10 Oil and Gas Companies to follow in 2026
Lower oil prices presented tough conditions for many explorers and producers through 2025. Brent crude fell by more than 15pc to trade at around $60 a barrel. Supply rose sharply as OPEC and its partners ramped up production, and more oil was produced in the US.
The IEA forecasts that global oil supply will continue to exceed demand next year, by an average of 3.84 million barrels per day. But the organisation’s most recent report indicates higher demand is reducing the imbalance. Breakthrough US trade deals have encouraged global economic sentiment after tariff-related tensions hit consumption earlier in the year. New and continued sanctions on major suppliers such as Venezuela and Russia have constrained supply. The IEA expects the phenomenon of ‘parallel markets’, in which ample crude supply is juxtaposed with tight fuel markets, to persist into the new year.
Continued oversupply means the environment for high-cost oil production, frontier exploration and speculative expansion will continue to be unfavourable.
But the prospects for natural gas and liquefied natural gas (LNG) are much brighter, driven by demand from Asia, continued energy-security concerns in Europe, and coal-to-gas switching.
Gas continues to gain importance as a transition fuel for power generation, industry and heating. Long-term LNG contracts signed over recent years are now translating into new capacity and more stable cash flows. Companies exposed to LNG exports, gas-weighted production and gas infrastructure are well positioned to benefit.
Investors should look closely at energy services and efficiency-focused technology. With capital discipline a priority, producers are spending less on aggressive expansion and more on improving productivity, reducing costs and extending the life of existing assets. Digitalisation, automation, drilling optimisation and emissions-reduction technologies are gaining importance, shifting growth in services away from volume-driven drilling and toward smarter, more efficient operations. And carbon capture and storage, blue hydrogen and methane-reduction initiatives are attracting increasing investment as companies respond to regulatory pressure and investor expectations.
Conditions for North Sea producers remain bleak. With mature assets and a tax take consuming 78pc of profit, the UK’s once formidable oil and gas industry is one of the world’s toughest markets.
There are still opportunities. Oil and gas still supplies about three-quarters of the UK’s total energy demand. The Government’s decision to allow drillers to develop new fields next to existing ones should encourage some new production. Energy consultancy Wood Mackenzie estimates there may be an additional 1.4 bn barrels equivalent of economically feasible reserves in the North Sea relatively close to existing sites. But there is little indication that the windfall Energy Profits Levy, imposed after the Ukraine war briefly boosted profits, will be lifted under the present administration.
Operators are responding through a surge in M&A activity. TotalEnergies has entered into a joint venture with private equity group HitecVision and Spain’s Repsol, following other North Sea tie-ups including Eni, Ithaca, Equinor and Shell. Bigger companies can lower unit production costs, and offset tax credits from past losses against production.
Here, we look at how 10 Oil and gas companies faired in 2025 plus look ahead to their prospects in 2026. Also look out for our small cap mining picks of 2026 plus our 10 alternative companies to follow.
Arrow Exploration (AIM:AXL)
Arrow Exploration (AIM:AXL) has built on a highly successful 2024 with the continued exploration and development of highly prospective Colombian oil assets.
Focused on expanding oil production from some of South America’s most active basins, including the Llanos, Middle Magdalena Valley (MMV) and Putumayo Basin, AXL’s core asset is a 50pc working interest in Columbia’s highly prospective Tapir Block.
Spanning 65,154 gross acres, with 32,577 acres net to AXL, Tapir’s 3P reserves (at 2020 year-end) were a gross 3.9 MMbbls, with 1.9 MMbbls net to AXL. Oil fields to the southeast of the Block along a similar fault trend had produced 38.5 MMbbls as at the end of 2020. The average peak or test rate from the three main producing formations within the vicinity of the Block was approximately 1,100 bbls/d, with some rates in excess of 2,000 bbls/d.
AXL described 2024 as ‘the best year for the Company so far on all fronts’, with substantial growth in production, revenue and EBITDA. The company recorded a 65pc increase in total oil and gas revenue to $73.7m (FY 2023: $44.7m), and a 78pc increase in adjusted EBITDA of $48m (FY 2023: $27.1m). Annual average corporate production was up 63pc to 3,542 boe/d (FY 2023: 2,167 boe/d). Seven horizontal wells and five vertical wells were drilled, with Proved Developed Producing reserves at year-end 2024 increasing by 92pc to 2.4 MMboe.
AXL’s most recent results – for Q3 2025 – showed the company had maintained the higher levels of production achieved in 2024, reporting average corporate production of 4,214 boe/d (Q3 2024: 4,124 boe/d). The company recorded net $18.5m oil and natural gas revenue,. New development wells have been drilled in Tapir’s Carrizales Norte field, and an exploration well in the Block’s Mateguafa Oeste field. The company reverted to a single operating rig to consolidate spending after the intensive capital outlay required for new exploration. AXL was discussing options for extending Tapir with regulators.
