10 Oil and Gas Companies to follow in 2025
Readers need no reminding its been another indifferent year for UK markets, and another poor one for AIM.
Nearly 90 companies have left the exchange in the past year, leaving not much more than 700, the fewest since 2002: 1,694 companies were quoted at the market’s 2007 peak.
Such is the dark mood that a forecast by investment bank Peel Hunt that up to a third of small and mid-cap AIM businesses could be bought up next year, rendered vulnerable due to a lack of liquidity and depressed valuations, might be the best bet for many investors.
Issues include insufficient coverage by professional analysts (UK small and mid-caps attract a quarter as many as their US peers), a significant reduction over the past 15 years in British investment funds targeting small companies, ever tighter liquidity, and the tidal pull of investor money towards passive investment strategies focused on major indices.
A paper by Barclays highlights some common proposals to address one of the most vexatious issues, the path by which companies can transition from AIM to the LSE Main Market, including extending – for a limited period – the tax concessions enjoyed by AIM investors, such as relief from capital gains and inheritance tax, and the abolition of the 0.5% transaction tax currently levied on many LSE securities. Other proposals are more drastic: a report by the Onward and Tony Blair Institute think tanks argues AIM should simply be abolished, and merged with a beefed-up Main Market
That is perhaps rather too bleak. AIM head Marcus Stuttard, noting that so far this year 40pc of all capital raised across Europe’s growth markets has come from AIM, said that ‘Over almost 30 years, AIM has supported more than 4,000 companies to raise nearly £135bn in equity capital, enabling pioneering businesses to fund innovation, create jobs and drive growth.’
With appropriate reforms, and a more favourable low interest rate economic environment, things could be different. Of the more than 250 European start-ups generating $100m to $500m in revenue, almost half are based in the UK. Britain has a world class scientific research base, and a strong record of innovation in blooming sectors such as AI, fintech and biotech. Markets need to try harder to attract them.
In the meantime those companies that do list on AIM offer opportunities for the diligent researcher, many of them, as our roundup suggests, in the energy and resources sectors.
This year it became ever clearer that the transition to a lower carbon and more digital economy needs a lot of energy. The IEA forecasts consumption to grow by about 4pc this year, up from 2.5pc last year. Global electricity demand has risen at an annual rate of 1,000 terawatt hours, equivalent to plugging another Japan into the world’s grid.
Reasons include soaring demand for air conditioning, the proliferation of AI data, the onshoring of manufacturing, and mass adoption of electric vehicles. Nuclear power is back in fashion, driven by governments scrambling to meet net zero targets and big tech in search of green energy. Microsoft made headlines announcing plans to reopen Three Mile Island in Pennyslanvia, site of the worst nuclear accident in US history in the 1970s.
Analysts Wood Mackenzie predict an increase in global oil consumption of about 1.4 million barrels per day next year, though, as so often with the oil gas sector, that forecast is subject to considerably volatility. Demand could be cut by a third if the incoming Trump administration sparks a tariff war. And the supply side is shadowed by geopolitical uncertainty: a new government in Syria, a weakened Iran and ongoing war in Israel.
Demand for other resources looks somewhat more predictable. Battery storage metals are needed across the world, particular in the Middle East, as Saudi Arabia builds out solar and wind generation plants. Fundamentals for copper remain strong, reflected in competition amongst the majors for emerging ventures. And demand for blue hydrogen is surging: Wood Mackenzie predicts projects with capacity totalling more than 1.5 million tonnes per year are set to come online, securing the position of the US as the world’s leading producer of blue hydrogen.
All of these resources and more are well represented in our selection of companies to look out for in 2025.
Here, we look at how 10 Oil and gas companies faired in 2024 plus look ahead to their prospects in 2025. Also look out for our small cap mining picks of 2025 plus our 10 alternative companies to follow.
Ascent Resources
Ascent Resources (AIM:AST), a natural resources company with a long-time focus in eastern Europe, opened up new opportunities this year while continuing to pursue legal settlements both with the Republic of Slovenia and an estranged joint venture partner.
The company announced its maiden investment away from Slovenia in April, exposing shareholders to new growth in US onshore gas and helium processing through an initial investment into an operational and cash generative midstream business in the helium rich Paradox Basin.
The Lisbon Plant, held by GNG Partners, in which AST now has a $1m stake worth 10pc of the company, has helium purification and liquidation facilities fed by more than 500 miles of gas gathering pipeline spanning the Paradox Basin and flowing through the Four Corners region of America. Lisbon is the sole operating independent natural gas processing plant in the Basin, with access to helium rich gas sources of up to 7-8pc helium. The 60 MMcfd plant has a 1.1 MMscfpd processing capacity for helium, a 45 MMcfd cryogenic plant and 10,000 bpd fractionation train. The partners believe the plant can produce approximately 3.4pc of US liquid helium (1.7pc of the world’s liquid helium).
The plant has a liquification unit which has been in care and maintenance since around 2013 (when the liquified helium price was only $62.25/Mcf as compared to today’s $750-1,250/Mcf range). The partners plan to quickly recommission the unit to rapidly move back into premium markets of producing and sell liquified helium, and invest in iso-containers giving the business even greater price command.
