsplc(“theGroup”,“Predator”orthe“Company”) for the six-month period ended 30 June 2026.

Thepriceenvironmentfor oilandgasremainsverystrong,withthecontinuationofconflictintheMiddleEastremaining unresolved.Atthe timeofwritingtheBrent Oil price remains close to $90/bbl.

Thefirsthalfofthisyear has,onceagain,beenaperiodofintenseactivity.

InTrinidadtheonshoreproducingpropertiesacquiredfromChallengerEnergyhavebeenintegratedintotheCompany’spre-existingportfolio.Thishasinvolvedconsiderable administrative and financial work, which has been completed.

Alsoin Trinidad,there has been agreat deal of operational activity of workoversand new wellsin the oilfields acquired from Challenger, carried out by NABI,anexperiencedlocalservicecontractor at nocosttoPredator.This work has managedproductiontoasustainablelevelconsistent withdeliveringstablecashflow forfinancialprojections. The work hasimportantlyreduced outstanding work commitments on theEnhanced Production Services Contractsadministered byHeritagePetroleum.Equallyithasimprovedenvironmentalperformanceandaddedinfrastructuretoassistfutureoperationsandmarketabilityoftheassetsshouldtherebea point in the future where an attractive divestment opportunity arises.

ThehighlightofoperationsinTrinidadthisyearwillbethedrillingoftheSnowcap-3development/appraisalwellontheCoryMorugaconcession,whichhasthepotential to transform theCompany’s production profile and generate truly significant cashflow.

In Morocco, planning hasadvanced todrillthe MOU-6 well,in parallelwith ongoing discussions witha preferredjointventure partnerthat, subject toa successfulandsatisfactory welltest forMOU-6,wouldbecapablesupportinga DeclarationofCommerciality,subject toregulatory approvals.Alllong-leaditems forMOU-6havebeensourcedandareonaschedulefor deliveryintoMorocco,evenagainstabackgroundofverydifficultlogisticalchallengesasaresultoftheconstrictionofmovement of cargoes through the Straits of Hormuz.

OffshoreIreland,whilstmaterialprogresstoobtainasuccessorauthorisationonLicensingOption16/26,containing theCorribSouthgassatelliteprospect,hasnotyetbeenachievedpriorupdatingourfinancialcredentialsby30September2026,weremainoptimisticthatconcernsregardingIreland’ssecurityofgassupplymayfinally provide a path forward.

TheCompanyhascontinuedtorunaverytightship,keepingadministrativecoststoaminimum,despitetheadditionandenlargementoftheTrinidadoperation,sothat funds can flow through to the drill-bit.

Iwouldagainliketothankourshareholdersfor theircontinuedsupportthroughthefundraisingscarriedoutthisyearrequiredtodeliverthe2026 drillingprogrammes.

Finally,IwouldliketopaytributetothetremendouseffortsoftheteamatPredator,whoseeffortshaveallowedtheCompanytomoveforwardanddrilltwopotentially transformational wells in the second half of the year.

StephenBoldy

Non-ExecutiveChairmanOperationalreviewMOROCCO

ActivitiesintheGuercifLicenceonshoreMoroccohavefocussedondesigning,planning andexecutinganoperational programmedesignedtoflowgas fromwhatisnow designatedas the TGB-6 Submarine Fan, whichcovers an area of 81 km²and has a gross interval thickness of 51 metres.In MOU-3 thereare 8 sands thatwouldformthebasis of awellperforatingandtesting programme.Thepresenceof biogenicgas inMOU-3 wasconfirmedpost-drillingbasedonlaboratoryanalysisof formation gas shows whilst drilling.Gas composition was 98 to 99% pure methane, whichrequires very little processing toachieve the necessary quality andcompositional specifications to support gas sales.

IndependentTechnicalResourcesReportbyScorpionGeoscienceLtd.dated 20February2026 (the“ITR”)The ITR specifically focussed on the TGB-6 Submarine Fan interval only.

For the MOU-3 structural closure only withinthe TGB-6 Submarine Fan interval (11 km²) 2C (contingent) recoverable gas resources net tothe Company’s 75%interest areassessedtobe72.4 BCF.TheMOU-1wellalsotestedtheTGB-6 SubmarineFanintervalandsimilarlyencounteredformationgasshowswhilstdrilling.The MOU-1 structurecovers 6 km².Technical studies completed in2026 to date indicate that the MOU-1 and MOU-3 structures are linked to forma singlecommon structure. This supports the 3C (contingent) recoverable gas resources net to the Company’s 75% interest of 151 BCF.

TheTGB-6SubmarineFanintervalpotentialgasresourcesaresufficienttosupporta gross10-yeargassales plateauproductionforecastof10MMcubicfeet/day

(7.5MMcubic feet/day),representing37.8%only oftheCompany’s 75%interest of2C(contingent)recoverablegasresources of72.4 BCF.

Scopetoincreasethegross 10-year gassales plateauproductionforecast to20 MMcubic feet/day (15 MMcubicfeet/day) isachievable basedontheCompany’s75% interest of 3C (contingent) recoverable gas resources of 151 BCF, representing only 48.3% of this figure.

The ITR economic modelling yieldeda gross undiscountedsales revenue net to the Company’s 75% interest of US$456 MM at an averagegas sales priceassumptionofUS$9/Mcf.Thedevelopmentmodel adoptedforthepurposesofestimating netcashflow isaCompressedNaturalGas(“CNG”)option.However,aMicro-LNG development optionis also being considered and evaluated.The20 MM cubic feet/day 10-year plateau production profileyields an undiscounted

EBITDAinrespect of theCompany’s75%interest of3C (contingent) recoverablegasresources of 151BCF of US$245 MMaftertaxes,royalties,capital andoperating costs for a Company IRR of 74%).

Largervolumes ofgaswouldbesuitablefora differentdevelopmentconceptfocussedongas off-takeintotheMaghrebGas Pipeline,whichliesless than10kilometres from the core area of biogenic gas potential.

Conclusion

Technicalstudies andeconomic modellingcarriedouttodatein2026haveconfirmedthatthestructuretestedpreviously bytheCompany’swells MOU-1andMOU-3, andwhich encounteredformation gasshowsinthe TGB-6Submarine Fan interval,isthe primaryinitial candidate for a Declaration ofCommerciality,leading to an application for an Exploitation Concession and ultimately monetisation of the gas resources.

Toachievethisobjectiveanewwell(“MOU-6”)wasdeterminedasbeingnecessaryandwhichisengineeredtoovercomethehistoricalissuesofexcessivelyhigh

mudweightswhilstdrilling,leadingtoreservoirformationdamage,anddrillingfluidsthatreactedwiththeunusualmineralogyofthereservoir sands.

MOU-6wellplanning

AsurfacelocationfortheproposedMOU-6 well,600 metres NWof theMOU-3well,wasselected.AnEnvironmental Impact Study wascompletedandthewellpermitted in consultation with local landowners.

Thepre-drillgeological programmehas beensubmittedtoevaluateallhorizons which exhibitedformationgas showsseeninMOU-3 betweenapproximately 300and 900 metres depth.

Thepre-drilllocationtargets thesamestructureandseismicamplitudeanomalyinMOU-3(tiedtotheformationgasshows between815.5 and866.5 metresdepth in the TGB-6 SubmarineFaninterval). Reservoir thickness and/or quality may be further enhanced at the MOU-6 pre-drill location based onseismicmodellingstudies.

MOU-6 willalsopotentiallyconfirmthepresenceof athick(11-13 metres) sandseenat339 metres inMOU-3,whichhadformationgas showsandislikelytobemoderatelyover-pressured.The“A” Sand,asitis now designated,lies withina structuralclosure of6 km²with2C(contingent)recoverablegasresources net tothe Company’s 75% interest of 21.1 BCF.