Reporting last month on its latest exploration wells, AXL said the Mateguafa 6 (M-6) well, in Tapir’s Mateguafa Attic field, had reached total depth and been put on production at a heavily restricted rate of approximately 824 bopd gross (412 BOPD net). The testing results indicated ‘the well is capable of higher rates’. The ultimate flow rate will be determined in the first few weeks of production. Another new well Mateguafa 5 (M-5) continues to produce at approximately 550 bopd gross (275 bopd net).
Earlier this month AXL reported that the Mateguafa H27 well had been put on production at 1,694 bopd (gross) (847 bopd net). The testing results indicate the well is capable of higher rates and the ultimate flow rate will be determined in the first few weeks of production. The Mateguafa 6 well (M-6) continues to produce at approximately 772 BOPD gross (386 BOPD net). The Mateguafa 8 (M-8) well has been spud, and the Mateguafa 9 (M-9) well is planned. Total corporate production is approximately 4,510 boe/d
AXL said: ‘The M-HZ7 well reinforces the materiality that the Mateguafa Attic discovery represents for Arrow. Future wells will help determine the extent of the pools and the potential reserves additions. The area has definitely turned into another core area for Arrow with the potential for further horizontal drilling development.’
AXL is looking forward to other prospects. A 3D-seismic survey over the southeast Tapir block has identified multiple prospects, notably Icaco, which has target formations that have yielded success elsewhere in Tapir. The first exploration well at Icaco is targeted for Q1 2026. The company continues to develop other producing fields, including Carrizales Norte and Rio Cravo Este, with horizontal wells, recompletions, and water-disposal infrastructure.
AXL currently trades at 12.5p with a market cap of $CAD71m.
Block Energy (AIM:BLOE)
Block Energy (AIM:BLOE) has taken significant steps towards unlocking the full value of previously discovered fields in the former Soviet republic of Georgia, closing on a farm-in deal for the company’s highly prospective Project III gas resource, and completing a pilot injection programme towards the validation of a major Carbon Capture and Storage (CCS) facility near the capital city of Tbilisi. Initial results have confirmed rapid mineralisation of the injected CO2.
BLOE is now Georgia’s largest independent oil and gas company, with interests in seven PSCs covering an area of 4,256 km2, with good connections to the Southern Gas Corridor linking Azerbaijan with Turkey and southeast Europe. The company’s principal asset is its 100pc interest in the onshore licence Block XIB, historically Georgia’s most productive block. XIB’s key fields have more than 2.77 TCF of 2C contingent gas resources with an estimated NPV of $1.65bn. BLOE is pursuing four concurrent projects to monetise low-cost, low-risk developments across the company’s assets to reinvest in delivering XIB’s gas resource..
The company’s flagship Project III is focused on the undeveloped gas-bearing natural fracture system within the Block’s Lower Eocene and Upper Cretaceous reservoirs. BLOE estimates the Project could achieve production of 4.7 bcm per year – around 40pc more gas than Georgia currently consumes.
Earlier this month BLOE received a non-binding farm-in offer for Project III from ‘a large energy company’. The indicative offer includes a full carry of the Patardzueli-Samgori appraisal programme, comprising three historical well re-tests (two Lower Eocene and one Upper Cretaceous); two highly inclined sidetracks targeting the Lower Eocene; and a full suite of reservoir data acquisition and well-testing operations.
In addition to the appraisal carry, the offer includes an initial development carry covering the construction and hook-up of a 20 MMcf/d (c. 3,300 boe/d) early-production facility. Block estimates the total gross cost of the proposed carry to be in the range of $25-30m.
Negotiations are advancing with a major international energy and petrochemical company on a potential farm-in to Project III. The company has signed a non-exclusive MoU with a leading international trading company establishing a framework for potential future gas offtake and marketing cooperation. The farm-out would see initial production of 20 MMCF/d (c. 3,300 boepd) following completion of the appraisal programme, with a planned ramp up (in the 2C case) to 200 MMCF/d (c. 33,000 boepd).
Project IV is focused on another farm-out, for the XIQ PSC just north of Block XIB, in which the company holds a 10pc interest. Discussions are advanced for a leading international E&P company to commit to an exploration of XIQ’s Martkopi Terrace prospect, which holds 301.7 MMboe mean unrisked recoverable prospective resources.
The Block XIB field offers one other intriguing prospect: a potential CCS facility with the potential to serve as a net-zero hub in Georgia’s industrial heartlands. A study commissioned by the company estimates a CO2 storage capacity ranking – at both reservoir and basin scales – amongst the highest in Europe, the reservoir scale storage is estimated at 256 million metric tonnes, and the basin scale at up to 8.7 gigatonnes. The technology proposed for the storage of CO2 in the Middle Eocene is similar to that successfully deployed by CarbFix in Iceland.
