10 Oil and Gas Companies to follow in 2024
The confusion of factors that determined oil and gas prices this year seems likely to continue in 2024.
A confluence of conditions drove prices higher in 2022, notably the outbreak of war in Ukraine, restrained investment by US shale companies, and Opec price cuts to offset weaker demand from China.
This year continued Opec cuts and renewed conflict in the Middle East pushed the oil price to a peak of $95 a barrel, but it has fallen back under $80 in Q4 as continued high production has coincided with a weaker economic climate. Cartel cuts have been counterbalanced by greater US output, and China’s weak pandemic recovery has continued to weigh on demand.
Opec’s intentions are uncertain going into 2024. Saudi output has – so far – been restrained, but other members, including Russia, Iran, Venezuela, Iraq and Nigeria have been stepping up production. Supply may, however, be threatened by further unrest in the Middle East, signalled by recent interruptions of trade through the Strait of Hormuz. And an upturn in global economic conditions would push demand higher. Goldman Sachs predicts GDP growth of 2.6pc in 2024. Analyst’s predictions are mixed, but on average estimate a price of $88 for Brent crude in 2024.
Here we look at how 10 oil and gas small caps faired in 2023, and look ahead to their prospects in 2024.
Afrenta
Afentra (AIM:AET) has spent big this year to consolidate its presence in Angola and Somaliland. But a 20pc spike in the company’s share price over the past six months indicates market optimism that the investment will be worth it.
Angola is one of the largest oil producers in Africa with current production of 1.1 million bbl/d from deepwater, shallow water and onshore dating back to 1956: global research and consultancy business Wood Mackenzie estimates some 15 billion barrels of oil and gas reserves and resources.
Following this year’s transactions AET has significant stakes in three Angolan assets. The company has a 30pc interest in Block 3/05 located in the Lower Congo Basin, consisting of eight mature producing fields with more than 100 wells, 40 in production. The field has gross 2P reserves of 110 MMbbls and 2C resources of 44 MMbbls. In H1 2023 average daily gross production was some 18,000 bbl/d with an exit rate for June 2023 of approximately 19,100 bbl/d following well intervention activities carried out during Q2 2023. Additional well interventions are ongoing to enable further production rate increments.
AET has a 21.33pc interest in the adjacent Block 3/05A containing the undeveloped discoveries Punja, Caco and Gazela with an estimated in place resource of 0.3 billion barrels and 2C resources of 33 MMbbls. Assessments are underway to define an optimal development framework that would make optimal of Block 3/05 facilities and infrastructure. A well test earlier this year yielded 1,200 bbl/d.
The company has a 40pc interest in Block 23, a 5,000 km2 exploration and appraisal block located in the Kwanza basin in water depths from 600 to 1,600 metres with a working petroleum system. The field contains the Azul oil discovery, the first deepwater pre-salt find in the Kwanza basin, with oil in place of approximately 150 MMbbls and flow rates of some 3,000 to 4,000 bbl/d of light oil.
AET’s interests in Somaliland are focused on the country’s undrilled onshore rift basin, in the form of a 34pc stake in the 22,840 km2 Odewayne Block. Both the operator and AET have confirmed the presence of trace oil in a sample taken at the water well drilled by the Somali state. The likely source for the oil is a Mesozoic age source rock which fits with an Upper Jurassic source rock. AET is working with the operator to develop a work programme to further evaluate the licence’s prospectivity.
AET’s H1 2023 results reported that incremental acquisitions of interests in Block 3/05 (4pc) and Block 3/05A (5.33pc) had been completed through a $27m net upfront consideration funded through $18.9m in agreed debt facilities and $8.1m cash. Acquisition of further interests in Block 3/05 (12pc) and Block 3/05A (16pc) had been completed for a firm consideration of $48.5m and contingent payments of up to $36m. Both purchases qualified as reserve takeovers, requiring the suspension of trading in AET from July 2023. The company reported cash resources as at 30 June 2023 of $15.7m, and debt drawdowns at two facilities of $12.8m and $9.1m. Its loss after tax was $3.9m (H1 2022: $2.9m).