TheMOU-6welldesignhasbeenre-engineeredcomparedtoprevious designsfortheCompany’searlierwellstoallowforthe following:

1. Set intermediate casing above the primary TGB-6 Submarine Fan target interval to protect the “A” Sandand any other shallow sands from formationdamage; runwirelinelogs over theinterval(notpreviously attempted);andpreservetheintervalfor perforatingandwelltestinginisolationfromtheprimarydeepertargets.
2. Drill to950 metrestotal depthtoleave no morethan 250 metres open holethroughthe primaryobjective, the TGB-6 Submarine Fan interval.Thiswill reducetheriskofformationdamagecausedpreviously byincreasing mudweight throughthemobile,increasinglyover-pressuredclaystones, below 950metresthatarecharacterised by swelling clay minerals.

1. Thenewwelldesignhasgreaterflexibilityandfacilitates using TCPperforatingguns allowingfor thewelltobetestedimmediately afterwellcompletionusingtherigbeforedemobilisation(stackedat nocost at theMOU-6 wellsite.Thiswilleliminate theprevious delays inhavingtoperformriglesstestinglongafterthecompletion of the well.

1. TheMOU-6welldesignalsoaccommodatestheability,whenrequired,tore-enterthewellandtest the“A”Sand;test othersands;deepenthewell;and/or

sidetrackthewell.

The wellis plannedto be retainedas afuture productionwellandthereforethe abilitytore-enterthe welllaterin productionlifetocominglelowerpressure sandsfor enhancing and prolonging production life is an important consideration.

TheMOU-6 drillingprogrammehas beenpreparedandsubmitted.Thenewfeaturesoftheprogrammerelativetopreviousdrillingprogrammesareasfollows:

1. Drillingmudanddrillingfluidsdesignednottoimpacttheformation mineralogy.

1. Calciumcarbonate(whichissoluble)andnotbarite(whichis reactive)usedtoincreasetheweight ofthemud.

1. Mudweightcarefullymanagedtobeas nearasinbalancewithexpectedformationpressures toreducethepotentialforformation damage.

Welltestingprogrammedesignedfor:

1. Usingthelargest41/2”perforatinggunsforthefirsttime–6-monthlongleadtimetoimport.
2. TCPwelltestingwillallowthereservoirstobeperforatedunder-balancedforthefirsttimetopromoteandenhancepotentialgasflow.

1. Asaconsequence,drawdownpressurecanbeoptimisedforastabilisedgasflowwithoutproductionofunconsolidatedsands.

Alltherequiredwellinventory andwellservicesareprojectedtobeinMoroccoahead ofanticipatedmobilisationoftheStarValley Rig101(re-namedby therigowner Intrepid 11), stacked on the MOU-5 well site, within a window from August to October 2026.

Commercialactivities

Alongsidetheplanning of theMOU-6well,theCompany is engagedincommercialdiscussions tofinanceaninitialgas developmentandtheoff-takeandsaleof thegas to end users.

Subject toasatisfactory gastestresultfor MOU-6 anda periodoftechnical,commercialandlegalduediligence,theCompany expects toannouncea binding legalagreement for the future monetisation of the gas early in Q1 2027.

Keytechnicalandcommercial risks

Currentlyitis notpossibletopredictgas flowratefromMOU-6as therearenoanaloguereservoirstogiveanappropriaterangeofpossibleflow rates.Therefore, although thereis a gross sequence of 51 metres of potential gas the deliverability from individual sands may vary.

Forguidancepurposesonly astabilisedgas flowratefromMOU-6intherange5 to10 MMcubicfeetg/d,combinedwithnoevidenceofsignificantreservoirpressure depletion during theconduct of thewell test,will beseen by the Company as a result that would support aninitialgas development.

Thecommercialriskis onlyattributabletotheinabilitytoflowgasfromMOU-6withintheaboveguidancerates.

Otherprospectivity:desk-topstudies

Additional biogenicgastargets have beenre-evaluated. Ofsignificanceis the potential for biogenicgasin up to 800 metres of section penetratedin MOU-1. Thiscomprises a very finely laminated sectionthat cannot beresolved by conventional wirelinelogs.The Company has been preparing a scope of work for anindependentcontractorwithexperienceinproducing biogenicgasina similarsettingandfromananaloguesectioninRomaniaandUkraine.Theobjectivewillbeto determine if there is a basis for developing a work programme to further evaluate potential to producefrom this interval. TheCompany has identified a corearea of 120 km² where this potential biogenic gas play is developed.

Studies haveprogressedtoassess theappropriatework programmes toevaluateJurassicandTriassicprospectivityforthelargestructuralclosuredrilledby theMOU-5 exploration well in 2025. An option to deepen the well to the Trias will be considered in the future.

Ahigh-levelscopingstudy forthepotentialtocreatecavernsintheTriassicsaltinterpretedtobepresentbelow thepresentdepthreached by MOU-5 has beencompleted. The site is favourably located within 3 kilometres of the Maghreb Gas Pipeline to support gas storage economics.

Themodel forheliumgenerationandtheoriginsofheliumgasinMOU-3andMOU-5 hasbeensupportedbyfurthergeophysicalstudies.

GuercifLicenceterms

AnextensionoftheFirst ExtensionPeriodoftheGuercifLicenceto5November2026wasappliedforand approved.

Afurther extensionto5 February 2027isbeingappliedforandisexpected tobeapprovedbeforetheendof2026.This will enable the results of the MOU-6 well to be fully evaluated by all parties.

AllpartiestotheGuercifLicenceagreethat theresults of theMOU-6well,withthepotentialde-riskingofgas flowat commercialrates,willhavea materialimpacton thescope of the future work programmes for the Guercif Licence. This may include, for example, a separateapplication for an ExploitationConcessionand anewworkprogrammefor theremaining areaoftheGuercifLicencetobedeliveredwithinanextendedtimelinethatreflectsthemultipleprospectscreatedbytheCompany through the drilling of six wells in the exploration phase to date. Of significance is that thereis currently no legislationin placein Morocco for theextraction of helium.

TRINIDAD

ActivitiesonshoreTrinidadhavefocussedon:

CoryMorugaExplorationandProductionLicence–SnowcapStructure

Designing,planningandexecutinganoperationalprogrammedesignedtoflowoilat materialratesfromwhat aredefinedastheGr7aKaramatHerreraandCiperoHerrera 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. tothe WSW, whereapproximately 23 millionbarrels of oil has been recovered over nearly 70 years.

Goudron,Inniss-Trinity,IcacosandBonasseproducingfields

Monitoring production data from thesefields, which are under the operational management ofNABIConstruction (Trinidadand Tobago) Limited ("NABI”), andfrom which theCompany receives 30% of gross sales revenues after deduction of royalty and taxes from productionresulting from well-workovers of the existingwellsinthefield.For new wells drilledby NABItheCompanyreceives 15% ofgross sales revenues lessroyaltyandtaxesincreasingto30% after NABIhasrecoveredits invested drilling costs.

NABI’soperationsareperformedunderthetermsofaMasterServicesAgreement(“MSA”)withtheCompany.

Inits capacity as non-operator,theCompany monitors monthlytheperformanceofNABIundertheterms oftheMSAtoassessstabilisedproduction ratesandgrowth potential; completion of licence commitments; new investment in maintaining and upgrading infrastructure and subsurface geological and reservoirengineeringcompetence.

CoryMorugaExplorationandProductionLicence–SnowcapStructure

IndependentTechnicalResourcesReportby ScorpionGeoscienceLtd.dated20February2026(the“ITR2”)

ITR2addressesthepre-drilloilresourcesbeingtargetedbytheproposedSnowcap-3appraisal/developmentwell.

Snowcap-3willbetestinganarea ofstructuralclosureforthetopof theHerrera#8Sandof2.51km².2PrecoverableoilresourcesnettotheCompany’s100%

interestareassessedtobe8.73MMbarrels.ThisisbasedononlytheHerrera#1,#2,#3and#7(nowre-correlatedas #8) Sands.