A pilot injection programme, the first of its kind in the eastern European region, was successfully completed in August, paving the way for commercial engagement with industrial partners and carbon markets. Post-injection sampling and third-party laboratory analysis has confirmed rapid mineralisation of the injected CO2, with 70pc to 100pc mineralisation being achieved since the pilot injection. BLOE said: ‘These results are a major technical milestone for Block. Post-injection sampling and third-party laboratory analysis has confirmed rapid and permanent mineralisation of CO2 in the reservoir, materially de-risking the project and enabling us to take the next steps toward development and commercialisation … Mineralisation provides a fundamentally different and higher-integrity form of storage as compared with conventional CCS and delivers permanent storage without the reliance on long-term trapping mechanisms … We’re therefore very excited to begin work on Phase 2 and what could become a material asset for the Company.’
BLOE completed a £1.5m raise last month to support the CCS programme and its farm-out campaigns. The new funds will also Project I, aiming for oil production from the Middle Eocene reservoir of the West Rustavi/Krtsanisi field, where eight development zones identified, and Project II, focused on the redevelopment of the Middle Eocene reservoir of the Patardzeuli and Samgori fields, where a large legacy well stock offers multiple drilling opportunities. Patardzueli-Samgori Middle Eocene (Project II) contains 2C contingent resources of 235.0 MMbbl. A new Project I well drilled this year marked the first successful application of the Company’s ‘slim-hole’ technology in Georgia. BLOE’s projects are also supported by ongoing production. During H1 2025 the company reported total production of 87.5 Mboe comprising 66.4 Mbbls of oil and 21.1 Mboe of gas (1H 2024: 82.8 Mboe, comprising 61.3 Mbbls of oil and 21.5 Mboe of gas).
BLOE moves into 2026 with two major value catalysts: Project III and the CCS initiative. Prospective investors should keep a particularly close eye on the proposed Project III farm-in. BLOE currently trades at 0.75p, up 17pc this year, with a market cap of £7.55m.
Borders & Southern (AIM:BOR)
Borders & Southern (AIM:BOR) has soared this year as a Final Investment Decision by JV partners Rockhopper Exploration and Navitas Petroleum for the multi-million barrel Sea Lion development project has highlighted the potential of the Falklands Basin. BOR is seeking farm-in partners for its Darwin Field, located to the south of the Basin.
BOR has 100pc interest and operatorship in three production licences covering an area of nearly 10,000 square kilometres in the South Falkland Basin, a frontier focus for exploration extending to the south and east of the Falkland Islands.
The company’s flagship Darwin field, located in 2000 metres of water approximately 2.6 km below the seabed, comprises two adjacent tilted fault blocks, Darwin East and Darwin West. Extensive work has been done to define the field’s potential, with BOR having completed three seismic surveys and drilled two deep water wells.
A 2012 discovery well situated on the Darwin East structure yielded an independent resource assessment for the combined Darwin East and Darwin West fault blocks of an un-risked (P5O) recoverable resource of 462 million barrels of liquids. The mobility of the hydrocarbon in the reservoir and the excellent reservoir quality promises a high hydrocarbon recovery rate and relatively low capex. Engineering studies have demonstrated that the discovery, if successfully appraised, could be commercialised through standard floating production, storage and offloading units using proven, off-the-shelf technology.
BOR has dedicated the past two years further defining the prospect’s potential, and strengthening the company’s balance sheet to support farm-out discussions, assisted by the appointment of an international investment bank with global networks. BOR raised a gross £2.2m from institutional and private investors earlier this year, securing a cash balance as at 30 June of $3.2m. The company now has sufficient funds to cover its expected overheads until the end of 2026.
Navitas and Rockhopper confirmed a FID for the Sea Lion project earlier this month. Sea Lion is prospective for 319 million to 500 million barrels of certified 2C recoverable resources.
BOR said: ‘We are delighted that Navitas and partner, Rockhopper, have taken FID on Sea Lion. It is a transformational moment for all stakeholders in the Falkland Islands. The significance of the region taking its first step towards being a fully-fledged oil and gas producing province cannot be overestimated. FID on Sea Lion proves that projects in the Falklands are bankable and further enhances the value of our project … Our world class Darwin prospect has over 460 million barrels of recoverable liquids, a phased development plan, very quick payback and huge upside with 40 plus prospects that could yield over 9 billion barrels of liquid hydrocarbons and 10Tcf of gas.’
Darwin continues to elicit fresh and renewed interest from potential tier-1 industry partners amid the associated interest in the Falkland Islands, a regime offering highly competitive fiscal terms, as a new hydrocarbon producing basin. The IEA has highlighted how historic under-investment in new projects has led to over reliance on shale oil and gas, necessitating new investment to replace declining fields. The Sea Lion development in the South Atlantic Ocean north of the Falklands, where partners Navitas Petroleum and Rockhopper Exploration are closing on a final investment decision, highlights the potential of the Falklands basin to host major projects.
