12 Oil and Gas Companies to follow in 2023
Mainstream oil and gas stocks have soared this year as prices have been forced up by the accumulating energy supply shock: the slowdown in production through the pandemic, subdued output from a US shale industry keen not to repeat past boom-bust cycles, the reluctance of OPEC to step up supply, and, of course, the war in Ukraine and the subsequent Russian oil embargo.
But as with everything in 2022, there are plenty of uncertainties. Windfall profits have been followed by windfall taxes, a surcharge on what governments consider excess returns from rising oil and gas prices. Not a great burden, it may be argued, if the gain on which the taxes are applied was not expected. But a comparative disadvantage for companies in countries in which they are applied – like the UK – as against those in which they are not. There is the growing threat of legal action by environmental groups: Greenpeace, for example, has applied to the High Court for a judicial review of the decision to approve a new oil and gas licensing round in the North Sea. There are near term economic pressures. Demand may fall next year as recessionary fears grow, Peel Hunt predicting the price of Brent crude will fall from $90, to $80 and then $65 through 2023-25. And competing renewables are getting ever more efficient and cheaper: the IEA estimates renewable capacity will increase by almost 75pc by 2027 – much faster than it had previously forecast.
But the bigger picture, as this year has viscerally demonstrated, is that hydrocarbons will be with us for some time to come. The world still depends on oil, gas and coal for 80pc of its energy. The UK relies on gas for 40pc of its electricity. Increasing demand for renewables does not preclude persistent demand for fossil fuels: the IEA itself estimates oil demand will rise from 95 million barrels a day (Mb/d) in 2021 to 102 Mb/d by 2030. That doesn’t sound like a lot, but oil and gas companies need to work hard to open up new fields to replace those that are declining. Goldman Sachs estimates that producers will invest about $750bn in new fields as late as 2025, only a quarter less than 10 years ago, but even that will be unsufficient to cover the underlying declines in production as fields mature.
Demand for oil will gradually slow as its largest end product, automative fuel, makes way for electric cars. But it will still be required for a wide range of other applications. And while renewables will continue to supply an ever greater share of the world’s electricity, natural gas will still be required for the fertiliser that accounts for 60pc of current demand. Emerging cleaner ‘blue’ and ‘green’ hydrogen processes require enormous capital investment. The green transition must also navigate considerable political pressures, illustrated by the twists and turns of the ecologically-sensitive Biden administration to rising gas prices.
Energy investors would have done well to have had a decent stake in big oil this year, which has produced strong and steady returns. But as TMS readers know, small cap E&P stocks that strike oil can yield spectacular returns. By September they accounted for seven of the 10 best performing AIM stocks.
Our dozen Oil and gas picks last year yielded a fantastic return. Overall an average 65% return on EACH selection with the standout picks #IGAS (up 1000% in 2022) then #PXEN and #UJO both up over 400% during the year.
Readers will also know, however, that finding those opportunities takes work. The big companies mirror global trends, but small caps depend much more on micro-specifics. Local markets and political conditions must be assessed, assets risk assessed and adjusted, balance sheets examined, management teams scrutinised, and (often) very long discounted cash flows taken into account. Traditional metrics such as price-to-earnings and price-to-book ratios are often not much help. That said, the risks the E&P sector has to take to locate and develop assets have lessened in recent years due to the increasing availability of high-quality assets offloaded by large operators, which has allowed smaller operates to both enhance and de-risk their portfolios. A few have even been in a position to follow bigger companies in pay dividends and engage in share buybacks.
Here we pick out a few small cap oil and gas companies worth following in 2023.
Companies covered include:
#88E #ANGS #BEY #BLOE #CHAR #CORO #ECO #EOG #IOG #LBE #NTOG #UJO
88 Energy (AIM: 88E) has assembled an intriguing portfolio of prospects located on Alaska’s largely unexplored North Shore. The first two exploratory wells disappointed, halving the company’s value after a bright start to the year. But with money in the bank, and new prospects at various points on the horizon, 88E is worth another look.
The company owns and operates four prospective projects on the Alaskan Central North Slope, funding their exploration, in part, through cash flows secured from a majority interest in a group of producing wells in the Permian Basin, Texas. Alaskan oil exploration continues to be politically contentious – the Arctic National Wildlife Refuge is one of the largest areas of untouched wilderness in the US. But the limited exploration that has taken place indicates rich hydrocarbon resources. The relatively unexplored North Slope, 88E’s area of interest, boasts some of the largest oil fields in the US, including Prudhoe Bay, North America’s largest.