TheITR2 economicmodellingassumeda10-year productionprofileforthe Herrera#1and#2 SandswithanunescalatedWTIspotpriceofUS$60 per barrel.Thisyielded an undiscounted net-back of US$32.6 per barrel produced.

The Company’s later updated project economicsare based onaninitialoilrateof 300bopd from the Herrera #1Sand to be tested by Snowcap-3. The Herera#1Sandisthebasal sandinthegrossHerrerainterval.Thetopmost sand,Herrera#8,hasanassumed initialoilratealsoof300 bopdbutisonly producedwhentheHerrera #1 Sandreservoir pressure has fallenafter up to 12 months of productionsoas to enablecomingling of production ata common pressure at aninitialcombined rate of 459 bopd. A 10-year production forecast for thesingle Snowcap-3 well cumulativelyrecovers 489,336 barrels of oil (80,229 barrelsin thefirstyear of production at an average of 220 bopd).

Atan unescalatedWTIspotpriceofUS$75per barrelthis givesanundiscountednet-back ofUS$41.02 per barrel producedandnetundiscountedrevenuestotheCompany’s 100%interest ofUS$2,564,320forthefirst12 months ofproduction.Thesepost-taxrevenues areafterPetroleumProfitTax(“PPT”),whichisreducedfrom 50% to an effective rate of 12.5% by utilising legacy material tax losses when theCompany acquired the entity holding the Cory Moruga Licence interest.

TheCompany’s initialproductionrates arebasedoncomparisonwithoffsetwells ontheSnowcapStructure.Snowcap-1,tothe NEoftheproposedSnowcap-3 welllocation,tested the Herrera #8 Sand at a stabilisedrate of 500 bopd of light oil. Rochard-1, SW of the proposed Snowcap-3 well location,testedtheHerrera #1Sand at an initial rate of 312 bopd of light oil.

TheproposedSnowcap-3 wellis being designedtoberetainedas a productionwell.Thewirelinelogging,perforatingandwelltestingprogrammewillbesufficiently comprehensive to potentially validate the pre-drill forecast production rates and reservoir pressure depletion profile.

Snowcap-3wellplanning

Followingnewgeologicalandgeophysicalstudies theoriginalsurfacelocationfor theproposedSnowcap-3wellhas beenmovedapproximately1700 metrestotheSW of the original surface location, whichlay to the NE of Snowcap-1. A legacy Certificate of Environmental Clearancealready exists for seven wells in the CoryMoruga Exploration and ProductionLicence. This will be updated specific tothe new Snowcap-3 proposedwell locationand to include the establishment ofproduction facilities at the site.

Therationaleformovingthelocationwasasfollows:

1. Seismicre-mappingofa newlyacquiredlegacyversion ofthere-processed 3Dseismicindicatedthat theareaaroundtheoriginallocationwas definedby poorerseismic data quality, possibly attributable to fracturing and the presence of gas.

1. TheoriginallocationonthecrestoftheSnowcapStructureis structurallyhigherthanSnowcap-3.Agas capmay thereforebedevelopedatthislocation.

1. Attheoriginallocationthethrust fault defining theSnowcapstructuraltrapisrelativelyflat-lyingandhardtoseismicallyimage.Thereisa greater riskthereforeof missing key Herrera reservoir sands (as historically in Snowcap-1) if the fault position is poorly constrained.

1. Therevisedwelllocationfor Snowcap-3 isnowlocatedbetweentheRochard-1welltotheSWandtheSnowcap-1welltotheNE –thatis betweentwowellsthathavetestedoilatgoodinitialrates fromtheHerrerareservoirs.Thenewlocationis favourablypositionedwellbelow any potentialgascap,expansionof whichcanalso provide the mechanism for primary oil recovery.

1. Muchimprovedseismiccorrelationof Snowcap-1withRochard-1 andanimprovedseismictieof thedeviatedSnowcap-1well,whichhistoricallyhad beenmis-tied by previous operators, has identified theHerrera #8 Sand inRochard-1,which tested oil at an initial rate of 720 bopd, as the same Herrera #8 Sandas inSnowcap-1, which tested oil at a stabilised rate of 500 bopd.

Basedona revisedHerrera#8 Sandreservoirmapthenew Snowcap-3 well locationis optimallylocatedforwell-developedoilsands,whereastheintervalisnotlikely to be well-developed at the original well location.

Thenewsandtrendis mirroredatthedeeperHerrera #1Sandtargetlevel andtheexpectationisforwell-developedHerrera#1 Sands tobepresentatthis depthtoo.

1. Seismicimagining ofthefault definingtheSnowcapStructureat thenewSnowcap-3locationis unambiguous.Thereforetheriskof missingkeyHerrerasandintervals that are faulted out is eliminated.

Thenewsurfacelocationallowsforthedrillingofa verticalwelladjacenttoa mainroad,thereby dismissinganyrequirementfora deviatedwellatextracost andimproving site access to production facilities and oil storage tanks.

Conclusion

ThenewSnowcap-3locationisoptimalforreservoir development,structuralintegrity,costsavings,andlogisticalplanning.Commercial and technical risk of failure are greatly reduced.

Thepre-drillgeological programmehas beensubmittedtoevaluateallhorizons whichbothflowedontestinRochard-1 andSnowcap-1 andwhichhaveproducedoil in the nearby Moruga West field between approximately 4,700 and 5,400 feet depth.

Thepre-drilllocationtargetsthesamestructureaswastestedbyRochard-1andSnowcap-1.The Snowcap-3 well design has been engineered based on the tried andtested Snowcap-1:

1. Fourstringsofcasing–20”,133/8”,95/8“and7”Completionliner.

1. Drill to5,450 feettotal depthand set intermediate95/8“casing at4,200 feetdepth, toleave no more than 1,250 feet open hole through the primary objective,theHerrerasands interval.Thiswillreducetherisk of formationdamageif mudweight hastobeincreasedthroughmobile,potentiallyover-pressuredclaystones,above 4,200 feet depth that are characterised by swelling clay minerals.

1. Thewell designfacilitatesriglesstesting of theHerrerareservoirintervalimmediatelyafterwellcompletion.Thiswilleliminatedelaysinhaving toperformrigless testing long after the completion of the well.

TheRochard-1 andSnowcap-1 lightoilsarewaxyinnature,thereforewell planning isfocussedonflowassurancefromthetestedreservoirsandplacingthemonproductionas early as possible after completion of thewell to prevent any down-holewax build-up that canrestrict future productionrates without wellintervention and wax treatments.

Accordingly,thecivilengineeringscopeofworkfor theSnowcap-3wellpadlayoutincludesdesignatinganareafortheestablishmentofproductionfacilities.

1. TheSnowcap-3welldesignalsoaccommodatestheability,whenrequired, tore-enterthewellandtest otherHerrerasands (potentially#4,#5and#6 Sands) ifwarranted after wireline logging results.

The wellis plannedto be retainedas afuture productionwellandthereforethe abilitytore-enterthe welllaterin productionlifetocominglelowerpressure sandsfor enhancing and prolonging production life is an important consideration.

Anamendmenttothewell designiscurrentlyunderconsiderationasfollows:

1. TheHerrera #1and#2 Sands areseparatelysealedfromtheshallowerHerrerasandsandmay beover-pressuredbasedon olddata fromtheRochard-1well(1955) requiring a potential significant increase in mud weight whilst drilling into this section.

1. Inordertoprotect theshallowerHerrera #8 Sandfrompotentialformationdamage,anotherstring ofcasing may besetatapproximately5,100feetdepthbefore drilling into the Herrera #1 and #2 Sands.

Theaboveoption,ifselected,willallowtheflexibilityfortheHerrera #1and#2Sands tobetestedandput onproductionfirstandforthewelltobere-enteredinthe future to comingle the shallower Herrera #8 Sand when downhole reservoir pressures have equalised.