AET reported its investments were beginning to bear fruit in August, selling its first cargo of 300,000 bbls of crude oil, generating net pre-tax sales of $26.4m. The company looks forward to ending the year having completed all three transactions, giving it material proven reserves, robust production and cash flow, and significant upside potential from a high-quality asset base. Light well intervention and water injection programmes have so far yielded positive results. Market optimism regarding AET’s prospects for the new year are reflected in its share price of 35p, up 33pc this year, taking the company’s market cap to £79.5m.
Ascent Resources
Ascent Resources (AIM:AST), an oil and gas exploration and production company focused on onshore European production, has this year continued to disentangle contractural disputes that have checked the development of its Slovenian operations, but has also widened its growth strategy.
AST has a 75pc interest in the Petišovci gas project in north-eastern Slovenia, a joint venture with Slovenian partner Geoenergo, which holds the remaining 25pc. AST, which has invested €50m in the project since 2007, funds project development in return for 90pc of the revenues until all costs are recovered. A 8.8 MMscf test result has been recorded, and an independent volumetric assessment of the field estimated P50 contingent gas resources of 456 Bcf.
AST’s strategy to unlock the project’s full potential has two phases. The first has been executed: the export of untreated gas to Croatia from two wells, Pg-10 and Pg-11A. The second envisages levering increased production from the field’s tight rock reservoir through hydraulic re-stimulation. This would allow the re-entering and deepening of existing wells, and the construction of a processing plant to treat the gas for injection into the Slovenian national gas network, the channel most likely to secure the highest price. Implementation of the second phase stalled when the Slovenian government voted to amend the Republic’s mining law to impose a blanket ban on fracking. AST is engaged in arbitration proceedings against the Republic, submitting a monetary damages claim of more than €500m, but notes that if the claim is successful ‘any amount actually received by the Company may be significantly lower’.
AST has made swifter progress towards resolving a second dispute, an arbitration claim against joint venture partner Geoenergo in relation to the parties’ respective interpretations of Petišovci’s baseline production profile, and the number of wells from which AST is entitled to receive revenues. Last month a Tribunal binding interim decision confirmed AST’s entitlement to proceeds above the baseline production profile from all wells in the concession area, stating that the company is entitled to a 90pc share of the hydrocarbons produced above the baseline production profile from all of the wells on the concession area. AST estimates the proceeds could be more than €8m.
Amidst the disputes gas production at Petišovci has continued, AST’s H1 results reporting 645,140 scm produced by the PG-10 and PG-11A wells. Revenue for the period was £1.36m, against £581,000 for the full year 2022, with the company reporting a cash balance of £242,000.
AST’s growth strategy extends beyond Slovenia, the company evaluating opportunities to grow in onshore oil and gas, oil services, mining and ESG Metals. In October it entered into a Strategic Collaboration Agreement with investment company MBD Partners SA, owned by a high net worth natural resource investor with an existing portfolio of natural resource investments. Under the agreement the partners ‘will review and evaluate business development opportunities with a view to positioning the Company to secure cash flows and material upside in the natural resources space.’
AST’s price is up 10pc over the past six months as the company has worked through its legal issues and set out its plans for the future. It currently trades at 3.8p with a market cap of £8m.
Beacon Energy
Beacon Energy (AIM:BCE) has intrigued the market this year with the prospect of strong flow rates from a newly purchased set of assets onshore Germany.
BCE acquired Rhein Petroleum last year, raising £6m to launch a summer work programme focused on the SCHB-2(2.) development well on the Erfelden field. By September the company was able to publish a highly positive update reporting that drilling had encountered an ‘excellent’ 34-metre gross interval containing 28 metres of oil-bearing net reservoirs in the Pechelbronner-Schichten (PBS) sandstones within the Stockstadt Mitte segment of the Erfelden field. These oil-bearing reservoirs were encountered approximately 25 metres higher and 10 metres thicker than prognosis, with porosities averaging 18pc in the Lower PBS and 21pc in the Upper PBS, with no water-bearing sands.
With the metrics ‘above or at the top of the range of pre-drill expectations’ BCE was able to predict ‘a material upgrade to recoverable reserves in Stockstadt Mitte and a de-risking of 2.4 million barrels of Contingent Resources already ascribed to Schwarzbach South’, and the possibility of ‘an initial production rate in excess of 900 barrels of oil per day’, in line with rates of production achieved on historic wells in the area. At those flow rates the company ‘would expect to deliver operating cash flows in excess of $1.5m per month (assuming $80/bbl Brent)’.