The company’s four Alaskan prospects are at various stages of development. The wholly-owned Project Peregrine, acquired in 2020, spanning 195,973 acres, is targeting the Nanushuk reservoir contiguous with Conoco Phillip’s Harpoon and Willow drilling programmes to the north, the latter of which contains a recoverable 750-800 MMbo (million barrels of oil). 88E’s current estimates indicate Peregrine has a total mean prospective oil resource of 1,624 MMbo.
There was a significant setback earlier this year at Peregrine when the Merlin-1 and Merlin-2 exploratory wells found the targeted reservoir quality was insufficient to warrant a production test. While acknowledging the anticlimactic results 88E said that the wells were drilled on the basis of ‘sparse, vintage 2D seismic data’ that could only offer a narrow view of the reservoir and limited optionality on drilling locations. The company ‘will assess the merits’ of a future 3D seismic acquisition or in-fill 2D programme to define optimal play fairways and determine the Project’s potential commerciality. Detailed analysis of all data obtained from the Merlin-2 drilling programme indicated that richer resources may lie in locations somewhat to the north of initial drilling. The ‘abundant oil shows’ that the wells had did indicate were encouraging for the as yet untested northern prospects.
Though Peregrine got most of the attention this year 88E has also advanced its Project Icewine prospect, in which the company has a 75pc interest, a 193,000 acre field with a resource currently estimated at 1.77 billion boe. An exploration well is planned next year to further define the acreage’s potential ahead of an expected strategic-farm out. A maiden Independent Prospective Resource estimate completed at Project Icewine East published in August indicated a potential resource of 1.03 billion barrels of oil recoverable from multiple reservoir zones. Interpretation of 3D seismic data has identified the location for an exploration well, Hickory-1, planned for 1H 2023.
88E’s two other Alaskan prospects are at earlier stages of development. The company’s wholly-owned Umiat Oil Field, acquired last year, features an historic oil discovery in shallow Nanushuk sandstones, located immediately adjacent to the southern boundary of Peregrine, opening the prospect that ‘in combination with Project Peregrine’ Umiat may have ‘the potential to form a potentially large oil field development.’ Current estimates indicate a 2P net reserves to revenue entitlement of 94,007 barrels of oil, and 3P net reserves of 43,439. 88E’s 100pc owned Yukon Leases, spanning 19,000 acres, also encompass an existing historic discovery, the Yukon Gold-1 well drilled back in the 1990s, which indicated a 90 MMbo prospective resource. Earlier this month the company moved towards a fifth Alaskan interest, being ‘declared the highest bidder for select acreage offered as part of the North Slope Areawide 2022W Oil and Gas lease sale’. The prospective Project Leonis will comprise 10 leases covering approximately 25,600 acres, and contain an historic exploration well drilled by ARCO in the 1980s targeting the deep Kuparuk and Ivishak reservoirs. Further work and analysis will further define the acreage’s potential and define a possible exploration programme and timeline.
Earlier this year 88E made its first move into producing oil and gas assets with the acquisition of a 73pc non-operating interest in Project Longhorn, located in the Permian Basin with independently certified net 2P reserves of 2.1 MMboe. Following 88E’s purchase the partners embarked on a workover programme which succeeded in increasing production by 70pc, generating $1.2m for 88E, prompting plans for a further 11 workovers and new drills to push the rate up to 1,300 boe. A September update reported Longhorn was delivering around 450 boe per day, an overall output increase of 60pc since the acquisition. The programme had secured net cash flows of $1.9m, with produced expected ‘to reach over 500 BOE per day by end of 2022’.
88E’s H1 results reflected the cost of Project Peregrine’s Merlin operations, the company recording a loss of $67m against an H1 2021 profit of $445,446. But it was debt free with cash on hand of $10.5m (H1 2021: $32.31m), and net assets of $80m. An August placing raised £8.59m for pre-planning and permitting for the Icewine East well, and preparations for a flow test programme.
After Merlin wells failed to take off 88E’s share price plunged from 2p to 0.7p in the space of a day, a drop in value from which the stock has not yet recovered, bumping along at around 0.5p to 0.75p ever since, fixing the company’s market cap at around $83m at the time of writing. But the company is debt free, has cash, and is drawing revenues from Project Longhorn. Project Peregrine seems to have potential north of the initial Merlin targets, though the company has not detailed its next moves here yet. Project Icewine’s forthcoming Hickory-1 well would seem to be the next concrete event on 88E’s horizon. If it can stay funded to unlock even some of the potential its assets seem to promise, 88E’s stock will surely climb.