BOR is up by more than 300pc this year, trading at 10p at the time of writing with a market cap of £88m.
Challenger Energy (AIM:CEG)
A year in which Challenger Energy (AIM:CEG) sharpened its focus on exploration opportunities offshore Uruguay culminated in its acquisition by Canadian oil and gas exploration company Sintana Energy. The combined company is targeting a highly prospective petroleum system that parallels major discoveries off the Namibian coast. (Pending the completion of the acquisition, expected by the year end, this overview will refer to CEG as the company under review.)
CEG holds two licences offshore Uruguay covering a (gross) 19,000 km2. The company has a 40pc non-operating interest in AREA OFF-1, covering approximately 14,557 km2, following a farm-out of a 60pc operating interest to Chevron. CEG’s technical work has identified three prospects, with ‘significant multi-billion barrel resource potential’.
The agreement commits Chevron to cover the costs of a 3D seismic campaign up to $37.5m. CEG will receive $12.5m from Chevron on completion. Chevron will then carry 50pc of CEG’s share of costs associated with an exploration well, up to a maximum of $20m. The partners expect seismic acquisition to begin ‘in late Q4 2025’, subject to the finalisation permitting by the Uruguayan Ministry of Environment.
CEG’s wholly owned AREA OFF-3 covers an area of 13,252 km2 located in a relatively shallow water depths approximately 100 km off the Uruguayan coast. Two primary prospects were identified and mapped when the licence was held by BP. Following extensive technical work focused on the licensing, reprocessing and interpretation of a 1,250 km2 3D seismic data set, CEG has commenced a formal farm-out process. The material aggregate resource potential for the licence’s two primary prospects comprise a best estimate (Pmean) of approximately 380 million barrels oil recoverable, and an upside (P10) case of approximately 980 million barrels oil recoverable. The prospects’ shallow water and reservoir depths indicate relatively low development costs and commerciality at even modest discovery volumes.
CEG strengthened its financial position through the year with the disposal of legacy assets in Trinidad and Tobago, bringing its ‘true’ cash holding to around $9m, sufficient funds ‘to meet all of its planned activities for the remainder of 2025, 2026, and well into 2027, without the need for any additional capital.’
All of that was before September, when CEG announced an agreement for the terms of an $84m acquisition by TSXV-quoted Sintana Energy which has interests in petroleum systems offshore southwestern Africa with parallels to those held by CEG. Sintana’s portfolio of assets in Namibia includes a 4.9pc interest in the Mopane discoveries (PEL 83) announced in 2024, and indirect interests in five other blocks.
With a diversified portfolio of high-impact assets in multiple jurisdictions and basins CEG and Sintana want to create ‘an Atlantic-margin focused oil and gas exploration “champion”’. The combined company will ‘enhance opportunities to deploy combined expertise in oil and gas projects, attract increased investor interest, and generate returns to shareholders.’ CEG said: ‘This recommended merger fulfils all the strategic intentions of Challenger, creating an entity with a diversified and very high-graded portfolio, and which will be a springboard to further excellent returns for both sets of shareholders.’
According to terms of the acquisition, which was approved by CEG shareholders last month, CEG will delist from AIM and become a private subsidiary of Sintana. Sintana will retain its listing on the TSXV exchange and join AIM. An indicative date of 24 December has been given for admission. Former CEG shareholders should receive 0.4705 Sintana shares for each share they held in the formerly listed company.
The combined company enters the new year with several value milestones in view, notably the prospect of a decision on exploration well drilling at AREA OFF-1 following 3D seismic acquisition, and commencement of the AREA OFF-3 farm-out process.
Before leaving AIM CEG was valued at 9.5p, up 40pc on the year, with a market cap of £27.1m. Sintana is expected to debut on AIM imminently – before the year end – with an estimated market cap of around £100m.
Eco Atlantic (AIM:ECO)
Eco Atlantic (AIM:ECO) ended 2025 in style, securing a farm-out partner for its portfolio of offshore projects in Guyana, Namibia and South Africa, and sending its share price soaring.
The company operates and has an 85pc working interest in four assets covering 28,593 km2 in Namibia’s Walvis Basin – PEL 97, PEL 99, PEL 100, and PEL 98 – with prospective resources estimated at approximately 2.362 billion boe (P50). PEL 98 has already been farmed-out and, prior to the agreement, partners were being sought for the other three.
The company has two blocks in South Africa’s hugely prospective Orange Basin. Prior to the recent agreement it was seeking to farm-out Block 1 CBK, in which it has a 75pc working interest and operatorship. Legacy discoveries at the Block offer evidence of an active petroleum system in both shallow and deep-water. ECO has acquired all existing 3D and 2D seismic surveys, and secured exploration rights.