Earlier this month AST widened its footprint in the US by acquiring a 49pc interest in American Helium LLC’s Utah and Colorado upstream acreage, prospective for 18.2 Bcf of natural gas (with up to 1pc helium), 2.79 MMbbls of oil and condensates and 2.34 MMboe of natural gas liquids of independently certified Proved Recoverable Reserves (1P). The Reserves have an estimated NPV10 of more than $80m.
AST is alert to further opportunities strategic collaboration agreement with Delta Energy, a private oil and gas company with access to multiple hydrocarbon opportunities.
In the meantime the company continues to vigorously pursue its legal cases, most notably with the Slovenian state. Prospective investors should carefully review the history of the case, but, in brief: AST has a legacy 75pc interest in the Petišovci gas project in north-eastern Slovenia, a joint venture with Slovenian partner Geoenergo, which holds the remaining 25pc. AST has invested €50m in the project since 2007, and has funded the project’s development in return for 90pc of the revenues until all costs are recovered. A test result of 8.8 MMscf has been recorded, and an independent volumetric assessment of the field estimated P50 contingent gas resources of 456 Bcf. The project has been partially implemented, with gas exported to Croatia from two wells, Pg-10 and Pg-11A. A second phase envisaged levering production from the field’s tight rock reservoir by means of hydraulic re-stimulation, opening the way for the re-entering and deepening of existing wells, and the construction of a processing plant through which gas would be injected into the Slovenian national gas network.
But those plans were shipwrecked when the Slovenian government amended the Republic’s mining law, imposing a sweeping ban on fracking. AST argues the decision was ‘politically motivated’. The field’s capacity to produce ‘was very significantly reduced’, effectively depriving the company of its right to produce gas in Slovenia and ‘destroying’ the value of its investments in the country’s energy sector.
AST has served the Republic with a notice of dispute of breaches under the UK-Slovenia bilateral investment treaty and the Energy Charter Treaty, an international agreement establishing a framework for cross-border cooperation in the energy industry. The arbitration proceedings include a monetary damages claim of more than €500m, although it is important to note – as AST itself acknowledges – that if the claim is successful ‘any amount actually received by the Company may be significantly lower’. AST has opened up the potential gain to shareholders, establishing a special purpose vehicle to distribute an entitlement to ‘the economic interest in 49pc of any net proceeds’.
A second dispute continues to grind on: an arbitration claim against venture partner Geoenergo in relation to differing interpretations of Petišovci’s baseline production profile, and the number of wells from which AST is entitled to receive revenues. AST is claiming 90pc of the proceeds received by Geoenergo from production in excess of the baseline production profile for all wells in the concession area. Geoenergo filed for insolvency before the claim could be settled. AST’s petition against the insolvency claims a settlement of €11m.
AST raised $1m earlier this year to fund its ongoing work. The company’s share price is currently 2p and its market cap £5.52m.
Block Energy
Block Energy (AIM:BLOE), Georgia’s largest independent oil and gas company, continues to pursue the farm-out of a multi-TCF gas resource, and define the potential of major carbon capture and storage (CCS) opportunity.
BLOE applies contemporary technology to realise the full potential of previously discovered Georgian fields, helping to meet the former Soviet republic’s strong domestic demand for energy, and, by means of the country’s extensive pipeline infrastructure, Europe’s increasingly urgent need for new sources of gas.
BLOE’s assets include a 100pc working interest in the onshore licence block XIB, historically Georgia’s most productive block, where, during the 1980s, production peaked at 67,000 bopd, cumulative production reaching 100 MMbbls and 80 MMbbls of oil. The remaining 2P reserves across block XIB are 64 MMboe, comprising 2P oil reserves of 36 MMbbls and 2P gas reserves of 28 MMboe. An internal technical study estimates gross unrisked 2C contingent resources of 200 MMbbls of oil.
The company also has a full working interest in the West Rustavi onshore oil and gas field spanning licence blocks XIB and XIF. The field has so far produced more than 75 Mbbls of light sweet crude and has 0.9 MMbbls of gross 2P oil reserves in the Middle Eocene. It also has 38 MMbbls of gross unrisked 2C contingent resources of oil, and, according to an Independent Engineering Report published earlier this year, 2.77 TCF of 2C Contingent Resources of gas.
BLOE is pursuing four concurrent projects designed to monetise low-cost, low-risk developments across the company’s assets to reinvest in delivering Rustavi’s huge undeveloped gas resource.
Project I is focused on developing oil production from the Middle Eocene reservoir of the West Rustavi/Krtsanisi field, which has an internal contingent resources estimate of 19.5 MMbbl 2C. Project II aims to redevelop the Middle Eocene reservoir of the Patardzeuli and Samgori fields, to which an internal Contingent Resource report ascribes Gross 2C Contingent Resources of 235 MMbbl. The company’s flagship Project III is focused on the undeveloped gas-bearing natural fracture system within the Lower Eocene and Upper Cretaceous reservoirs – each more than a kilometre thick – spanning the XIB and XIF blocks. BLOE has opened the Project to a farm-out campaign, with multiple interested parties currently in the data room. Project IV is focused on exploring the undiscovered potential of the company’s licences, so far leading to a farm-out agreement with Georgia Oil and Gas.