BCE went on to raise £4.3m on the back of the results, allowing it to establish flow rates through a clean-up of the wellbore in preparation for the installation of an Electrical Submersible Pump. And a November update upgraded the Erfelden field’s reserves, from a pre-drill Best Estimate of 3.8 MMbbls to 7.2 MMbbls (with a Low Case of 4.72 MMbbls and High Case of 10.20 MMbbls.
BCE’s value rose sharply through the autumn, but the market’s optimism was punctured earlier this month when an operations update reported that production had stabilised as a rate of approximately 40 bopd. The company said the ‘low production rate indicates that the reservoir near the wellbore has been invaded with drilling fluids which are restricting flow rates’ and that this ‘is not uncommon in situations where hole stability issues have occurred during drilling due to the use of high-density drilling fluids to stabilise the hole.’ BCE will ‘undertake industry-standard well stimulation in the fourth week of January 2024, which is expected to improve production.’ Some 1,600 barrels of oil have so far been produced, and the company ‘continues to estimate that given the excellent reservoir properties and the light oil recovered, and in the absence of an invasion zone which restricts flowrate, the SCHB 2(2.) well could achieve production in the region of 900 bopd.’
Time will tell. After spiking at 0.27p in September BCE’s shares have fallen back to 0.09p at the time of writing, taking the company’s market cap to £11.7m. Given the company’s promising assets, that decline could be temporary.
Block Energy
Block Energy (AIM:BLOE) has continued to rollout and refine a four project strategy designed to unlock the value of a now substantial set of assets in Georgia.
The company’s primary focus this year has been on Project I, a multi-well programme to develop the Middle Eocene reservoir of the West Rustavi/Krtsanisi field to which internal estimates ascribe 27.5 MMbbls of 3C Contingent Resources. Now BLOE is shifting the emphasis of its strategy, seeking to achieve a ‘quantum leap’ through focus on the long term prize defined by Project III, an undeveloped gas-bearing natural fracture system within the Lower Eocene, Palaeocene and Upper Cretaceous reservoirs that internal estimates indicate may hold a multi-TCF contingent gas resource.
Since listing five years ago BLOE has achieved its initial aim of becoming Georgia’s leading independent oil and gas company, having accumulated assets with a gross total 2C resources of 255 MMbbls of oil and 984 BCF of gas, including XIB, historically the country’s most productive block, having produced more than than 180 million barrels of oil, equivalent to an estimated present value of more than $2bn in today’s money.
Over the past couple of years BLOE has pursued a five well programme focused on the first of eight development areas at Project I, the Krtsanisi Anticline area of the West Rustavi/Krtsanisi field, which an independent CPR estimates as having Gross 3P Reserves of 3.01 MMbbls and an NPV of $57m. The first three wells drilled have offered early vindication of BLOE’s subsurface analysis, intersecting their targeted fractures and helping the company secure average production of 630 boepd.
Revenues from Project I have been channeled into the development of Project III, but BLOE now believes Project III is sufficiently advanced to be farmed-out at the asset level. The company has already signed one significant farm-out agreement, entering into a partnership last year with Georgia Oil & Gas Limited (GOGL), the country’s largest exploration company, according to which GOGL will explore swathes of XIB: an independent prospective resource report published earlier this month assigned 302.8 MMboe mean unrisked prospective resources to the area’s Martkopi Terrace prospect. BLOE retains a 50pc interest in the development.
The company is now looking for partners to develop Project III. Earlier this year BLOE completed an integrated full field development study of the Project’s Lower Eocene and Upper Cretaceous reservoirs, identifying gas-bearing natural fracture systems one and a half kilometres thick spanning three of the company’s fields, work which included reinterpretation of two 3D seismic surveys, well design and planning, third-party conceptual development engineering, and cost estimation for a pilot scheme and full field processing facilities. An MoU has been signed with the State of Georgia according to which it will assist BLOE’s efforts to commercialise the resources: the Georgian government has declared the field a strategic asset capable of opening a rich new seam of energy for a country that imports nearly all of its hydrocarbons. Project III gas can also be exported to the EU and beyond through the South Caucasus Pipeline that crosses BLOE’s licences. A M&A advisor in London has been appointed to provide additional support. BLOE is also completing a study on XIB’s capacity to support a world-class Carbon Capture and Storage venture for integration into Project III’s development plan.