The company has a 5.2pc interest in Block 3B/4B where the partners are waiting for final environmental permits from the South African government. ECO is due to receive $11.5m from its Block 3B/4B JV partners upon milestones in accordance with previously signed farm-out agreements. An initial drilling target has been identified.
Before December’s ground-breaking announcement ECO was also seeking to farm-out the Orinduik Block offshore Guyana. ExxonMobil is currently developing the Hammerhead discovery at the neighbouring Stabroek block.
Earlier this month entered into a ‘truly transformational’ binding framework agreement with Navitas Petroleum with game-changing implications for the Block 1 CBK and the Orinduik Block offshore Guyana (close to ExxonMobil’s Hammerhead discovery at the neighbouring Stabroek block). Navitas, which recently acquired Challenger Energy, is an international oil and gas exploration and production partnership with a portfolio of established North American and Falkland Islands oil and gas assets.
Under the agreement Navitas will farm-in to Block 1 CBK for $4m to take a 47.5pc working interest. ECO’s remaining working interest, up to 47.5pc, will be carried for the work programme, with the value of the carry being capped at $7.5m net to ECO. Navitas will farm-in to the Orinduik Block for $2.5m in exchange for an 80pc working interest and operatorship.
Navitas will also have the option, subject to agreement on commercial terms at the time of exercise, to potentially acquire at least 25pc of ECO’s working interests, encompassing PEL97, PEL99 and PEL100 in Namibia, and an interest of at least 25pc in Block 3B/4B offshore South Africa. Under the terms of the strategic partnership ECO and Navitas will work on a 50:50 basis on future new ventures and assets targeted and potentially acquired by ECO.
Welcoming the agreement, ECO said: ‘This strategic partnership with Navitas, a multi-billion-dollar company with a strong record in acquiring, financing, and developing high-impact oil and gas projects, is truly transformational for Eco Atlantic. The proposed Guyana and South Africa farm-ins, together with our understanding that this is a long-term collaboration, significantly enhances our ability to accelerate growth across our portfolio.’
ECO currently trades at 20.5p, up 90pc on the year, with a market cap of $CAD126m.
Reabold Resources (AIM:RBD)
Reabold Resources (AIM:RBD) moves into 2026 looking ahead to a work programme to re-establish gas flow at the PEDL 183 licence at West Newton, and the prospect of revenues from an earn out mechanism triggered by the sale of its interest in one of Europe’s largest undeveloped gas licences.
RBD describes Colle Santo, an onshore gas resource with 65 bcf of 2P reserves, as ‘the largest onshore proven undeveloped gas field in mainland Western Europe’. The development, which will consist of a small-scale LNG facility producing an initial 10 mmcf/d, has the potential to produce for 20 years and generate an estimated €11-12 million of gross post-tax free cash flow per annum. It would help to meet increasing demand for LNG in Italy, where it serves as a transition fuel replacing diesel in road and maritime transportation.
Subject to regulatory approval Colle Santo will produce first gas in 2027. In August LNEnergy’s development plan was granted a positive opinion by the region’s Independent Environmental Impact Assessment Commission, a significant milestone towards the final EIA Ministerial Decree and the award of a Natural Gas Production Concession. LNEnergy is finalising an agreement with Italfluid, the development’s proposed contract operator.
In October RBD announced a binding conditional agreement for the sale of its 47.4pc interest in LNEnergy to Beacon Energy for a €16m earn out mechanism. RBD will receive 25pc of its pro rata share of the net cash flow from the Colle Santo project once on production. Beacon is organising a placing to raise approximately £3.5m to finance the Colle Santo project through to a final investment decision and towards first production. RBD will participate in the placing with an investment of £750,000.
RBD said: ‘Through this transaction, Reabold has successfully crystallised value from the Colle Santo gas project, both through the Earn Out mechanism and the receipt of Beacon shares, whilst protecting Reabold shareholders from any further funding requirement, increased development costs or dilution in the asset … This is the Reabold strategy in action; unlocking strategic gas discoveries which have considerable valuation uplift potential by securing funding to bring projects to the next stage of development.’
RBD has significant onshore and offshore interests in the UK. The company has a 69.9pc economic interest in PEDL 183 in West Newton, an onshore hydrocarbon discovery located north of Hull, England operated by Rathlin Energy. Three wells have been drilled indicating what may be one of the largest hydrocarbon fields discovered onshore UK.
The JV partners plan to re-enter and re-complete West Newton’s A-2 well to establish sustained gas flow. The full field development plan calculates a pre-tax NPV(10) net to RBD for West Newton of $179m. The Environment Agency has issued a draft permit and a decision document for review. RBD expects operations to commence in Q1 2026 pending approval. The partners believe West Newton will be an important strategic asset to the UK as the country looks to secure domestic gas supply for affordable energy.