BLOE’s Block XIB field also hosts a significant Carbon Capture and Storage (CCS) opportunity with the potential to support a major net-zero CO2 industrial hub. 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.
Phase 2 studies for the opportunity, which got underway in November, include desktop and laboratory studies followed by a pilot injection scheme designed to achieve a monitoring and verification plan for carbon storage, opening the way for commercialisation. The technology proposed for the storage of CO2 in the Middle Eocene is similar to that successfully deployed by CarbFix in Iceland, and in an ongoing pilot by 44.01 in the United Arab Emirates. Pilot injection of CO2 into reservoir is targeted for Q1 2025.
While pursuing the big opportunities within its licences has BLOE has remained profitable and cashflow positive. The company’s most recent results, for the six months ended 30 June 2024, reported EBITDA of $645,000 (1H 2023: $491,000), profit of $2,000 (1H 2023: loss of $432,000), and cash of $656,000 (31 December 2023: $713,000). BLOE stated total production of 82.8 Mboe comprising 61.3 Mbbls of oil and 21.5 Mboe of gas (1H 2023: 96.4 Mboe, comprising 75.3 Mbbls of oil and 21.1 Mboe of gas). The company has extended its $2m loan facility (with existing lenders) to February 2026.
At the time of writing BLOE trades at 0.7p with a market cap of £4.86m.
Clean Power Hydrogen
UK-based green hydrogen technology and manufacturing company Clean Power Hydrogen (AIM:CPH2) took a major steps this year towards the commercialisation of its next-generation electrolyser technology with the completion of the product’s research and development phase.
CPH2 believes its IP-protected Membrane-Free Electrolyser (MFE) offers the cleanest method yet to produce hydrogen through water electrolysis – the delivery of hydrogen and pure oxygen as separate gases. Whereas conventional PEM and Alkaline electrolysers require Platinum Group Metals to serve as catalysts – or ‘membranes’ – for the separation process, the MFE is constructed from readily available materials which can be reused or recycled at the end of its operational life. CPH2’s process also promises to produce hydrogen more quickly than its competitors.
CPH2 says the MFE has ‘attracted considerable interest as a disruptor in the hydrogen production sector from large-scale liquefaction projects for heavy-duty transport, aviation, and wastewater purification.’ Hydrogen offers a green fuel for heavy transport, such as fuel-cell electric vehicles, trains, and shipping, for which lithium batteries are poorly suited.
CPH2 passed a major milestone in September when the MFE110, its first scaled membrane free electrolyser, successfully completed its Factory Acceptance Test (FAT), confirming the first customer acceptance and validation of CPH2’s scaled electrolyser technology. The test marks the end of the research and development phase on CPH2’s pathway and moves the company to focus on the commerciality phase, focused on the MFE220, CPH2’s flagship 1MW system.
The company passed other important landmarks earlier in the year. CPH2 was awarded three ISO certifications for Occupational Health and Safety (ISO 45001), Environmental Management Systems (ISO 14001) and Quality Management Systems (ISO 9001) in February, and in June achieved a CE marking for the process of making its electrolyser stacks.
CPH2’s commerciality phase has several components: delivery of the MFE220 customer contracts so far secured; activating the licensees and supporting them with finalised MFE220 designs, instructions, procedures, training and procurement support; continued technology and product improvement; and growing the company’s commercial pipeline. Deliverables through the commerciality phase will be focused on revenue generation with commercial MFE electrolysers working on customer sites, and licensees commencing manufacturing.
An operations update published in November summarised CPH2’s current status. The company has contracts for the sale of four MFE220 units, with one unit to be deployed to Belfast for Northern Ireland Water, two further units to Fabrum Solutions Limited in New Zealand, and one unit to Lisheen H2 Energy Park Limited, which trades under the name Hidrigin, in Ireland. In addition, CPH2 has licence agreements in place with Fabrum, Hidrigin and Kenera Energy Solutions Limited, a business unit within leading drilling, engineering and technology company, KCA Deutag, which enable CPH2 to rapidly scale up to meet demand for its MFE technology across multiple geographies.
The company’s short-term activities are aimed at deploying the initial MFE110 unit to NIW and completing the design and optimisation of the MFE220. The first MFE220 electrolyser will be built for NIW, followed by the Hidrigin unit and the two units for Fabrum. During the next 18 months the company also intends to fully activate its various licensees and build out its commercial team. These activities are to prepare it for increasing its manufacturing capability in late 2026 as it moves into the scale phase of the commercialisation pathway.
CPH2 raised £6.1m earlier this month to fund implementation of the strategy. CPH2’s most recent results, for the six months ended 30 June 2024, stated a loss of £2.3m for the period ended 30 June 2024 (H1 2023: £1.6m), mainly due to the higher development costs incurred in supporting the MFE110. Cash stood at £4m.
CPH2 currently trades at 8p with a market cap of £21.6m.
Georgina Energy
Georgina Energy (LON:GEX) is developing a set of assets highly prospective for helium and hydrogen in Northern and Western Australia’s vast Amadeus and Officer Basins.