The company’s strategic shift has been encouraged by growing exploration activity in Georgia. OMV is planning to acquire 3D seismic in the Black Sea, and China’s commitment to the country has been underlined by the presence of a private Chinese firm using services supplied by CNPC, the Chinese state-owned integrated energy group, in an onshore location between the Black Sea and Block’s Project III. CNPC has been contracted to deliver a firm work programme comprising two deep wells, using a modern rig and a full suite of integrated services. BLOE says that ‘Positive results from this work programme would have an instant read-through to the value of Project III, which stands to benefit from access to a drilling rig and integrated services capable of drilling deep directional wells promising to reduce mobilisation and demobilisation time and costs.’ Georgia entered into a strategic partnership with China this summer, and has been accepted as an EU candidate nation.
Project I’s low-cost design and BLOE’s continued efforts to contain operational costs means the company ‘will be well funded to execute this high-impact strategy through 2024, based on current production, oil prices and expected natural decline rates.’ Though the emphasis is now on Project III BLOE will consider drilling further Project I wells next year. In light of its new focus the company will publish updates as and when necessary rather than on a quarterly basis.
BLOE’s evolving strategy reflects the company’s willingness to adapt to expedite the potential of its resources. Its share price – just under 1p at the time of writing taking the company’s market cap to £7.07m – has fallen by 13pc this year as Project III, always the main prize, has somewhat receded from the market’s view, with the slow burning Project I taking centre stage. The new emphasis gives BLOE an opportunity to change perceptions, and drive a return to the higher valuations the company enjoyed a few years ago.
Eco (Atlantic) Oil & Gas
Eco (Atlantic) Oil & Gas (AIM:ECO) continues to seek to realise the potential of significant holdings in some of the world’s most prospective fields in the Atlantic margin basins offshore Guyana, Namibia and South Africa, this year taking an operating interest in its Guyana asset.
A 2022 CPR indicates best estimates, net to ECO, of 681 MMbbls oil and 544 BCF gas for Guyana, 6,705 MMbbls and 6,565 BCF for Namibia, and 6,705 MMbbls and 6,565 BCF for South Africa. This year ECO became operator of the 1,800 km2 Orinduik Block, expanding its working interest to 60pc and aggregate participating interest to 75pc. With untapped resources of 13.6 billion barrels of oil and 32 trillion cubic feet of natural gas, the Guyana-Suriname Basin, off the north coast of South America, is ranked by the US Geological Survey as the world’s second-most prospective and under-explored offshore basin. Adjacent and updip to ExxonMobil’s 13 discoveries on the Stabroek Block, which has estimated recoverable resources of more than six billion barrels of oil, the Orinduik Block offers 22 prospects, with 11 leads in the Upper Cretaceous horizon, most having a 30pc or better chance of success. ECO has initiated a farm-out process for the Block, ‘receiving early interest from a number of multi-national oil and gas companies.’
Offshore South Africa, ECO is operator and holds a 50pc working interest in Block 2B and a 26.25pc working interest in Block 3B/4B operated by Africa Oil Corp, totalling some 20,643 km2. Block 2B, covering an area of 3,062km2, has an estimated 349 million barrels of oil (Best Estimate – Gross Prospective Resources) in relatively shallow water depths of less than 200 metres, and hosts a previous light oil discovery, the AJ-1 well that flowed 191 barrels of oil per day back in the 1980s. 3D seismic data acquired in 2013 indicates further prospectivity up-dip from the discovery. Block 3B/4B, located between 120 and 250 km offshore, directly south of the Graff-1 and Venus-1 multibillion barrel discoveries announced earlier this year by Shell and TotalEnergies, covers an area of 17,581 km2 and lies in water depths ranging from 300 to 2,500 metres. ECO is progressing plans for a two-well campaign on Block 3B/4B in parallel to continuing farm-out discussions with various large industry partners. The company has submitted a Production Right Application for Block 2B to the Petroleum Agency of South Africa.