Rathlin is pursuing an intriguing innovation to co-locate gas-powered generators and crypto mining equipment at West Newton, signing a non-binding Letter of Intent with 360 Energy, a natural gas offtake and monetisation solutions provider. Rathlin will work with 360 Energy to scope, design, and, subject to regulatory and third party approvals, deploy 360 Energy’s proven In-Field Computing technology, a natural gas offtake solution designed to convert produced natural gas directly into electricity to power on-site data centres, generating revenues from bitcoin production. Mined Bitcoin could prove both a precursor and supplement to the unlocking of West Newton’s substantial low-cost natural gas. The site may also be suitable for powering co-located AI data centres: the British Government has signalled strong support for rolling out AI capacity across the UK.
RBD’s other British interest is a 10pc holding in Licence P2659 in the Southern North Sea. Initial four year work programme commitments for the licence are focused on completing an advanced geophysical processing study using 475 km2 of existing 3D seismic data. RBD also has a 42pc shareholding in Daybreak Oil and Gas, an OTC traded oil and gas company exploring and producing crude oil and natural gas in California, and a 50.8pc position in Danube Petroleum, owner of the Parta exploration and Iecea Mare production licences in Romania. ADX Energy, which holds the remaining 49.2pc on behalf of Danube, is engaged in ongoing discussions with regulatory authorities in relation to options to extend the Parta exploration licence or work programme alternatives.
RBD retains a strong balance sheet with net cash at £4m as at 30 June 2025. The company currently trades at 0.05p with a market cap of £5m.
Tower Resources (AIM:TRP)
Tower Resources (AIM:TRP) enters 2026 anticipating the regulatory green light for drilling to begin on its highly prospective Thali Block in Cameroon. The company is also closing on another significant interest, the PEL96 concession offshore Namibia.
The Thali PSC, covers 119.2 km2 in shallow waters in the Rio del Rey basin. The basin has produced more than a billion barrels of oil, and has estimated remaining reserves of 1.2 billion boe, primarily within depths of less than 2,000 metres. It is a sub-basin of the Niger Delta, an area in which over 34.5 billion barrels of oil have been discovered, with 2.5 billion boe attributed to the Cameroonian section.
The Thali Block has the potential to hold at least four distinct play systems, including two established plays in which three discovery wells have already been drilled. TRP estimates risked PMean recoverable resources of 35.4 million barrels.
TRP’s Namibian asset covers an 80pc operated interest in Blocks 1910A, 1911 and 1912B (PEL96) over 23,297 km2 of the northern Walvis Basin and Dolphin Graben, an under-explored offshore region in which recent drilling results have proven the presence of a working oil-prone petroleum system, with good quality turbidite and carbonate reservoirs.
TRP also holds a 50pc interest in the Algoa-Gamtoos licence, offshore South Africa, covering 9,369 km2 straddling the Algoa and Gamtoos basins on the shelf, and the outboard slope edge of the South Outeniqua Basin. Algoa-Gamtoos is adjacent to the Brulpadda and Luiperd discoveries in the 11B/12 Blocks owned by Total.
TRP opened 2025 announcing transformative farm-out agreements, for both Cameroon and Namibia, with Prime Global Energies, a UK company with more than three decades of upstream operational experience.
Under the agreement TRP will farm-out a 42.5pc non-operated interest in the Thali license to Prime in exchange for a $15m cash contribution towards the Thali work programme and the drilling of the NJOM-3 well. Prime will also acquire a 25pc non-operated interest in PEL96, with TRP receiving $2.5m cash on completion (of which $1.875m will be held back pending completion of both the Thali and PEL96 farm-outs). The partners agreed in principle to work together on other projects in Cameroon, with Prime participating up to 42.5pc depending on the project.
Since the deal TRP has sustained momentum, securing a jack-up rig to drill the NJOM-3 well and putting all major service contracts in place, minimising time between approval and drilling. The company now expects drilling ‘to commence in the first quarter of 2026’. TRP said the ‘Cameroon government has quite formal approval processes, and as with many governments the elapsed time for them can be lengthy even when the process is positive’. But the company remains ‘completely confident about drilling the NJOM-3 well’. Last month Cameroon returned President Paul Biya to office, who has already indicated support for the Thali project. TRP has also entered in into discussion with multiple banks for longer term development financing of the next Thali three wells.
In Namibia TRP continues to identify data to further narrow down the area within the license where 3D seismic should be acquired, probably by the end of 2026. In South Africa the operator of TRP’s Algoa-Gamtoos JV license continues to meet potential production partners. Legal issues regarding the implementation of environmental regulations introduced by the country’s new petroleum law are gradually being resolved.
TRP has also built its finances in readiness for drilling in Cameroon early next year and to keep its Namibian work programme on track. The company’s H1 2025 results stated cash of $394,025, but it has expanded its Bridge Loan from £0.75m to £1m, and raised £500,000 and £280,000 in two subscriptions over the past three months.