The company, which joined the LSE Main Market in July, holds a 100pc interest in the Hussar Prospect, and has an option to earn a 75pc interest in the Mount Winter Prospect, with the potential to reach 90pc. Together the two ventures cover 3,951 km2 in Western Australia, a region with proven gas potential.
The Hussar Prospect hosts unrisked 2U Prospective (Recoverable) Resources of some 155 BCFG (155 million MCF) of helium, approximately 173 BCFG (173 million MCF) of hydrogen, and around 1.75 TCFGE (Trillion Cubic Feet Equivalent) of hydrocarbons, making it one of the most potentially lucrative resource basins in the Asia Pacific region.
The Mount Winter Prospect hosts unrisked 2U Prospective (Recoverable) Resources of circa 148 BCFG (148 million MCF) of helium, around 135 BCFG (135 million MCF) of hydrogen, and some 1.22 TCFGE (Trillion Cubic Feet Equivalent) of hydrocarbons. The Mt Winter-1 well was drilled in 1982 to a total depth of 2,650 metres, but did not penetrate the subsalt Heavitree Formation in the region’s Amadeus Basin, the then targeted reservoir, reaching total depth in salt just above it. When penetrated by historic drilling, the Heavitree Formation has flowed gases with unusually high concentrations of both hydrogen and helium, up to 11pc hydrogen and 9pc helium, among the top 5pc of concentrations so far discovered anywhere in the world. GEX is targeting the analogous subsalt Townsend Formation, also in the Amadeus Basin.The Dukas 1 well recently drilled by Santos in the Amadeus Basin, close to the Heavitree Formation, has reported high concentrations of helium and hydrogen.
GEX has an off-take MoU applicable to both Mt Winter and Hussar with Harlequin Energy, although the non-exclusive agreement permits GEX to hold discussions with other potential parties. GEX raised a gross £5m on IPO to support its current programme of work, £2.5m contributed by directors.
By mid-August GEX was ready to announce details of its Well Re-development Programme, which plans to extend the original well drilled in 1982 from 2040 metres to 3400 total depth metres, seeking to penetrate the targeted Townsend Formation.
A November operations update reported the company was completing the required process for engineering design, HSE and environmental approvals and meeting its obligations under the Native Title Land Access agreement. GEX has advanced negotiations to secure the consent from traditional aboriginal landowners necessary to farm-in to the 75pc interest in the Mt Winter Prospect, and has been advised that ratification of traditional owners approval of the granting process for Mt Winter project is ‘anticipated to complete in December 2024’.
GEX continues to advance a comprehensive conceptual scoping study with an independent international consultancy for a large-scale separation plant for hydrogen, helium and natural gas products at or near the Hussar site. The study will include capital and operating costs estimates and concept estimates of the revenue from gases produced at the wellhead to be sold to third parties under the offtake agreement. It is anticipated first draft of the scoping study will be delivered in January 2025.
While pressing ahead with work at Hussar and Mt Winter, GEX has identified additional high potential re-entry and development targets. The company is evaluating 10 priority re-entry targets from a possible 168 plugged and abandoned wells within its licences ‘with potential to recover material volumes of helium, hydrogen and natural gas’. The top two candidates for re-entry will be determined subject to clarification of ownership rights.
GEX has executed a confidentiality agreement ‘with a well-established Australian-listed Oil & Gas exploration and production company, with Australian onshore gas production assets’, in relation to its well re-entry programme. The agreement will evaluate the potential acquisition or farm-out of certain permits between the parties, subject to formal agreements. A further confidentiality agreement with ‘a second well-established Australian oil and gas production and exploration company’ was announced in November.
GEX currently trades at 8p, with a market cap of £7m.
Mendell Helium
Mendell Helium (AQSE:MDH) took a sharp change of direction this summer when the former plant-based health and wellness manufacturer and e-commerce business, then known as Voyager, entered into an option agreement to acquire the entire issued share capital of M3 Helium, a Kansas-based helium producer. MDH raised £864,468 in June conditional on exercising the option, for which the date is provisionally set for 31 March 2025.
M3 Helium operates from two locations. The Hugoton gas field, located primarily in southwestern Kansas, western Oklahoma, and the Texas panhandle, is one of the largest natural gas fields in North America. Covering around 31,080 square kilometres, the field has made a significant contribution to North America’s natural gas supply since its discovery in 1927. It has produced more than 30 trillion cubic feet of natural gas, with substantial quantities of natural gas liquids and helium.
M3 Helium’s North Play potentially extends to 250 sections with recoverable gas, with each section being approximately 640 acres. Production to date has indicated a helium content of 1.25pc. Analogous wells drilled by other operators within the North Play have averaged over 0.44 bcfg per well. With four wells per section, M3 Helium estimates a potential of up to 440 bcfg of recoverable gas across the entire area, and potential recoverable helium of over 5.5 Bcf.
M3 Helium has a direct path to commercial sale through a pipeline and Scout Energy’s Jayhawk helium plant in Kansas (which processes 4pc of the world’s helium). Helium is being sold at the Jayhawk helium plant at $550 per Mcf. An independent resource report published earlier this year for the field’s contingent resources offered a best estimate for natural gas of 787.7 Bcf, and 16,513 Bcf helium, and a high estimate for gas of 1,068.9 Bcf and helium of 23,038.4 Bcf.