ECO has a stake in another of the world’s emerging hydrocarbon locations, the Walvis Basin, offshore Namibia, which is estimated to hold some 25 billion barrels of prospective resources. The company has an 85pc working interest and operates four Namibian licence blocks spanning 28,593 km2 across the Basin. Joint Operating Agreements have been drafted for all four wells, and paying partner approvals have been granted by Namibia’s Ministry of Mines and Energy. ECO continues ‘to receive incoming interest with regard to our highly strategic acreage position, which has increased following recent media reports of multi-well drilling campaigns being lined up’.
The company’s most recent results, for the three and six month periods ended 30 September 2023, stated cash of $3.85m and no debt. The prospectivity of its assets notwithstanding, ECO’s share price has been subdued over the past couple of years as it has tried to find a path towards realising their potential. It fell some 45pc this year, down to 10.1p at the time of writing, taking the company’s market cap to CAD$54.7m. 2024 may yet reveal whether ECO is something of a sleeping giant.
Longboat Energy
Longboat Energy (LON:LBE) continues to build its presence on the Norwegian Continental Shelf, where a series of exploration wells drilled with partners including Equinor, Spirit, Idemitsu and OMV have yielded five discoveries. The company also has interests in South East Asia.
LBE entered an agreement with Japan Petroleum Exploration (JAPEX) to form a new joint venture company in Norway named Longboat JAPEX Norge AS. JAPEX received a 49.9pc shareholding in the new venture in return for a $50m cash investment, and a $100m facility to finance acquisitions and associated development costs.
A production acquisition soon followed, JAPEX investing $12.75m to take interests in two Statfjord satellite fields, Statfjord Øst (4.8pc) and Sygna (4.32pc), for a cash consideration of $12.75m. Statfjord Øst, located 7 km to the northeast of the Statfjord field in a maximum water depth of 190 metres, produces oil and gas from two subsea production templates and one water injection template tied-back to the Statfjord C platform. The Norwegian Ministry of Petroleum and Energy approved a redevelopment plan in 2021 to drill five new production wells into potentially undrained areas of the field while also adding gas-lift to increase production levels. LBE says the acquisition, expected to be completed in January, ‘represents long-term cash flow with the fields expected to produce until late 2030s.’
Last month the partners announced the drilling of the fourth of five new infill wells at Statfjord Øst, with both fields ‘expected to be fully on stream from all wells early in the new year.’ Initial production for 2023 is estimated to be around 250 boepd net to JAPEX. Production is ‘expected to increase significantly early in 2024 when all wells will be brought on stream.’ Earlier this month JAPEX decided to farm down two exploration licences on the Shelf: the company has farmed down PL1182S from 30pc to 15pc in return for a full carry of the Lotus exploration well, expected to spud in Q3 2024, and PL1049 from 40pc to 25pc. LBE says the decision reflects its strategy of retaining ‘exposure to high quality exploration wells but at minimum use of the Company’s equity capital.’
LBE entered Malaysia in February through the award of a PSC for Block 2A, offshore Sarawak, covering 12,000 km2 and located in water depths of between 100 to 1,400 metres where a number of large prospects across multiple plays have been identified, with significant volume potential representing multiple trillions of cubic feet of gas. 19 exploration discoveries have been recorded, 13 of which were made offshore Sarawak, and two exploration-appraisal successes. Earlier this month LBE extended its working interest in the PSC over Block 2A to 52.5pc
LBE’s H1 results reported exploration financing facility drawings of £33.7m (2022: £15.7m) resulting in a net debt position of £31.5m, but £32m will be repaid from a Norwegian government tax rebate of £35.5m. The company’s cash was £2.1m. LBE’s share price received a shot after the JAPEX deal, and has held steady at just over 17p, taking its market cap to just under £10m. The company continues to pursue ‘numerous growth opportunities, which span from near-term, short-cycle developments through to current production – many with a gas-weighting.’
Predator Oil & Gas
Predator Oil & Gas Holdings (LON:PRD) made confident progress this summer towards realising its goal of helping meet Morocco’s urgent demand for gas, tripling its share price through June and July.