TheSnowcap-3drillingprogrammehasbeenpreparedbasedon:

1. Drillingmudanddrillingfluidsdesignedtoaddressthepresenceofswellingclays.
2. Mudweightcarefullymanagedtobeas nearasinbalancewithexpectedformationpressures toreducethepotentialforformation damage.

Welltestingprogrammedesignedfor:

1. Usingthelargest41/2”perforatingguns.
2. Obtaininga stabilisedoilflowrateandconnectedoilvolumetothewell-boretoassistwithfuturedevelopmentwellplanning.

1. Optimisingdrawdownpressureforastabilisedoilflowratewithoutproductionofunconsolidatedsands.

1. Maintainoilproductiontopreventwaxbuild-up.

Rigselection

InitialSnowcap-3 well planning focusedonpotentiallyre-activating a stackedrigwiththecapability of drillingto5,500+/- feet depth.As theSnowcap-3well designanddrillingprogramme evolved,it becameclearthat significant operationaland executionrisk wouldbecreatedby mobilizinga rigstackedfor over 5years todrillthrough the potentially over-pressured Herrera #1 and #2 Sands. The Company concluded that this was an unacceptable risk to bear given the importance of theSnowcap-3welltoits near-termbusinessdevelopmentstrategy.AnalternativeoptionarosetousetheStarValleyrig205,whichhadarecenthistoryof drillinghighpressure wells for another operator near to Cory Moruga. Additionally, Star Valley is well-known to the Company having drilled 5 wells in theGuercif Licence. Thenew rig option was more cost effective and gave greater certainty of operational readiness. Accordingly, the rig reactivationprogramme was abandoned with nocost to the Company.

Alltherequiredwellinventory andwellservicesareprojectedtobeinTrinidadaheadofananticipatedmobilisationoftheStarValleyRig205withina window

fromAugusttoOctober2026and/orfollowingthecompletionoftheCompany’splannedMOU-6drillingprogrammeintheGuercifLicenceinMorocco.

Commercialactivities

Alongsidetheplanning oftheSnowcap-3 well,theCompanyisengagedincommercialdiscussionstosecureoptionsonseveralpotentialSalesPointsfortheSnowcap-3 oil, based on a trucking operation initially and a minimumamount of storage capacity availableat the selected Sales Point.

Third-partyfunding oftheSnowcap-3 productionfacilities,based onthepre-drillexpectationsoftheproductionprofile,isenvisagedcurrentlynotto benecessarygiven the development costs are less than the 10% contingency allowed for the drilling and testing costs for Snowcap-3.

Afull-fielddevelopmentplanwillonlybeconsideredafter6 month ofproductionfromSnowcap-3toallow for planningtherequiredscaledupfacilitiesandinfielddevelopmentwells.

Undertheterms oftheSaleandPurchaseAgreementfortheentirety ofChallengerEnergyGroupPlc’s St.Lucia-domiciledsubsidiarycompany,Columbus Energy(St. Lucia)Limited(“CEG Trinidad”) and itsbusinessand operations inTrinidadand Tobago effective29 August2025, afurther instalment of theConsideration isscheduled for 29 August 2026. It is likely that this will be successfully renegotiatedsoas to have noimpact on theavailable cash tothe Company in2026.

Keytechnicalandcommercial risks

Theprimaryriskis operational.Thisis thefirstwelltobedrilledby theCompany inTrinidadas operator.Whilstmany ofthepotentialissuestobefacedwhilstdrilling are manageable there remains a risk of an unforeseen and un-planned for event.

ThegrossHerrerareservoirsequenceis 509to650 feet thick.Reliableoffsetproductiondataforthesereservoirs exist, includingwithinthesamestructureasSnowcap-3 is re-appraising.

Forguidancepurposesonly aninitialoilflow rateof300bopdincreasing to459 bopdis potentiallyachievable.However,this may beimpactedbyfactorssuchaswaxdrop out, gas content, water cut, oil declinerate and connected volumeto thewellbore.These pre-drill variables can only be de-riskedfollowing thecompletion of a rigless well testing programme over a period of at least 3 days.

ThecommercialriskisattributabletotheinabilitytoflowoilfromSnowcap-3atlessthan,forguidancepurposes only,50bopd.

Minimal productionfacilitiesarerequiredto process oilto be trucked toa SalesPoint. Should these costs escalateor require moreinfrastructure to handle largerthan anticipated pre-drilling estimates of production, then development costs for Snowcap-3 may escalate. In sucha scenario the potential to debt-finance ifabsolutely necessarytheextracosts isanoptionshouldSnowcap-3generatereserves capableofreserves-basedlendinggiventherobust cashflow projectionsforthe independently assessed project economics.

CoryMorugaLicenceterms

CoryMorugaisalreadyanExplorationandProductionLicence.There is no impediment to producing oil from Snowcap-3.

Goudron,Inniss-Trinity,IcacosandBonasseproducingfields

TheCompany has continuedto monitor productiondataand,moreimportantly,its attributablesalesrevenues fromthesefields,whichareunderthe operationalmanagement of NABI under an MSA.

TheCompany has nocost exposuretotheinvestments madeby NABIundertheMSA infieldinfrastructure,heavyworkoversandany potentialnew 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” andregulatory procedures,anda network ofservicecontractors necessary foritto establishits ownproductionfacilitiesfortheCory MorugaLicenceand theproposedSnowcap-3 appraisal/development well.The acquisition of oil storage tanks at the Bonasse field was particularly significant as some will move to the Snowcap-3production 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 theBonasse field via access to the existing crude oil sales arrangement and under the same commercial terms and conditions applicable to Steeldrum under the saidarrangement. This agreement was important to have established as it defined the Company as an oil producer and provided invaluable commercially sensitiveinformation to input into our Snowcap-3 project economics.

Sinceinceptionin2025,implementationoftheMSA fortheacquiredfieldshasresultedin:

1. Reductionoffieldoperatingcostssuchthatthefieldsarenowmakinganoperatingprofittooffsetagainstmaterialtaxlosses.
2. Significantinvestmentininfrastructureby NABIisprovidingnewelectricalinfrastructureandaccess toformerlyinaccessiblewellsforheavyworkovers.
3. Aprogrammeof heavyworkoversisbeingimplementedtosatisfythelicenceworkprogrammecommitments.

GY-664andGY-665intheGoudronfieldare currentlyadding34and18bopdproductionrespectively.

1. Inthefirst6 monthsof2026,grosssales oilwas52,310barrelsrealisingnetpetroleumrevenues of£1,522,877(beforecosts).

UndertheMSAtheCompany’scost-freeshareofpetroleumrevenueswas £306,283.

For June2026,reflecting increasing WTIspotprices,theCompany’s monthly cost-freeshareof petroleumrevenues was £71,690 (US$96,058 exchangerate1.3399on 30 June 2026).

Akey objectiveoftheCompanythathasevolvedduringthefirstsixmonths of2026istomanagefieldoperatingcostsandprofitabilitytomaintainanddemonstratea stabilised net revenue income.

Thefactorsthatimpact thedesiredobjectiveareasfollows:

1. Operationalefficiency–lessfocusonpoorlyperforming,high-costintervention,productionwellsandmorefocusondeliveringastableproductionprofile.

1. Managingtheproductionprofileincombinationwithoilpricevolatilitytoholdback increasingratesuntiltheglobaloil markets stabilise.

Factorsthatimpactthisstrategyinclude:

1. GoudronandInniss-TrinityfieldsareeachoperatedunderaseparateEnhancedProductionServicesContract(“EPSC”)withHeritagePetroleumLimited (“Heritage”).

Thesehavecommerciallylessattractivefiscalterms –includingroyalties toHeritageandaFirstTrancheSales oilquotasoldtoHeritageataverymuchreducedpriceto WTI spot price.

1. FairMarketValueforoilsoldtoHeritagefromtheEPSCissignificantlybelowtheWTIspotprice,toreflecttheHeritagehandlingcost inexportingandsellingtheoil.