The second prospect, Fort Dodge, in Ford County, Kansas, is currently focused on the producing well Rost 1-26. Helium concentrations at Fort Dodge of 4.6pc have so far been higher than the North Play, though comparable infrastructure does not exist: M3 Helium will utilise its modular hybrid plant to process and enrich produced helium, and purified helium is expected to be collected on site by customers with terms. The Fort Dodge lease allows for two additional wells to be drilled.
Announcing the option MDH said: ‘M3 Helium offers several significant benefits. With proven geology in one of the USA’s most recognised resources postcodes, the company is already producing helium and, even more importantly, has access to infrastructure to transport, process and bring it to market. M3 has established its production credentials and we know the likely cost of new wells. We can apply funding raised to develop and extend M3’s asset base with the clear goal of accelerating and increasing helium production.’
A November update expanded on M3 Helium’s three potential ‘company maker’ projects. The first is a farm in agreement with Scout Energy Partners covering 161,280 acres of the Hugoton field, including a minimum target of 25 new wells, although M3 Helium estimates a potential 100 to 200 well opportunity within this acreage. All production from new wells will be delivered to Scout Energy’s gathering system and the Jayhawk processing facility.
The second, Fort Dodge’s Rost 1-26 well, has tested extremely positively: testing in July indicates a gas composition of 5.1pc helium, and a well pressure of 302.7 psi. The flow rate was measured at 47,100 cubic feet per day (47.1 Mcfd), a result achieved despite brine levels of 1,058 feet over the perforations.
The third, Hugoton’s Nilson well, has responded impressively to fracking operations undertaken in September. Post-frack production results typically spike before declining, but Nilson’s production has steadlily risen by a little under 1 Mcf per day at around one cubic foot every two minutes. Earlier this month MDH reported that Nilson’s production had passed 100 Mcf/day and was continuing to rise by more than 2 Mcf per day. Nilson is now in the top 1pc of producing wells (by volume) in the Hugoton.
Mendell Helium currently trades at 2.5p with a market cap of £1.1m.
Pantheon Resources
Pantheon Resources (AIM:PANR) has made robust progress this year defining the promise of its fully owned Ahpun and Kodiak fields in the State of Alaska.
Independently certified best estimate contingent recoverable resources attributable to the projects currently total some 1.6 billion barrels of Alaska North Slope (ANS) crude and 6.6 Tcf (trillion cubic feet) of associated natural gas. PANR is working to demonstrate sustainable market recognition of a value of $5-$10 per bbl of recoverable resources by end of 2028, based on bringing the Aphun field to a Final Investment Decision (FID) and producing into the TAPS main oil line. PANR’s natural gas would be produced into a proposed 807 mile pipeline from the North Slope to Alaska from 2029, in accordance with a Gas Sales Precedent Agreement (GSPA) signed with the Alaska Gasline Development Corporation (AGDC).
On achieving financial self-sufficiency PANR plans to move to a FID on the Kodiak field, targeted for late 2028 or early 2029. The fields are proximate to existing roads and pipelines, allowing for shorter development timeframes and a lower pre-cashflow funding requirement than is typical in Alaska. Low CO2 content of associated gas would allow export into the planned natural gas pipeline without significant pre-treatment
PANR has moved ahead on a number of fronts over the past year. A set of Independent Expert Reports (IERs) provided independent validation of its contingent resources base. Best estimates of Kodiak’s contingent recoverable resources now indicate 1.2 billion barrels of ANS crude and 5.4 Tcf, a 25pc increase over 2023. Two further reports, covering the Alkaid horizon and additional topset horizons, indicate strong contingent resources in oil, natural gas, and natural gas liquids (NGLs) supported by favourable economic models. The base case for the Alkaid horizon includes 79 MMbbl of ANS crude and 424 Bcf of gas, with the NPV10 estimated to be $0.2-0.5bn. Analysis of the broader Ahpun field, focusing specifically on the western topsets, presents similarly promising estimates, the best estimate (2C) including 282 MMbbl of ANS crude and 804 Bcf of gas. Given current assumptions, the NPV10 for the 2C contingent resources is approximately $1.7bn, based on an $80 per barrel price for ANS crude.
In the coming year PANR intends to complete the basis of design for the Ahpun development, complete the studies to allow submission of documents needed for the regulatory approvals, and – subject to funding availability – plan for two appraisal wells to firm up oil, NGL and natural gas resource estimates, and narrow the range of prospective helium resources contained in the Kodiak field’s associated gas.
PANR has continued to work with the AGDC and the State of Alaska to accelerate development of Alaska LNG Project through the GSPA to address the projected supply shortfall of natural gas in the state in the next few years. Phase 1 of the Project focuses on construction of the gas pipeline, allowing gas transportation as early as 2029. The GSPA commits PANR to supply up to 500 MMcfd of natural gas at a maximum base price of $1 per MMBtu.