Though the company also holds interests in Trinidad and Ireland, its primary focus is its 75pc working interest in the Guercif Petroleum Agreement, prospective for tertiary gas, located some 10 kilometres from the Maghreb-Europe Gas Pipeline, which supplied Morocco, Spain and Portugal until its closure in 2021. PRD believes the Agreement has been partially de-risked by the substantial technical evaluation work it has undertaken so far.
The first well, MOU-1, drilled in 2021, encountered formation gas in the primary target region, and studies have validated pre-drill interpretations for the development of deeper water submarine fan reservoirs similar to those found in the Rharb Basin, and in the offshore Anchois gas discovery to the west of the Guercif licence. Subsequent MOU-2, MOU-3 and MOU-4 appraisal wells have explored the eastern end of the MOU-1 structure, seeking to establish the viability of a scalable CNG development. If the project meets the threshold for gas development in the Moroccan industrial market the potential to scale up to 34 million cubic feet of gas per day (approximately 12 Bcf/year) will be assessed. The current gross Best Estimate resource, based on a conservative 66pc gas recovery over 13 years, is 393 Bcf (295 Bcf net attributable to PRD’s 75pc interest).
After engaging with potential end-users in Morocco’s industrial sector PRD signed an MoU last month with Afriquia Gaz S.A with a view to entering into ‘substantive discussions regarding a Gas Sales Agreement upon completion of the rigless testing programme at Guercif’. The company described the MoU as ‘the first of its kind in Morocco to address specifically the sale of CNG at a scale of up to potentially 50 million cubic feet of gas per day over time.’ Successful conclusion of discussions would give PRD ‘the solid foundation to penetrate the downstream Moroccan industrial market’.
The company continues to pursue its interests in Trinidad, where it is hoping to capitalise on the state’s newly adopted strategy to promote CO2 EOR and CO2 sequestration, designed to counter high CO2 emissions generated by ammonia and methanol plants.
Last month the company concluded its acquisition of an interest in the Cory Moruga exploration and production licence, representing ‘one of the few opportunities in Trinidad to apply CO2 EOR techniques in an early phase of field development before virgin reservoirs pressures have declined’, as is the issue with mature onshore oil fields in Trinidad. PRD said ‘Cory Moruga will provide newsflow over the next 12 months but most significantly creates the opportunity for cash flow in 2024 to protect against difficult market conditions and negative investor sentiment caused by uncertainty generated by regional conflicts and poorer global economic performance.’ The acquisition gives PRD three years to drill an appraisal well ahead of a proposed Field Development Plan, which in turn could unlock production of 5,000 to 9,000 bopd.
PRD continues to pursue its Mag Mell Floating Storage and Regassification Project (FSRU), ultimately designed to ensure Ireland has an indigenous source of ‘cushion gas’ through gas storage facilities that would use the existing Corrib and Kinsale gas pipelines. The company is following a ‘wait-and-see’ policy towards Ireland until the government completes its security of supply review, originally due for publication this year. PRD’s Irish interests were galvanised last year when the company received an approach for the acquisition of its position in the Corrib South exploration asset, which has mid and high case estimates for gross gas resources of 137.8 and 484.8 Bcf respectively (PRD net interest 50pc), estimated to have a 44pc chance of geological success and a 50pc chance of development.
PRD’s share price has fallen back from a July high of 20p to 8.5p at the time of writing, taking its market cap to £49m. But progress in Morocco and Trinidad the company is worth watching early in the New Year.
Reabold Resources
Reabold Resources (AIM:RBD) has sharpened its focus this year on exploration, appraisal and development projects onshore UK and Italy.
RBD has an aggregate 56pc economic interest in the West Newton-PEDL183 licence north of Hull operated by Rathlin, potentially one of the largest hydrocarbon fields discovered onshore UK. The JV partnership is planning to drill and test the WN B-2 by next June, envisaging a multi-well development programme served by a 50 Mscf/d gas facility. The licence’s Crawberry Hill prospect has been identified as another significant potential discovery.
RBD has built a significant interest in LNEnergy Limited this year, taking a 26.1pc stake in a company focused on the Colle Santo gas field in Abruzzo, Italy, a gas resource with an estimated 65 Bcf of 2P reserves, with two production wells already drilled. The field, which RBD says ‘could be the largest onshore proven undeveloped gas field in mainland Western Europe’, is development ready, subject to approvals and permits. A small-scale LNG facility is planned, producing at an initial at 10 MMcf/d from two existing wells. LNEnergy believes that the field has the potential to generate an estimated €11-12m of gross post-tax free cash flow per year.