TRP currently trades at 0.03p with a market cap of £8.35m.
Touchstone Exploration (AIM:TXP)
After securing the acquisition of Shell Trinidad Central Block earlier this year Touchstone Exploration (AIM:TXP) anticipates ramping up production next year to take advantage of a tightening gas market.
TXP’s core Trinidad and Tobago developed natural gas acreage holds gross 2P reserves of roughly 53,030 Mboe, and developed crude oil acreage gross 2P reserves of roughly 14,349 Mboe. The company’s exploration acreage extends over some 137,312 net acres.
2024 saw TXP increase production and revenue, improve cash flow, and return to profit. The company achieved record annual production of an average of 5,734 boe/d, up 44pc on 2023. Revenue was 19pc higher at $57.47m, and funds from operations increased by about 22pc year-on-year to $16.75m. Net earnings were $8.27m.
TXP closed the year with the acquisition of Shell Trinidad Central Block, which holds a 65pc operating working interest in the Central Block exploration and production licence and gas processing plant in Trinidad and Tobago. The $23m purchase increased TXP’s base net production by approximately 2,080 boe/d (94pc natural gas) at field estimated rates at the time of purchase.
Gross production from the Block was approximately 18.0 MMcf/d of natural gas and 200 bbls/d of natural gas liquids (approximately 3,200 boe/d). The Block came with natural gas sales contracts providing access to both local and LNG world gas market pricing. Infrastructure included an 80 MMcf/d gas processing plant, field natural gas and liquids flowlines, and a gas export pipeline to both the domestic market and an LNG facility. The Block offered opportunities ‘for numerous infill well locations as well as a deeper Cretaceous prospect’.
2025, however, has been tougher. TXP’s Q3 results reported $5.86m in operating netback, a 21pc decrease from Q3 2024, which the company attributed ‘primarily due to decreased petroleum and natural gas sales and related royalties and increased natural gas operating expenses.’ Cash flow from operations declined to $0.74m from $3.02m in the prior year equivalent quarter. Petroleum and natural gas sales were $12.7m, 4pc down from $13.25m recorded in the comparative prior year quarter. TXP recorded a net loss of $2.06m compared to net earnings of $1.85m from the previous year.
But there are green shoots. Q3 production averaged 5,141 boe/d (71pc natural gas) against 4,399 boe/d (69pc natural gas) in Q2, and only slightly down from a year ago, when it was 5,211 boe/d (75pc natural gas). TXP said Q3 production reflected strong performance from the recently acquired Central field, and the stabilisation of two existing wells.
A new well targeting a previously identified natural gas zone with bypassed pay potential is being mobilised to Central Block, with production expected to be tied into the company’s existing natural gas processing facility in the first quarter of 2026. The company has identified new reservoir intervals for perforation in both the Cascadura-2ST1 and Cascadura-5 wells at its Ortoire licence. The zones ‘are capable of producing water-free oil and can be accessed at minimal cost without the use of a service rig.’ TXP plans to drill up to four additional development wells and may conduct fracture stimulations on two existing wells.
The company is also working with the National Gas Company of Trinidad and Tobago to revise gas pricing at Cascadura, ‘as current pricing does not adequately reflect the capital intensity of development or align with that received by other producers in the country.’ TXP closed a $12.5m private placement of convertible debentures and common share purchase warrants with a private investor to support the remaining 2025 Cascadura development drilling programme.
TXP moves into the new year with hopes of capitalising on tightening gas markets. As the company proved in 2024, it commands an infrastructure capable of supporting significantly higher production volumes. The Central block purchase, which has already started to prove its worth this year, has equipped the company with additional production firepower, and access to LNG markets that may command higher prices than domestic gas contracts.
TXP is currently valued at 7.15p with a market cap of $CAD40.7m.
Union Jack Oil (AIM: UJO)
Frustrated by planning and tax issues in the UK, Union Jack Oil (AIM: UJO) has pivoted to make strategic progress in the US, making multiple commercial discoveries and building a royalty income stream. In Britain the company continues to generate cash through its Wressle field, and is looking ahead to testing the highly prospective West Newton licence.
The Wressle field (PEDL180/182), in which UJO holds a 40pc interest, remains one of the UK’s most productive conventional onshore fields and the cornerstone of UJO’s UK operations. The field has produced more than 735,000 barrels to date, and generated more than $23m net to UJO since a 2021 enhancement programme. In H1 2025 Wressle produced another 120 bopd net to UJO. With 2P reserves of 2,373 Mboe (with 263pc uplift) it is expected to generate significant revenue for at least another decade, contingent upon planning approvals. Operator Egdon Resources has revised development plans in light of the Finch Supreme Court judgement, which has required companies to account for the impact of Scope 3 emissions.