Another significant milestone was last month’s spudding of the Aphun field’s Megrez-1 well which has potential to add another 40pc to the overall resource base. Before drilling, PANR estimated the well to have a 69pc geological chance of success of encountering a 2U Prospective Resources of 609 million barrels of ANS crude and 3.3 Tcf of natural gas.
Earlier this month PANR said the Megrez-1 well had discovered a large light liquids hydrocarbon column. Preliminary analysis indicates the well has intersected multiple horizons containing light liquid hydrocarbons over some 2,060ft of measured depth. Multiple reservoirs were contained in this overall section consisting of interbedded sands and shales. Over the coming weeks and months, the company will be evaluating a large data set gathered from the well, with preliminary analysis estimated to be completed during February 2025. These analyses will be used to determine more detailed reservoir characteristics and begin the planned extensive long term production testing programme.
PANR’s most recent set of results reported cash and cash equivalents of $23.7m, which is currently funding the ongoing Megrez-1 well operations. The company’s strong progress has pushed its share price higher this year, to 26.23p at the time of writing, taking its market cap to £302m.
Prospex Energy
Prospex Energy (AIM:PXEN) has made significant progress this year in extending its scope beyond long-term interests in two producing European gas plants, acquiring a new interest in Spain and exploring prospects in Poland.
PXEN’s most recent results, for the six months ended 30 June 2024, reported solid production at the Italian and Spanish plants in which it is invested.
Production at the Selva Malvezzi gas concession, in which the company has a 37pc working interest, yielded 13,220,652 scm during the period, with €1,560,893 of gas sales attributable to PXEN. PXEN’s joint venture partner confirmed potential for a new seismic acquisition programme over the licence area following the successful reprocessing of the existing 2D seismic lines in the production concession.
There is also the prospect of expansion following the Italian Ministry of Environment and Energy Security’s annulment of Italy’s planning laws, which had previously limited the extent of hydrocarbon prospecting, exploration and production in the country. PXEN said the change was ‘an important sign of the current Government’s commitment to promote and enable more domestic gas production to address the serious energy security challenges which Italy and more broadly Europe, are facing’. The partners have filed four new drilling applications with the Ministry.
PXEN has a 49.9pc interest in the El Romeral gas production concessions in Andalucía, southern Spain, where income from electricity generated during the period was a gross €398,000, with €199,000 attributed to PXEN’s share. Again, there is the prospect of growth, the concession partners advancing the permitting of five new wells to bring the utilised electricity production capacity of the gas-to-power plant to 100pc (currently at 33pc). They are also continuing to evaluate the possibility of expanding the capability of the El Romeral assets to sell gas directly to the national grid, as well as expanded solar power generation.
In August PXEN increased its interest in Spain acquiring, with the help of £4.2m fundraise, a 7.5pc stake in HEYCO Energy Iberia (HEI), which has majority ownership in the Viura gas field in northern Spain. PXEN is earning into the stake by funding 15pc of the cost of HEI’s Viura development programme. Last month the partners reported that flow testing at the site’s Viura-1B development well had reached its revised targeted Total Depth of 4,500 metres. The well is currently being connected to the existing gas processing facilities on-site with production income expected before year end. Earlier this month HEI reported that flow testing had exceeded expectations, achieving rates up to 500,000 scm/d which 72,000 scm/d net to PXEN.
PXEN opened up another new front in October, qualifying to apply for onshore open acreage hydrocarbon exploration licences in Poland. The company says it hopes to acquire prospective blocks meeting its strict investment criteria, namely, ‘areas which have proven gas production, high potential prospectivity in the targeted geological horizons, high potential for new reserves to be unlocked and can be brought onstream within two to three years’.
PXEN’s interim results reported cash and cash equivalents of £10,991 (30 June 2023: £395,202), and a £275,120 loss after taxation from continuing operations (H1 2023 loss: £888,473). The company passed an important milestone in repaying all outstanding interest-bearing debt outstanding, and accrued interest, leaving it ‘well positioned for growth, cash generative with no debt’.
The company’s share price has mirrored its progress in opening up new possibilities this year, currently trading at 6.91p, up 40pc over the last 12 months, taking PXEN’s market cap to £27.82m.
Rockhopper Exploration
Rockhopper Exploration (AIM:RKH) moves into 2025 in its strongest position for some time, with a financial investment decision nearing for the Sea Lion Project off the Falkland Islands, and flush with compensation awarded for a long running dispute with the Italian government.
RKH is the largest acreage holder in the Falkland Islands, holding a 35pc interest in licences PL032 – which contains the Sea Lion field – and PL033 in the North Falkland Basin, a 35pc interest in the Basin’s PL004A, and a fully owned operating interest in the PL011, PL012 and PL014 licences in the South and East Falkland Basin.
RKH believes the Sea Lion field and its associated prospects within the North Falkland Basin represent a hugely important and valuable strategic asset for the Falkland Islands and the UK. The field’s operator, Navitas, has now completed the Environmental Impact Study (EIS) consultation phase, and elaborated a highly advanced field development plan.