RBD has interests in several other assets. The company retains four North Sea licences including the key Dunrobin prospect on licence P2478, which an April 2023 CPR estimated to have 201 MMboe aggregate gross unrisked Pmean Prospective Resources. It has a 42pc shareholding in Daybreak Oil and Gas Inc, an OTC traded oil and gas company engaged in the exploration, development and production of onshore crude oil and natural gas, primarily in California. And it continues to engage with Romanian authorities regarding an exploration licence for the country’s Parta and Iecea Mare licences.
RBD’s results for H1 2023 stated net cash of £2.6m at 30 June 2023, but the company has since confirmed continued payment from Shell for the sale of the Victory gas field last year, a project in which RBD had an interest. Following an initial payment of £3.2m last November, this month the hydrocarbons giant confirmed payment of another £5.2m, with a final consideration of £4.4m due upon the North Sea Transition Authority (NSTA) granting development approval for the Victory gas field, ‘which is anticipated to occur within the coming months’. The receipts, which RBD offer as vindication of its strategy of investing in projects with significant valuation potential, will fund ongoing development work and a £4m share buyback programme, initiated in April.
The Shell repayments have, however, triggered disputes regarding the company’s direction. Both have been accompanied by requisition notices requesting General Meetings to vote in new directors: the next will take place on 10 January. RBD’s management describes the efforts as ‘opportunistic’, noting that both have coincided with tranche payments from Shell. The rebel shareholders have significant interests in Daybreak Oil & Gas, a lower priority for the current board than West Newton and Colle Santo.
Internal disputes notwithstanding, RBD may be worth a look in the New Year, with a strong funding position facilitated by the Shell payments underpinning investment in two highly prospective projects. The company’s share price at the time of writing is 0.12p and its market cap £11.84m.
Tower Resources
Africa-focused exploration and production group Tower Resources (AIM:TRP) has spent 2023 constructing a balanced portfolio ranging from exploration through appraisal to production, initially focusing on lower risk appraisal and development within the proven Rio del Rey basin in Cameroon, where there is also low-risk exploration upside, while maintaining selective exposure to longer term and higher risk/reward prospects in Namibia and South Africa.
TRP is seeking near-term production and revenues through its 100pc interest in the shallow-water Thali PSC, offshore Cameroon, within the prolific Rio del Rey basin in the eastern part of the Niger Delta. 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’s priority is to drill PSC’s NJOM-3 well and thereby illuminate the potential of the asset’s Njoni structure. Risked pMean recoverable resources for reservoirs connected to the NJOM-1 and NJOM-2 wells have been estimated at 35.4 million barrels. TRP is seeking farm-out or equivalent funding at the asset level, estimating the funding requirement at around $13m. The company says it is ‘discussing this with multiple parties, and one discussion is now at a very advanced stage’. Earlier this month TRP announced the company had executed a contract for the hire of a suitable jack-up rig to drill the NJOM-3 well on in 2024.
TRP also has an 80pc operated interest in licence PEL 96 covering Blocks 1910A, 1911 and 1912B spanning a swath of the northern Walvis Basin and Dolphin Graben offshore Namibia, an under-explored region in which past drilling results have already proven the presence of a working oil-prone petroleum system, along with good quality turbidite and carbonate reservoirs. The blocks are located directly adjacent to licences in which ExxonMobil has interests. An initial (unaudited) resource estimate for PEL 96’s primary prospects and leads indicates billion-barrel oil potential in the licence’s Outer High Structural Closures, and includes individual leads ranging from 250 to 686 MMbbl in the Dolphin Graben Structural Closures, although this work is now being reviewed in the light of TRP’s recent basin modelling work. The company is developing an updated prospect and lead inventory leading to the specification of the optimal area for 3D seismic data acquisition and contractor selection for that work
TRP has a 50pc interest in the 9,369 km2 Algoa-Gamtoos licence, offshore South Africa, operated by New Age Energy. The acreage straddles the Algoa and Gamtoos basins on the shelf, and the outboard slope edge of the South Outeniqua Basin where Total made its Brulpadda and Luiperd discoveries in its Blocks 11B/12B, which are adjacent to Algoa-Gamtoos to the west. The updated (unaudited) prospective resources estimate, summarised on an unrisked volumetric basis, indicates a summed mean of Oil in Place of 5,273 MMbbl, and a summed mean of Recoverable Oil Equivalent of 1,983 Mmboe, but the most important part of this is in the deep-water Outeniqua basin lead. TRP continues to discuss the possible schedule for 3D seismic acquisition over Outeniqua, which may be feasible in 2025.