Angus Energy (AIM:ANGS) has a cluster of legacy oil producing fields across southern England, with 80pc interests in Brockham (PL235) and Lidsey (PL 241), 25pc in Balcombe (PEDL244), and 12.5pc in the A24 Prospect at Holmwood (PEDL 143). But the company is now firmly oriented towards gas, securing a 100pc interest this year in the Saltfleetby Gas Field (PEDL005) in Lincolnshire, and a set of emerging geothermal, hydrogen, carbon capture and waste-to-energy projects.
ANGS’s primary focus this year has been moving Saltfleetby into production, not least to take advantage of soaring gas prices. A revised CPR published last October estimated the field is capable of generating £230m in gross revenue. Production got underway in the summer, a September update reporting an average daily flow rate of 5.2 MMscfd and a peak flow rate of 5.7 MMscfd, results comparing favourably to the rate of 5.0 MMscfd forecast in the CPR. Pressure on the existing two wells A4 and B2 remains high at about 54 bars, with gas volumes equivalent to 1.2 million therms produced and sold. Sidetracking operations to further boost production are underway, with drilling expected to end this month. Testing will be required before flow rates can be announced.
Elsewhere ANGS has continued its efforts ‘to realise value from Balcombe, Brockham and Lidsey through either the resuming of production or through a sales process’. The company persists in its efforts to secure planning permission for well testing at Balcombe, so far repeatedly declined by the local authority. ANGS’ most recent final results, published earlier this month, said the company was doubling-down on its efforts to secure planning, noting that regulators ‘are being more pro-active and pre-emptive, and we must anticipate their needs and expectations better than we have in the past.’
The company has resumed production at Brockham’s Portland reservoir, achieving average rates of 50 bopd (net 40 bopd due to ANGS. The company is processing new seismic data acquired at Lidsey, third party verification shows there to be a significant structure not dissimilar in area to the original structure considered by the previous CPR, which continues to support a commercially significant estimate of oil in place.
ANGS is also advancing a set of renewable projects, notably a pilot geothermal initiative at Saltfleetby. Geothermal offers the possibility of safe, sustainable, base load electricity generation using technologies with which oil and gas operators are already familiar. Initial studies suggest Saltfleetby has the potential to generate up to 2 MW that could be used to power the site, support enhanced covered cash crop agriculture, and provide an electricity surplus for other local projects. In addition, ANGS is investigating a 35km2 area at Austinbridgeporth, south-western England, where analysis has identified unusually high heat flows. Initial meetings have been held with the National Grid to establish a connection point with 200 MW capacity to act as a centralised offtake point. Discussions are underway with landowners to negotiate heads of terms for the prospective project.
ANGS is also exploring Saltfleetby’s potential to contribute to the Humber Hydrogen Initiative. Connected to all of the production facilities on the Humber, the field has potential as a feedstock source or a potential storage field for hydrogen or CO2 once the remaining natural gas has been produced. The company has installed hydrogen tight thermoplastic pipes at Saltfleetby, allowing for a smooth transition to the gas if hydrogen blending is distributed into the grid.
ANGS is undertaking feasibility studies to assess the viability of pursuing Waste to Energy (WtE) projects that would combust non-recyclable waste products into energy in the form of steam, electricity or hot water for distribution into the grid or directly to end users. WtE has the potential both to reduce landfilled waste and while produce green energy.
ANGS has undertaken an aggressive fundraising campaign to push ahead with production at Saltfleetby, raising £7.1m earlier this month building on previously declared cash of £1.44m. The company’s stock has risen 135pc over the past year to just under 1.5p at the time of writing, taking its market cap to £43m. Impressive but down on the peak price of 2.7p touched in September, prior to the last round of fund-raising. This is a fast moving story: prospective investors should look out for continued progress at Saltfleetby.
Barryroe Offshore Energy
Barryroe Offshore Energy (LON: BEY), formerly known as Providence Resources, continues efforts to get the green light from the Irish Government and regulators for an ambitious programme to test a decades-old significant oil and gas discovery in the Celtic Sea.
A strategic review and CPR confirmed a core area ‘base case’ of 81.2 MMstb of Gross 2C oil resources in shallow waters offshore West Cork accessible through an initial two-phase development project, initially addressing a reservoir in the central core segments of the field. The CPR estimates a NPV of $401m to BEY’s interest in this initial project only, based on a 10pc discount factor and a $70 Brent oil price. The initial development project is predicated on the outcome of appraisal drilling to confirm the reservoir and hydrocarbon phase characteristics in the key Basal Wealden A Sands and the lateral extent of the shallower C Sands, with up to 400 bcf of gas resource in place. This will advance the potential for further development of other Barryroe reservoirs, including those holding its discovered and prospective in place gas resources in excess of 1 tcf. BEY envisages phased development leading to first production in late 2026. This summer the company raised gross proceeds of $1.8m. At the end of H1 it had cash of €2,188,000.