An independent report confirms that the field’s first 312 MMbbls (on a 2C basis) has a gross NPV 10 of over $4bn on a pre-tax, post-Falkland Islands Government (FIG) royalty at $77 Brent. The life of field cash breakeven is currently estimated to be $25/bbl making the project financially attractive at a range of commodity prices. RKH and Navitas are currently working to secure a financing package for the opening phase of the Sea Lion Project as they move towards a FID. Navitas published an updated independent resource report for the North Falkland Basin last month. Gross 2C recoverable oil resources have increased from 791 MMbbls to 917 MMbbls, and 2.1 TCF of 2C recoverable gas resources has been certified.
Navitas also reported that the FIG has requested no further public consultation on the EIS. The FID is now scheduled for mid 2025 and first oil for Q4 2027. The development concept envisages three phases delivering 532 MMbbls. Phase 1 and 2 production would peak at 55,000 bbls/day, increasing up to 120,000 bbls/day once all three phases have been developed.
RKH’s other big news was the award of €19m compensation for Ombrina Mare oil field blocked by the Italian government in 2016. In August 2022 the International Centre for Settlement of Investment Disputes arbitration panel unanimously agreed that Italy had breached its obligations under the Energy Charter Treaty, and awarded Rockhopper compensation of €190m plus interest. The money paid to RKH represents the first payment of three. The other two are on hold pending the outcome of the Italian Republic’s appeal against the decision. RKH believes ‘it has a strong chance of prevailing over Italy in their annulment attempt’. While there is no formal timetable for resolution, RKH expects a decision in H1 2025. RKH has put in place a €4m insurance policy against the possibility that the Italian government might succeed in having the award annulled.
Whilst RKH no longer produces any oil or gas in Italy, it does hold interests in two licences with material upside. The AC19 licence, in which RKH has a 15pc working interest, comprises two large discovered gas fields with a prospect on trend. Italy’s oil and gas regulations, which currently do not allow work to begin, are presently under review. Monte Grosso, in which RKH has a 23pc working interest, is Europe’s largest onshore undrilled oil prospect located on trend with Val d’Agri and Tempa Rossa. It is currently subject to the same regulations.
RKH’s interim results for the six months ended 30 June 2024 reported a profit after tax of $16.5m (H1 2023: loss of US$2.6m). Following the Ombrina Mare award the company ended the period with approximately $27.8m in cash and term deposits.
RKH is up 90pc this year, currently trading at 20.8p with a market cap of £135m.
Tower Resources
Tower Resources (AIM:TRP), pursuing a portfolio of oil and opportunities in Africa, is now close to concluding an agreement for the farm-out of its highly prospective Cameroon licence, and has made progress in clarifying the potential of its interests in Namibia and South Africa.
TRP’s current focus is on advancing its operations in Cameroon to deliver cash flow through short-cycle development and rapid production with long term upside, and de-risking exploration licenses through acquiring 3D seismic data in the emerging oil and gas provinces of Namibia and South Africa, where world-class discoveries have recently been made
TRP has a 100pc interest in the shallow-water Thali Production Sharing Contract covering 119.2 km2 of the Rio del Rey basin, offshore Cameroon. The basin has to date produced more than one 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 – Rumpi-1, Njonji-1 and Njonji-2 – have already been drilled on the Block. The latest company estimate of risked PMean recoverable resources is now 35.4 million barrels.
TRP’s second major prospect is a 80pc operated interest in Blocks 1910A, 1911 and 1912B (PEL 96) covering 23,297 km2 of the northern Walvis Basin and Dolphin Graben offshore Namibia, an under-explored region in which recent drilling results have proven the presence of a working oil-prone petroleum system, along with good quality turbidite and carbonate reservoirs. Recent licensing activity in the area has included the farm-in of Chevron to the PEL 82 license to the south.
The company also has a 50pc interest in the Algoa-Gamtoos licence, offshore South Africa. The 9,369 km2 acreage straddles the Algoa and Gamtoos basins on the shelf, and the outboard slope edge of the South Outeniqua Basin, where TRP made its Brulpadda and Luiperd discoveries in Blocks 11B/12B.
TRP reported positive developments across all of its licenses in 2024, notably in Cameroon, where it is close finalising financing for the development of the NJOM-3 well, having received a proposal for the financing of the well via a farm-out of a minority position, ‘from a substantial upstream company with existing production’. Spudding has now been targeted for ‘early in 2025’.
An October update reported that the company had received an updated proposal from the interested party, which would provide more than $15m funding for the Thali PSC work programme, including drilling the NJOM-3 well in return for a minority interest in the PSC, with TRP remaining as the operator. Importantly, the proposal does not contain any financing contingency as the counterparty has available funds, and a portion of the funding would be secured by a bank guarantee. TRP is currently reviewing the current proposal and clarifying its terms where appropriate, and expects to work on detailed contracts with this partner, or one of the other parties interested in the licence, ‘over the coming weeks’.
TRP has raised £1,188,500 to ‘remove any funding pressure while the Company concludes its Cameroon farm-out negotiations, and to allow the Company to keep operational preparations for drilling the NJOM-3 well moving forward without delay’.
In Namibia TRP spent the first six months of 2024 analysing more than 20,000 kms of 2D seismic data held over the PEL96 license area to identify the most promising structures along the likely oil migration paths identified by basin modelling and the oil seep analysis. The company has found ‘interesting structures in several areas of what is a very large license area, covering nearly 24,000 kms at present’. Rather than acquiring new 3D seismic over such a large area the company is reprocessing some of its existing 2D data to decide on which structures to focus on.