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 ofUS$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.

Anotherfactorthathastonowtobeconsideredin2026,andwasnota key concernpreviously,is thatwhenthepricereceivedforoilsalesexceedsUS$75/barrel,

then18% SupplementaryPetroleumProfitTax(“SPPT”)becomespayableonallproduction.ThiscannotbeoffsetagainsttheCompany’slegacytaxlosses.

Therefore,any productionincreasemust besufficiently largeandimmediatetooffsetthenegativeimpact onSPPT onrevenuesatthistimeofunforeseenhighWTIspot 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 forSnowcap-3 in the Cory Moruga Exploration and Production Licence. This is a direct Ministry licence free from the additional fiscal burdens of a HeritageEPSC. Theforecast production levels are sufficient to offset any material impact from the imposition of SPPT on projected sales revenues whilst efficiently utilising theCompany’s tax losses to reduce PPT liability to 12.5%.

Operationalhighlights

DuringJune2026, 21 well interventions were performed onin thefields with13 wells restoredto production,6 wells moved from swabbing to pumping (reducingoperatingcosts).

Theoverallactivewellbasewasincreasedto100wells(83pumpingoil,13swabbingoiland4 wellsflowingnaturally).

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

Operating efficiency was83.8%, partlyimpacted by adverse weather,representing the monthlyaccumulation of 17,830 man hoursfor which the Company has nocostexposure.

IntheBonassefield, new shallow wellsBON-18,BON-19 andBON-20 weredrilledduringtheendof 2025 intoearly2026 by NABIat nocost totheCompany.Thesehaveallbeenplacedonproductionandarepumping oil.TheCompany interpretstheretobemorepotentialtoberealisedby deepening at least one of thesewellsand recompleting an interval for enhanced production. It also identifies several opportunities for new drilling in un-evaluated areas. In order to realise any newpotential, the Company would be required to use its own subsurface technical team to plan and operate the drilling and testing strategy. Currently this isnot animmediate priorityasthefocusis onthepotentiallymuch higherreward offered by theSnowcap-3 appraisaland developmentwell.A subsurfacetechnicalaudit ofthe entire portfoliogoverned by the MSA will be initiated after the Snowcap-3 operations have beencompletedand potential sales production established.

Otherprojects:desk-topstudies

1. Potentialre-entryoftheJacobin-1,Snowcap-1,andSnowcap-2ST1wellsforheavywellworkoversandSGNthermochemicalwaxtreatmentcontinuestobeassessed. Key issues that have been considered during 2026 are as follows:

1. Snowcap-1is nowseenasanideallocationfora gasinjector intotheHerrera#8 Sandtoutilisegas producedduringlaterproductionforgas injection toboost oilrecovery.

1. TheHerrera #6 Sandwas penetratedat theoil-water contact inSnowcap-1.Thereis potentialforanupdipappraisalwelltoaccess specificallythis sandtotargetP50 recoverable oil resources of 1.91 MM barrels.

AnypotentialproductionfromaSnowcap-3 heavyworkoverwillreducecapacityforstorageandsaleofSnowcap-3 production.As a result, Snowcap-3 production might have to be scaled back, potentially increasing the risk of wax dropout.

Onthisbasisare-entryofSnowcap-1 doesnotwarrantexecutingatthistime.

1. The Snowcap-2ST1 well Herrera #8 Sand did not flow naturally on perforating and testing due to extensive formation damage whilst drillingby using high mudweights 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 thissection.

Thewellis nowacandidatetore-enterandrunwirelinelogs overtheHerrera#1 Sandintervalandpotentiallyperforateforwelltesting.

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 #1Sand.

Onthisbasisare-entryofSnowcap-1 doesnotwarrantexecutingatthistime.

1. TheCompany’sanalysis oftheJacobin-1well oilrecoveredaftera fluidlevelsurvey indicateda significantwaxcontentthatmay haveinfluencedthe poorresultswhen the well was originally perforated.

OnthatbasisthewellwasdeterminedaspotentiallysuitableforapilotSGNthermochemicalwax 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 tomanufacturethequantitiesofwaxtreatmentrequired,frequencyoftreatmentandtheoptimumsafemethodofadministeringthe waxtreatment(mostprobablyacoiled tubing unit).To date nothing of substance has beenforthcoming tofacilitatean economic analysis of thetreatment to determine its commercial viability.

Re-enteringJacobin-1atthistimeis nota priorityfortheCompanyasitfocuses ondeliveringtheSnowcap-3drillingprogramme.

1. Desk-topstudiesarebeing consideredto:

1. Evaluatethe potentialof poorer quality,claystone-laminated, oilreservoirs,currently notconsideredintheSnowcap Structureas acontributionto oil resources;for production based on analogues in the Moruga West field.

1. Tore-assesstheeconomics ofCO2EOR basedonthesuccessfulapplicationofthetechniquebytheCompanyinthepilotCO2EOR Inniss-Trinity project.

TheabilityofC02 EORtobreakdownwaxandlowertheviscosityof oilhasbeendocumentedandisapossiblealternativetoSGNthermochemicalwaxtreatment.Enhanced oil rates were recorded in the CO2 EOR Inniss-Trinity pilot project.

Thetechniquemaybeapplicabletothe poorerquality,claystone-laminated,oilreservoirsinparticular.

C02purchasemustbeState-subsidisedtoimproveprojecteconomics –thiswouldbeanappropriateuseoftheGreenLevyFundinTrinidadTo reduce CO2 emissions from ammonia plants.

1. AssessthepotentialfordeepCretaceous gasintheCoryMorugalicencearea.

Currentlythe databaseis poor andthe conceptis conceptual at this early stage. Well costs arelikely to bevery highandwell beyond thefinancial capability oftheCompany.

AlltheabovedesktopactivitiesaremediumterminnatureandnotprioritisedwhilstfocusisontheSnowcap-3 drillingproject.Thereisnojustificationforincreasingcorporate, administrativeand technical overheads to further mature these conceptual projects at this time. A further review in early 2027 is likely.

Forwardplans

Solefocusfortheremainderof2026istoexecutetheSnowcap-3 drillingandwelltestingprogramme.

Subjecttosatisfactorywellresultsandregulatoryapprovals,thewellwillbeputonproductionwiththetargetoffirstoilsalesfortheearliestopportunityinQ12027.

Ireland

The Company is focussed onsatisfying the financial criteria determined by the Geoscience Regulation Officeof the Department of Climate, Energy and theEnvironmentby 30September2026tosecuretheawardofasuccessor authorisationoverits legacyLicensingOption16/26(CorribSouth).Thepotentialawardofa 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 goingforward).

Satisfyingthefinancialcriteriaonlybecomesabindingcommitmentifasuccessorauthorisationisofferedandaccepted.

Theregulatoryprocess maycontinueformany months,thereforethisshouldnotbeconsideredasa“near-term” project withouta higherthannormallevelof

executionrisk.

Ifofferedalicenceinthefuture,theCompanywouldneedtocarefullyconsiderthesocio-economic-politicalclimateinIrelandattheprevailingtimeofany awardinorder to makea considered judgement whether or not it can rely on the IrishGovernmentsupport for any future operational commitments inCorribSouth.

The Company believes that Corrib South iscurrently the only asset offshore Irelandthat isstill within thelicensing regimeumbrella thatcontainsa structure withthehighest chanceof success tofindgasinastructurevery similartothat hosting the Corribgasfield.Asinglewelltie-back 18kms totheexistingCorribfield,andviathe pipelinetoshoreto thegas terminal,can prolongthe lifeand economicviabilityofthe infrastructure, thus reducing over-reliance onimported gasattimesof peak gasandelectricitydemand.Thelead-timetodelivertheproject islessthanany other optiontheIrishgovernment has, providedtheprojectis treatedas astrategic infrastructure project for fast-tracking.

CorribSouthcandeliverIreland’sonlygasstoragefacilityquickerthananyotheroption,subjecttotheprovisoabove.