BEY has ‘proactively and repeatedly engaged’ with Ireland’s GeoScience Regulation Office (GSRO), the Minister for the Environment, Climate and Communications (DECC), and an array of public representatives for the granting of the lease. The company notes that in 2019 the Irish Government affirmed that all existing licences – including Barryroe – would be allowed to run their full term: current policy does not restrict Ireland’s use of hydrocarbon fuels; it merely precludes new oil and gas exploration in Irish waters. Barryroe is a discovered oil and gas field, not a wildcat prospect, in relatively shallow waters not far off the coast of Cork.
BEY also notes Ireland’s relative dependency on imports for gas: the Economic and Social Research Institute recently ranked the country as the fourth-most energy insecure in Europe, reliant for 70pc of its gas on a pair of interconnectors running from Scotland to Ireland. The remaining 30pc comes from the Corrib field northeast of County Mayo, which is expected to be depleted by the end of the decade. The company argues that gas produced in Ireland generates 30pc lower carbon emissions than that imported from outside Europe courtesy of more efficient production technologies and shorter pipelines. Recent updates clearly communicate BEY’s frustration, the company’s half-year report commenting that ‘there is no reasonable justification for the ongoing delay. The Board believes that all required technical and financial information in relation to the Barryroe Lease Undertaking has been submitted to the GSRO.’
Though the leasing decision is ultimately out of its hands, BEY has been able to satisfy a further DECC requirement, responding last month to a Department request to clarify its funding for the venture with details on how shareholder Vevan Unlimited – backed by beef baron Larry Goodman – will underwrite all of the expected funding required for the work programme proposed in the Lease Undertaking Application. The funding will be in the form of a redeemable secured Convertible Loan Note instrument according to which the Loan Note holders will fund the Barryroe Work Programme up to €40m.
This is a tough one to call. BEY’s case is strong, but it’s nearly 50 years since Barryroe was discovered, by Esso back in 1974. It wasn’t brought into production then because of the cost of recovering the waxy oil and uncertainty over the size of the find: the field is expected to produce waxy oil, similar to types found in Libya, which solidifies when it comes to the surface. As Providence Resources BEY renewed efforts to develop the field in 2012, arguing better seismic and drilling technologies had helped it get much better definition on the potential scale of the oil deposits, and that new systems that keep oil heated as it is pumped would allow Barryroe’s oil to be recovered efficiently. BEY’s impressive €40m funding arrangement boosts the company’s case further, but grassroots resistance in Ireland to hydrocarbons projects has always been fierce: Shell struggled to push through the Corrib venture back in 2009. This remains an interesting project to keep an eye on, but history should teach prospective investors to be cautious. BEY’s share price was 3.3p at the time of writing, up 17pc over the year, taking its market cap to €33.8m.
Block Energy (AIM:BLOE) continues to execute an evolving strategy for unlocking the potential of a now extensive portfolio of oil and gas assets in the country of Georgia, a plan complemented by a new farm-in agreement targeting exploration opportunities of 800 MMboe.
Founded on the premise of bringing cutting edge drilling technology to a set of fields whose promise was proven during the Soviet era, the company’s exploration is underpinned by revenues generated from a cluster of producing wells. BLOE listed in the summer of 2018 with a set of fields on the outskirts of Georgia’s capital city Tbilisi, notably West Rustavi, which produced 50 Mbbls of light sweet crude during the Soviet era, with contingent resources of 38 MMbbls oil and 608 BCF gas in the Middle, Upper and Lower Eocene formations. The first few wells drilled by the produced recorded high gas-to-oil ratios, prompting the company to accelerate its gas offtake strategy with a view to serving a Georgian energy market almost wholly dependent on imports from neighbouring countries. Sales from the company’s West Rustavi gas facility began last year.