TRP said that although the company is ‘not formally seeking to farm out our license interest in Namibia, as we consider it somewhat premature given the current stage of work’, it is pleased to have ‘received unsolicited interest in the license and are sharing data with parties who wish to discuss it with us even at this early stage.’
Regarding South Africa, the company has been in discussions for some time with a potential partner for its Algoa Gamtoos license. This has ‘now reached the stage where draft documents are being prepared’.
TRP currently trades at 0.032p with a market cap of £8.44m.
Union Jack Oil
Union Jack Oil (AIM:UJO) continues to develop its flagship Wressle project at Wressle and pursue other UK opportunities, but has opened a promising new front with a rapidly evolving portfolio in the US.
UJO has a 40pc interest in the PEDL180 and PEDL182 fields at the Wressle Development in Lincolnshire, on the western margin of the Humber Basin. Following a highly successful workover three years ago Wressle has established itself as the company’s headline project, generating revenues net to UJO of $20m. Since then more than 650,000 barrels of high-quality oil have been produced and sold from Wressle, producing on constrained flow an average of 472 bbls of oil per day (188 bbls net to UJO) sold at a price of $83.46.
UJO believes that ‘within Wressle, where planning consent is in place, there remains significant material upside which will support the Company with revenues for at least another decade’. The most recent CPR indicated a 263pc increase in 2P Reserves to gross 2,373 Mboe. The joint venture partners are currently seeking planning content from North Lincolnshire Council (NLC) to support the next phase of the Wressle field development, including the drilling of two new wells, an upgrade of production facilities, and installation of a 600-metre underground gas pipeline linking the Wressle production site to the national gas grid.
Initial planning permission was granted in September but has been formally rescinded on the basis that NLC omitted to consider the likely Scope 3 greenhouse gas emissions associated with the project. Operator Egdon Resources will now provide the Council with an analysis of Scope 3 emissions for the proposed development conducted by an independent third-party specialist company and request a new EIA screening opinion.
UJO’s second major UK interest is a 16.665pc stake in the PEDL183 field at the West Newton Development, onshore north of the River Humber. The West Newton A-2 and West Newton B-1Z drilling programmes have yielded substantial hydrocarbon discoveries within the Kirkham Abbey formation indicating gross unrisked technically recoverable sales volumes of 2C gas 197.6 Bcf. UJO says commercial gas production could be brought to market within months of a successful production test, resulting in a materially reduced capital investment programme, providing significant early cash flow, whilst additional activity is carried out on the further development of the West Newton project.
Other significant UK interests include a 55pc holding in the PEDL005(R) licence in the Keddington oilfield located along the highly prospective East Barkwith Ridge. A technical review has confirmed that there remains an undrained oil resource located on the eastern side of the Keddington field. Modelling indicates that infill drilling is forecast to improve recovery from the Keddington field by between 113,000 to 183,000 barrels of oil, depending on the reservoir permeability model selected and the combination of infill targets.
UJO has a 45pc interest in the PEDL253 licence at Biscathorpe, situated within the proven hydrocarbon fairway of the South Humber Basin and is on-trend with the Keddington oilfield and the Saltfleetby gasfield. The prospect has a gross Mean Prospective Resource of 2.55 MMbbl, with overlying Basal Westphalian Sandstone offering potential to add gross Mean Prospective Resources of 3.95 MMbbl. The project remains on hold subject to planning permission. The company also has a 50pc stake in the PEDL241 field in North Kelsey, a conventional oil exploration prospect on trend with the Wressle oilfield with gross Prospective Resources ranging from 4.66 (P90) to 8.47 (P10) MMbbl.
Frustrated with planning issues and the Energy Profit Levy UJO late last year embarked on a US expansion plan ‘to seek growth opportunities in jurisdictions with more sympathetic views towards the hydrocarbon industry, without compromising global environmental objectives and the aim of achieving net zero by 2050.’ The company has so far acquired ‘six quality Royalty packages’, all brokered by the Company’s Oklahoma based agent and adviser, Reach, located in the Permian Basin and Eagle Ford Shale, Texas and Bakken Shale, North Dakota, USA, all operated by major producers. The proxy interests in 165 wells have so far delivered a 20pc return on a capital investment of approximately $1m.
Reach has also offered UJO an opportunity to access a wider inventory of drill-ready prospects and projects in Oklahoma, notably a 45pc interest the Andrews field located in Seminole County, Oklahoma, focused on the 1-17 and 2-17 wells drilled in summer this year. The Andrews 1-17 well has so far produced 7,052 barrels of high-oil and 6,407,000 cubic feet of gas, and the Andrews 2-17 well 1,014 barrels of oil and 3,656,000 cubic feet of gas.
UJO’s most recent results, to 30 June 2024, reported a net profit of £788,996 (2023: £572,263), including oil revenues of £2,338,710 (2023: £3,584,866). The company continues to be debt free.
UJO currently trades at 10p with a market cap of £10.66m.