Prolongingthelifeof theCorribproductionfacilitieswould enablea FSR LNGoffshoreimportfacilitytobeestablishedand long-termLNGimportcontractstobenegotiated and executed which would lower the price of gas in Ireland and give security of gas supply.

Thepractical,pragmatic,strategicandeconomicadvantagesareobvious,howeverthisisnotalwaysenoughtoswaytheStateinthedecision-makingprocesses.

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

TheCompanyis consideringitsresponsetotheGSRO’srequest.

Financialreview:

TheGroupreportedan operating lossfor the6monthsperiodof£0.9mil(£1.9milforthe6monthsperiodended30June2025).Theoperatinglossisafterincurringadministrative expenses of £1.2mil (£0.8mil for the 6 months period ended 30 June 2025).

Thetotallossattributabletoshareholderscomprised£0.9mil(2025:£1.6mil)

AdministrativeexpensesattheTrinidadsubsidiaries’level contributedtotheoverallincreaseinadministrativeexpenseoverthe2025levelduetoexpansionofthelocal office to prepare for the Snowcap-3 well planning and drilling operationsand the first-timeinclusion of theTrinidad Energy Ministrypenalties and taxes of

£208,616 duelargely to historical operational debts assumed on theacquisition of the entirety of Challenger Energy GroupPlc’s (the ”CEG Business”) St.Lucia-domiciledsubsidiarycompany,ColumbusEnergy(St.Lucia)Limited(“CEGTrinidad”)anditsbusinessandoperationsinTrinidadandTobago;andadecommissioningcost provision of £78,188, although no decommissioning of any production wells is envisaged in the medium-term.

Administrativeexpensesdirectlyrelatedtorunningtheday-to-daybusinessofthecorporateentityreflectasignificantincreaseincorporateactivitiesin2026withthe acquisition of producing assets inTrinidadand the resultantre-structuring of multiple subsidiarycompanies to retainlegacytax lossesand enablefuture

potentialflexibledivestmentofring-fencedindividualassets.Directorsfees increasedto£188,133(2025:£93,966).Consultantfeesincreasedto£145,223(2025:

£129,639)reflectinggreateractivitywithin the Trinidad Group. Technicalservicesarecharged by key consultants andthe executive directorin providingtechnicalsupportandreportsthatwouldotherwisehavebeenoutsourcedtothirdpartiesatcompetitivemarketratesincircumstanceswhereacquiringsimilarlyskilledandexperienced consultants would be potentiallychallenging. Administrativeexpensesat thecorporate level are also attributable to brokers’ fees:£76,686onthe

£7.5milfundraises.Brokers’commissions weresettledbytheissueofsharesandnotwithcash;Atthecorporatelevelforeignexchangelossesincludingtranslationeffects amounted to £43,492 (£234,187 gain for the 6 months period ended 30 June 2025).

TheCompany raised£7.5mil.intwoplacings: 128,571,419sharesissuedto raise£4.5 milinJanuaryata placingpriceof3.5pence;and85,714,286sharesissuedtoraise £3.0 mil in May at a placing price of 3.5pence.

Asaresult,thenumberofsharesinissueincreasedto900,602,100at30June2026from686,316,395sharesinissueat31 December2025.

9,000,000and6,000,000warrantshavebeengrantedat3.5pencepershare,exercisablewithin3yearsfrom23January2026andfrom20May2026respectively.

TheGroupisfinishingthereporting periodwithcashreservesasat30 June2026of£6.6mil(31 December2025£1.5mil).TheGrouphasnointerest-bearingdebt.Inaddition, theGroup holds TheGroup also holds £1,480,440 (31 December 2025: £1,455,000) inrestricted cash balances (bank guarantees and performancebonds).Therestrictedcash balanceincludesa US$1.5mil (£1,134,000) securitydeposit for the Guerciflicence in the form of a bank guarantee heldin favour ofONHYM. Restricted cash of £346,440 was held in Trinidad companiesat 30 June2026 as securityin favour of Heritage for licence performance bonds.

TheGroupgenerated£1.5mil(£66,815forthe6monthsperiodended30June2025)inproductionrevenuesfromoperationsinTrinidadfollowingtheacquisitionsof the CEG Business in 2025 and entering into a Master Services Agreement with NABI.

Trinidadoperationsincurredagrossoperatingprofitbeforechargingadministrativeexpensesof£283,041(2025:£66,815)

Sharebasedpaymentsweresignificantlyreducedto£54,701(anon-cashflowitem)inthecurrentperiod(£1,176,935forthe6monthsperiodended30June2025).The reduction is due mainly to there being no new share options awarded in the period to 30 June 2026.

TheGroup’sIntangibleassetsincreasedto£27.3mil(2025:£26.2mil)at30June2026,mostlyduetocostsincurredtoadvancethedrillingoftwowellsinthesecondhalf of 2026 (MOU-6 and Snowcap-3).

Nonewshareoptionswereissuedand3,000,000shareoptionsexercisableat10pexpiredduringtheperiodto30 June2026.The Company has no interest-bearing loans nor outstanding directors’ loans.

TheCompanyiswell-capitalisedforitsimmediateworkprogrammes.Thesituationremainsunderreviewasearlydrillingsuccessin either Moroccoor TrinidadwillenhancetheCompany’sportfolioofearlystagedevelopmentassets,withpossibleearlyproductionandcashflow,andpotentiallypartial divestment.Maintainingaprudent level ofcash reserves, throughconsidering all the diverse financing options availabletothe Company, will be necessaryto maintainmomentumtowardsachievingtheproductionobjectives.Thisisparticularlyrelevantinthecase ofTrinidadwheretheSnowcap-3wellcanpotentiallybeplacedonproductionrelativelyquickly.TheCompanyismaintainingitsundilutedequityinitskeyTrinidad andMoroccanprojectsthroughtheinitial higherriskstageofdiscoveryandappraisaltomaximise its opportunity to retain all production revenues andto demonstratea position of operational control and undilutedownership in future potential

divestmentnegotiations.ThisallowstheCompany’sassetstopotentiallyhavesufficientmaterialitytoimpacttheMoroccandownstreamgasmarketandTrinidadonshore oil production. This potentially enhances the strategic value and materiality of the Company’s assets.

PaulGriffiths

ChiefExecutive Officer

PaulGriffiths,ChiefExecutiveOfficerofPredator,commented:

“TheInterim FinancialStatementsfortheperiodto 30June2026 demonstratethat wearegenerating anoperating profit inTrinidadthatisset to increasesignificantly in early 2027 with the anticipated quantum of early production, subject to regulatory approvals, from the Snowcap-3 well.

Theacquisitionofourproducingassets inTrinidadin 2025laidthe foundationfordevelopingthe internal structures necessaryto be atechnicaloperatoroffutureproduction in our own right and to establish the commercial framework required for the sale of oil and generation of production revenues.

Snowcap-3willbeourfirstoperatedwellinTrinidadandthereforemuch ridesonthesuccessofthiseagerlyanticipated well.

In Morocco wehavespentconsiderabletime onunderstandingand resolvingthechallengingissuesinherent inourearlierdrillingand welltestingprogrammes thatfailedtodeliverourexpected resultsin this partof the Guercif Basin,which hadnever previously been drilled. We are confidentthat our pre-drill well re-designandre-engineering has reduced significantly operational risk to align with anticipated reservoir geology and formation pressures. The remaining technical andcommercialriskistodemonstrate agas flowcapableofsupportingafuture development,subjecttoregulatory approvals.Inthisrespectweare very encouragedtohave progressed discussions that in an MOU-6 success case will lead to the conclusion of a partial divestment opportunity. It demonstrates that the Guercif Projecthas never lost the interest of those who are familiarwith and understand the attractiveness of the risk-reward proposition forthe biogenic gas sampled in theprevious 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 ofHormozshouldnotbe under-estimated.The Company’swelldeliveryteamandmanagementhave workedtirelesslytogethertoensure thatwehave securedallofour required specialist well logging tools and even the larger 41/2” perforating guns to create the best opportunity for a successful result forthe MOU-6 well.