The challenge of securing financing for Thali’s NJOM-3 well have weighed on TRP’s value, currently 0.02p, keeping the company’s market cap at £2m, a figure dwarfed by the value of the company’s assets. The company ended 2023 on a positive note, securing a rig for NJOM-3, and raising £600,000 to support work programme commitments in all three of its licenses over the coming months.
Union Jack Oil
UK-focused oil and gas producer Union Jack Oil (AIM:UJO) has continued to profit from the highly successful resumption of production at its flagship Wressle asset, generating revenues underpinning plans for future ventures.
The company’s flagship asset remains its 40pc interest in the PEDL180 and PEDL182 Wressle Oilfield Development located by the Humber Basin. Since the resumption of production just over two years ago the Wressle-1 well discovery has produced nearly 500,000 barrels of oil from the Ashover Grit formation, which a 2016 CPR forecasts to have gross volumes of 2P 0.54 MMstb and 3P 1.12 MMstb. Evaluations are continuing in order to deliver a full Field Development Plan that will maximise hydrocarbon recoveries from the Ashover Grit, Wingfield Flags, Penistone Flags and other associated prospects. Production was paused earlier this year to allow flow-rate optimisation, including operations to minimise the well’s water cut, but was resumed last month. Earlier this month the company received Environment Agency approval to allow Wressle-1’s production to exceed 550 bopd.
UJO received positive news last month regarding its 45pc interest in the PEDL253 licence at Biscathorpe, situated within the proven hydrocarbon fairway of the South Humber Basin, on-trend with the Keddington oilfield and the Saltfleetby gasfield. Potentially one of the largest unappraised conventional onshore discoveries within the UK, a planned side-track targeting a gross Mean Prospective Resource of 2.55 MMbb has been blocked by regulators. But in November an appeal against the refusal of planning permission by Lincolnshire County Council was upheld by the Planning Inspectorate. The partners are reviewing next steps.
UJO has a 55pc interest in the PEDL005(R) licence at the producing Keddington oilfield located along the East Barkwith Ridge, an east-west structural high on the southern margin of the Humber Basin, where a subsurface review highlights a viable target to the east of the field, with up to 180,000 barrels of incremental production. The partners have secured planning permission for a side-track next year.
The company has a 16.665pc interest in the West Newton Appraisal PEDL183 licence north of the River Humber, where analysis indicates a gas reservoir, Best Case Gross Unrisked Contingent Technically Recoverable Sales Gas is estimated to be 197.6 Bcf. And it has a 50pc interest in the PEDL241 licence at North Kelsey, an oil exploration prospect on trend with and analogous to the Wressle oilfield, with a gross Prospective Resource ranging from 4.66 to 8.47 MMbo. Planning has so far been denied: a new application will be submitted following consultation with the local community.
Contributions from Wressle supplemented by Keddington revenues have allowed UJO to continue to post robust returns in 2023, the company’s H1 results reporting a gross profit of £1,608,973, a net profit of £572,263, revenue of £3,584,866, and a healthy cash balance of £9,250,000, as of September 2023. The company is fully funded for all G&A, OPEX and planned CAPEX costs, including any budgeted drilling activities for at least the next 12 months without recourse to the markets. Since last September UJO has returned over £2,995,000 to shareholders.
With strong ongoing production and new prospects 2024 looks like another bright year for UJO operations-wise, possibly clouded somewhat by political uncertainty regarding the development of the UK hydrocarbons sector. To ‘mitigate future risk, the Board believes it is compelled strategically to seek growth opportunities further afield in politically safe regimes and with sympathetic views toward the oil industry’. At the time of writing UJO’s share price was just under 20p, and its market cap £20.5m.