UJO has a 16.665pc interest in West Newton (PEDL183), which with 2C gas of 197.6 Bcf and 2C liquids of 593,000 bbl, has the potential to become one of the UK’s most significant new onshore gas developments, with rapid time-to-cash-flow once tested. It has a 55pc interest Keddington (PEDL005(R)) where more than 3,000 barrels were produced last year since re-startup. A planning appeal for the Biscathorpe (PEDL253) licence, in which UJO holds a 45pc interest, has been dropped.
UJO’s US strategy has delivered multiple consecutive commercial discoveries since 2023, validating the move away from UK planning risk and the impact of the Government’s Energy Profits Levy.
The company has a 45pc in the Andrews Field, where two recent commercial discoveries have yielded cumulative production of more than 72 MMcf gas and 10,000 barrels of oil. Moccasin 1-13, in which UJO has a 45pc interest, is a new commercial discovery producing around 60 bopd at constrained rate, with 1,000 barrels produced to date. Crossroads and Wolverine-1, both spudded in Q4, offer 1.67 million barrels and 1.31 million barrels gross estimated recoverable respectively. Wolverine-1 is particularly promising, with multiple reservoir targets.
UJO has also secured no-capex revenue growth through a mineral royalties portfolio comprising six royalty packages across three major US basins. The assets produced revenue of £69,438 in H1 2025, a return on investment of more than 18pc.
A sharp decline in crude prices during early 2025, continued US dollar weakness reducing translated US revenues, and a lower production rate of 149 boepd (H1 2024: 198 boepd) hit UJO’s oil and gas revenues in H1 2025, which was down to £1.29m from £2.34m. A net profit of £789,000 turned into a net loss of £490,000. But company remains debt free, and secured new funds, designated for drilling in the US, through a £2m institutional placing in July.
Moving into 2026 UJO continues to face planning and tax issues in the UK, but can look forward to secure cash-generative production led by Wressle and US wells that have yielded repeated commercial drilling successes. Near-term catalysts include new exploration in the US and testing at West Newton.
UJO currently trades at 2.4p with a market cap of £3.52m.
United Oil and Gas (AIM:UOG)
United Oil and Gas (AIM:UOG) has risen in value this year as the company continues to define and close on regulatory approval for its fully-owned Walton-Morant exploration licence offshore Jamaica. The prospect could prove to be one of the world’s few billion-barrel frontier opportunities.
Historic and new data, including 2,250 km2 of 3D seismic, indicates the 22,400 km2 licence has multiple plays and prospects supporting compelling evidence for a working petroleum system. An independent report highlights 11 high graded prospects and leads containing over 2.4 billion barrels of recoverable unrisked mean prospective resources potential, the largest containing a potential 1.1 billion barrels. 21 prospects have been identified, each promising more than 100 million barrels of oil. UOG’s sum of the mean/mid case prospective unrisked resources for each prospect and lead comes to more than seven billion barrels mean/mid case recoverable unrisked prospective resources.
UOG is seeking a farm-out partner and advancing planning and permitting to prime the licence for operations.Earlier this year the company secured a two-year licence extension to January 2028, creating the running room needed to drive farm-out discussions forward. Permitting has progressed further, Jamaica’s regulators awarding UOG an Environmental Permit and the Beach Licence opening a clear regulatory pathway for the next phase of technical work, which will include sub-surface geochemical exploration and piston coring (a technique used to collect sediment cores from the seafloor.)
By providing direct geochemical evidence of hydrocarbon generation and migration, a piston coring survey could increase the Geological Chance of Success (GCoS) at Walton-Morant’s Colibri prospect from 19pc to 32pc, and the GCoS at the Oriole prospect from 13pc to 21pc. It could drive similar uplifts across other prospects within the Walton Morant licence where hydrocarbons are detected.
UOG raised £2.33m in October to support a survey and fund the company through 2026, and signed a contract last month for a survey vessel for the planned piston coring and surface geochemical programme, due for imminent mobilisation. The programme will analyse 40 to 60 seabed cores from the Walton and Morant Basins, and bathymetric, multibeam, and heat-flow surveys. UOG expects geochemical and thermal signatures confirming the presence of a working petroleum system. The operations are expected to last two to three weeks with initial results ‘expected early Q1 2026.’ Jamaica’s port infrastructure remains operational in the wake of the recent storms. The company is working with authorities to support on-going relief efforts.
While focused on Jamaica, UOG also has a significant development asset onshore UK in the form of a 26.25pc working interest in the PL090 licence, which includes the Waddock Cross oil field. Operator Egdon Resources estimates that Waddock Cross contains a significant Stock Tank Oil Initially in Place (STOIIP) volume of 57 MMbbls, and that a new horizontal well could yield commercial oil production of 500 to 800 bopd, with around 1 MMbbls recovery per well. The partners are currently progressing plans for restarting production at Waddock Cross.
UOG currently trades at 0.13p – up 44pc this year – with a market cap of £5.3m.