Inorderto deliverthe2026drillingprogramme,we havetakenthe necessarysteps toensure that weare adequatelycapitalisedforthe forecast eventualitiesinthecoming months before production revenues reach a sufficient level to fund ouroperations.We have continued to adopt a strategy of not entering into interest-bearingloans inthe early,higherrisk,stageofearlyproject development.Neitherhavewe dilutedprojectequity ata prematurestageof valueenhancementforan“easy win” that might have reduced ourcontrol overour assets and ourability to offer an attractive material entry position into the Moroccan gasmarket or theTrinidad onshore oil sales market.

The immediate outlook for the rest of the yearis positive with not one but two potentially transformational wells being drilled overa 3-month period in twodifferentjurisdictions–one forgas andoneforoil.Riskisdiversifiedand rewardisconsummate withtheeffort required thisyearto achievethisposition.Iwouldlike to thank oursmall operations, technical and financial team for theircollective efforts. Only they would know what it has taken to achieve this position.”

PaulGriffiths

ChiefExecutiveOfficer( ) September 2026

Forfurtherinformationvisitwww.predatoroilandgas.com

FollowtheCompanyonX @PredatorOilGas.

Thisannouncementcontainsinsideinformationfor thepurposesofArticle7oftheRegulation (EU)No596/2014onmarketabuse.

FormoreinformationpleasevisittheCompany'swebsiteatwww.predatoroilandgas.com:

Enquiries:

PredatorOil&GasHoldingsPlc

PaulGriffithsChiefExecutive Officer

Tel:+44(0)1534834600

Info@predatoroilandgas.com

AlbRCapitalLimited

DavidCoffman/JonBelliss

OakSecurities

JerryKeen

Tel:+44(0)207469 0930

Tel:+44(0)203973 3678

Jerry.keen@oak-securities.com

FlagstaffStrategicandInvestorCommunications

TimThompsonMarkEdwardsFergusMellon

Tel:+44(0)2071291474

predator@flagstaffcomms.com

NotestoEditors:

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

Moroccooffersapotentiallyfasterroutetocommercialisationofshallowbiogenicgas throughaCNGormicro-LNGdevelopment.

Thestructurepenetratedby theMOU-1andMOU-3wellsiscurrently definedas havingthebest potentialforanapplicationforanExploitationConcessionin2026.TheCompanyiscommittedtopartneringwithentities capableofsupportingafuturedevelopmentdecisionandwhohavealreadyidentifiedtheopportunityas onewarranting the execution of a CollaborationAgreement and a Memorandum of Understanding. Moroccangas prices are high, andthe fiscal terms aresome of thebest in theworld. The presenceof gas export infrastructureadjacent totheMOU-1 andMOU-3 structureallows fora scalablegas development afterinitialCNG ormicro-LNG gas production over time establishes the extent of connected gas volumes and the capability of reservoirs to deliverat plateaurates over time.

Moroccangasprices arehigh,andthefiscalterms aresomeof thebest intheworld.

Trinidadoffersthesecurityofa matureonshoreoilprovincethathasbeenproducinghydrocarbonsforover50years.Predatorhasassembledaportfolioof onshoreproducing fields with opportunities for productionenhancementandadditional infill developmentandappraisal drilling.Significantlegacy taxlosses, economies ofscale and the application of new low-cost technologies are factors that can improve profit margins per barrel of oil produced.A Master Services Agreement withlocaloperatorNABIConstructionrelievestheCompany oftheburdenandcostsofoperatingthefieldsandexecutingdrillingandheavywellworkovers.InreturntheCompany receives30% of gross salesrevenues forwhichitcan useitsacquiredtaxlosses tosubstantiallyreducePetroleumProfit Taxfrom50%toan effectiverateof12.5%.

PredatorhasanexperiencedmanagementteamwithparticularknowledgeoftheMoroccanandTrinidadsub-surfaceand operations.

PredatorOil&GasHoldingsplcislistedontheEquityShares(transition)categoryoftheOfficialListofthe LondonStockExchange's mainmarketforlistedsecurities(symbol:PRD).

Forfurtherinformation,visitwww.predatoroilandgas.com

GoingConcern

TheGroup'scashflow projectionsindicatethattheGroupshouldhavesufficientresourcestocontinueasagoingconcernin aminimumcommittedexpenditurecase.

Asat30 June2026 theGrouphadcashof£6.6mandnointerest-bearingdebtandwasreceivingcash flow fromproductioninTrinidad,which,ifnecessary,canbere-purposed for a short period to support working capital.

Licence work programme commitmentsin the second half of2026 relateto the drillingofthe MOU-6 wellin Morocco andtheSnowcap-3 wellin Trinidad. Pre-drillbudgetestimatesfordrillinghavebeensatisfiedbytwoplacingscompletedinJanuary2026and May2026raising£4.5miland£3.0milrespectivelybeforeexpenses.Asa result,theGroupis notexpectedto requirefunding toexecute the drilling programsin Trinidadand Morocco based oncurrent budget estimatesand whichhave been scheduled for second half of 2026.

The April 2026forecast for production revenues from Trinidad have hadto be revised to takeintoaccountthe day-to-dayvolatilityof oil pricesand the significantrisesinWTIspotprice,whichcantrigger aSupplementaryPetroleumProfit Tax(“SPPT”)of18%thatisnotcapableofbeing offsetagainstlegacytaxlosses,andtheincreaseinoilexporttankercosts,whichimpact theFairMarketValuepaid byHeritagePetroleumLtd.(“Heritage”)attheSales Point.Under theseprevailingfiscalconditions, significantincreases in production must be achieved very quicklyto offsettheimpact of 18% SPPT onthe entire production output. Increasingproductioninthe onshore fields, particularlythose with thelessattractive net-back due to additional Heritage royaltiesand FirstTranche Oil terms, with modestwelldeliverabilityratesand higher operating costs does notincreasecash flowby a quantumthatjustifies the operationaleffort. Therefore, the fieldsare beingmanagedtosupport a stable andconsistent monthlyrevenue net-back for the Company under the Master ServicesAgreementwith NABI until oil price stabilises.Net cash flow isthe key financial metricatpresent, not production outputfrom the onshore fields,whichis being maintainedatan optimumlevel. The Companyhas no exposure to investment and operating costs for these assets.

Duringthesecondquarterof2027thereisaforecastshortfallinrequiredfundingafterGroupoverheadsaretakenintoaccount.There are currently no firm work programmelicence obligations for 2027. All forecast operations are discretional.

Snowcap-3inTrinidadisadevelopmentwellintheCoryMorugaExplorationandProductionLicence,whichisexpectedtobeproducingoil,subjecttoasuccessfuldiscretionarywell testing programme, andsignificant monthly positive cash flow in Q1 2027 from a quantum of dailyproductionat a sufficiently high enoughsustainable level to offset any impact of SPPT as a result of high oil prices.

MOU-6inMoroccoisanappraisalwell,whichsubjecttoasuccessfuldiscretionarywelltesting programme,willsatisfyaconditionprecedentfora partial

divestmentofinterestintheMoroccanasset,subjecttoregulatoryapproval,undertermsthatmayincludeastagedrepaymentof100%ofpastcosts,commencingasearlyas Q12027. The Company, subjecttoa successful MOU-6 well,isconfident thatacommercialtransaction willbe concluded within, forguidance purposesonly, the time framework forecast above.

Theabovearesourcesofadditionalfundingbythesecondquarterof2027thatarepotentiallyavailabletomeetworkingcapitalrequirementsandalsodiscretionary operational commitments for the period May 2027 to September 2027.

TheGroup’ssubsidiariesarefundedbyinter-companyloansadvancedbyPredatorOil& GasHoldingsplc(theCompany’).Therecoverabilityoftheinter-companyloansadvanced dependsalso on thesubsidiariesrealising their cash flow projectionsand will depend on raising either equity,and/or bank debt finance,and/orlicence and/or joint venture partnerships,and/or potential partial or complete divestment of itsassets in Morocco, ifanattractive opportunity to monetiseispresented 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 30June 2026.The situationremains under review asearlydrillingsuccessineitherMoroccoorTrinidadwillenhancetheCompany’s portfolioof earlystagedevelopment assets,withpossibleearly productionandcashflow,andpotentiallypartial divestment.Maintainingaprudentlevel ofcashreserves,throughconsideringallthediversefinancingoptionsavailabletotheCompany,willbenecessarytomaintainmomentumtowardsachievingtheproductionobjectives.This isparticularlyrelevantinthecaseofTrinidadwheretheSnowcap-3wellcanpotentially be placed on production relativelyquickly. TheCompanyis maintainingitsundiluted equityinits key Trinidad and Moroccan projects throughthe initialhigher riskstage of discoveryand appraisal to maximiseits opportunitytoretainall productionrevenuesand to demonstrate a positionof operational control andundilutedownershipinfuturepotentialdivestmentnegotiations.ThisallowstheCompany’sassetstopotentiallyhavesufficientmaterialitytoimpacttheMoroccandownstream gas market and Trinidad onshore oil production. This potentiallyenhances thestrategic value and materialityof the Company’s assets.

The Board have revieweda range of potential cash flow forecastsfor the periodto 30 September 2027,including reasonable possible downsidescenarios. GoingforwardtheGrouphasanumberofdifferentoptions,independentofalsobeingabletoreducecorporatecosts,byapportioningoperatingandadministrativecostsover alarger portfolio of producing assets,raise equity funds(as it hasshownto beconsistently capable of doing sincelisting asa publiccompanyin 2018),and

accessingreserves-basedlending,topotentiallyincreaseits workingcapitalifrequiredas follows: Theexisting Trinidadoil fields andlicenceandIPSCcommitmentsareself-fundingundertheNABIMaster ServicesAgreement.TheCory MorugaExplorationandProductionLicenceandSnowcap-3 oildevelopment areexpectedtobecomeself-fundingwhenproductioncommencesinthecourseoftheearlypartof2027.Cashresources heldat30 June2026willbeappliedtodrillingandtestingSnowcap-3 ("SC-3")appraisal and development well.The well isscheduled for Q4 2026 andisexpected to take up to 20 daysto drill and log to a depth ofapproximately5,450 feet. It isintendedto put the well into production in Q12027after drilling andtesting iscomplete. SC-3will potentiallyunlock the

independentlyassessed2Presourcesof8.73MMfortheHerrera#1,#2,#3and#8Sands(previouslydesignated#7Sand).fortheHerrera#1,#2#3and#4Sandsof

56.9MMbarrelsofoil.ThecashflowforecastsfortotalexpectedTrinidadproductionarerobustandaresufficienttocoveranyWorkingCapitalForecastshortfallduring the second half of 2027.

The Groupis progressing a potential partial divestment for the Guercifgas asset,which will include the principles for financing a Phase 1 CNG or Micro-LNGdevelopment,outlinetermsforaGasSalesAgreement,allcontingentonregulatoryapprovalsandtheawardofanExploitationConcessionin2027.Additional

principlestobeincludedareexpectedtoincludejointventureparticipationinfutureexplorationofthebiogenicgasplay, andJurassicandTriassicprospectivityonthe GuercifLicence. Predator GasVenturesLimited will remain operator of the Guercif PetroleumAgreement andany future Exploitation Concession.

PredatorOil&GasHoldingsPlc

Interimfinancialstatements for theSixmonths to30June 2026

Financialhighlights

forthesixmonthsto30June2026

Financialhighlights:

• Fullyfundedtoexecutethedrillingandtestingofthetwowells, oneinMoroccoandoneinTrinidad,inthesecondhalfof2026.
• Atotalof£7.5mil,beforeexpenses,raisedintwoplacingscompletedinJanuary2026andMay2026.Asaresult,thenumberofsharesinissueroseto900,602,100 at 30 June 2026 from 686,316,395 shares in issue at 31 December 2025.
• TheGroupgenerated£1.5mil(£66,815forthe 6monthsperiodended30June 2025)inproductionrevenuesfromoperationsinTrinidadfollowingtheacquisitions ofthe CEG business in 2025 and a MSA arrangement concludedwith NABI.
• Trinidadoperationsincurredagrossprofitbeforecharging administrativeexpensesof£283,041(2025:£66,815)
• TheGroupincurredalossfromoperationsforthe6monthsperiodof£0.9mil(2025:£1.9mil).Thelossisafterincurringadministrativeexpensesof

£1.2mil(2025:£0.8mil).

• Administrativeexpensesdirectly relatedtorunningtheday-to-daybusinessofthecorporateentityhavebeenprudentlymanageddespiteasignificantincreasein corporateactivitiesin2026.Theincreaseinadministrativeexpensesatthecorporatelevelisattributabletobrokers’expenses:£76,686onthe

£7.5mil fund raises. Brokers’ commissions were settled by the issue of shares and not with cash;At the corporate level foreign exchange losseson balancesheettranslationof £94,614 (£252,077 gain for the6 months period ended 30 June 2025); and directors and technical fees £188,133 (2025: £93,966)contributed to theincreaseinthecurrent period.Theadditiontopermanent personnel of aGeneral Manager for theTrinidadGroupaddedtotheincreasedlevel offeesinthecurrentperiod.Technical services arecharged by key consultants and the executive directors providing technical support and reports that wouldotherwisewouldhavebeenoutsourcedtothirdpartiesatcompetitivemarketratesincircumstanceswhereacquiringsimilarlyskilledandexperiencedconsultantswouldbepotentiallychallenging.

• Administrative expenses atthe Trinidad subsidiaries’ levelcontributed significantly to theoverallincrease in administrativeexpenseoverthe 2025leveldue tothefirst-time inclusionof theTrinidadEnergy Ministry penalties andtaxesof £208,616due largely tohistoricaloperationaldebts assumedontheacquisitionfrom CEG;and decommissioning costs of £78,188;
• Sharebasedpayments significantlyreducedto£54,701 (a non-cashflow item) inthecurrent periodfrom the£1.2m (a non-cashflow item)incurredinthe6monthsperiodended30June2025. Thereductionis duetoissuance of share options inthe6months periodended30June 2025,whichwas notrepeated inthecurrentreportingperiod.
• Thetotallossattributabletoshareholderscomprised£0.9mil(2025:£1.6mil).
• Intangibleassetsroseto£27.3mil(2025:£26.2mil)at30June2026mostlydueto costsincurredto advancethedrillingoftwo wellsinthesecondhalfof2026.
• The Groupis finishing thereporting periodwith cashreserves as at30June2026 of £6.6m(31 December 2025£1.5m). TheGrouphas nointerest-bearingdebt.Inaddition,the Groupholds £1.5mil (2025: £1.4mil) in restricted cash balances.The restricted cash balance includesaUS$1.5mil security deposit for the Guerciflicence in theformof abankguaranteeheldin favourofONHYM.Restrictedcashof£346,440washeldinTrinidadcompaniesat 30 June 2026assecurityinfavour of Heritage for licence performance bonds.
• No freshshareoptionswere issuedduring the reportingperiodand3,000,000shareoptionsexercisableat10pexpiredduring thereportingperiod.
• 9,000,000and6,000,000warrantsgrantedat3.5pencepershare,exercisablewithin3 years from23January2026andfrom20May 2026respectively.
• 5,030,795brokers’warrantsexercisableat10.5pexpiredduringthereportingperiod.

PredatorOil&GasHoldingsPLC

Condensedconsolidatedstatementofprofitorlossforthesix months to 30 June 2026