BLOE’s story turned a new chapter early in 2020 when the company took advantage of an unexpected opportunity to acquire significant assets adjacent to West Rustavi from departing operator SLB (formerly Schlumberger). The deal multiplied BLOE’s acreage more than 30 times, granting ownership of a cluster of development opportunities including Block XIB, which during the Soviet era had been Georgia’s most prolific field, producing more than 180 million bbls of oil from the Middle Eocene reservoir, rates peaking in the 1980s at 67,000 bopd. Together the new assets increased the company’s 2P reserves of oil and gas by 64 MMboe, its 2C contingent resources by 29 million boe, and its prospective resources by 245 MMboe. The acquisition began to look better still last month when SLB said it had decided not to take up the option to acquire the 108 million shares in BLOE granted to the major as part of the deal, thereby removing the prospect of a significant dilution in the value of BLOE’s stock.
The company gained the time it needed to assess how best to develop its new assets through placings and the drilling of what to date remains its most successful West Rustavi well, JKT-01Z, which came online at a rate of 344 boepd and has produced a cumulative volume of 64,000 boe over 11 months of continuous production, securing an approximate 2.5 times return on capex.
BLOE set out its development strategy early this year, organised into three projects designed to gradually open up the potential of its now substantial Georgian assets. Project I, for which the company is seeking non-dilutive funding, seeks to develop the Middle Eocene layer in the West Rustavi/Krtsanisi field spanning two blocks, XIF and XIB, and envisages three sidetracks and two new wells. A CPR was published this summer to attract funding for Project I, highlighting the potential of the field’s Krtsanisi Anticline, estimated to have Gross 2P Reserves of 1.07 MMbbls and 2P Reserves of 17.95 MMbbls. Project II, which is self-funded, focuses on the infill development of the Middle Eocene oil reservoir in the Patardzeuli oil field in Block XIB. Projected funds from Projects I and II will anchor Project III, a longer term venture to appraise and develop the extensive natural gas resources that BLOE’s analysis indicates is present in the Eocene layer under Blocks XIF and XIB. The company’s investment case asks that investors take a holistic view: results from each well should be viewed in the light of its position within the overall strategy.
The company has forged ahead with the plan this year. The first Project I sidetrack, WR-B01, is underway. Project II commenced in July with the drilling of well JSR-01DEEP, planned as ‘the first of a series of wells in a wide range of … opportunities designed to evaluate large, undrained areas of the deeper zones of the Middle Eocene reservoir and test contingent resources of over 200 MMbbls’. JSR-01DEEP came online at 45 bopd in earlier this month. Project III, the evaluation and development of the natural gas resources throughout the Eocene in blocks XIF and XIB, will begin with the workover of legacy wells where past operations have recorded gas discoveries. Operations will include the potential sidetrack of the PAT-E1 discovery well, engineered for a 1000 metre horizontal section through the Lower Eocene and designed to evaluate more than 300 Bcf of contingent gas resources.
Earlier this month BLOE’s three-part strategy was extended to include an effective ‘Project IV’, a farm-out agreement with Georgia Oil and Gas Limited (GOGL), the country’s largest exploration company, for a work programme on areas of the XIB licence not previously covered by the strategy. The agreement grants GOGL a 50pc participating interest in the Didi Lilo and South Samgori areas of XIB in return for committing to a $3m work programme that will include the acquisition and processing of 210 km of 2D seismic data and the reprocessing of 1,000 km of existing seismic data within and around Didi Lilo, South Samgori and the remainder of XIB. GOGL has assigned a risked (P50) Resource to the two areas of more than 400 MMboe. The transaction will have no impact on BLOE’s existing production base or operator status across all existing fields, and will cap BLOE’s commitment to $50,000 until GOGL elects to acquire a 3D seismic survey over the areas and/or drill a well.
While executing its strategy BLOE has recorded steady production and revenues, driven by JKT-01Z, an extensive workover programme, and high oil and gas prices. The company’s half-year report showed the company was now making a profit from continuing operations, $0.627m in H1 2022 against a loss of $2.05m for H1 2021. A Q3 operations update stated a cash balance of $1.1m (30 June 2022: $1.4m).
BLOE’s share price climbed steadily for most of the year, from levels of just below 1p to a peak of 2.3p early last month, though it has since fallen back to 1.1p at the time of writing, taking the company’s market cap to £7.3m. BLOE continues to be a somewhat enigmatic, but intriguing prospect, seeking to open up fields in a post-Soviet geology to which contemporary drilling technology has never been applied. Nothing is guaranteed. But the company has accumulated a significant set of assets in its short history, and mapped out a detailed, self-funded strategy for unlocking their value, which has moved forward on all fronts this year.
Africa-focused energy company Chariot (AIM: CHAR) has been one of 2022’s star small cap performers, a drilling campaign at the start of the year revealing a significant gas discovery at the Anchois Gas Project offshore Morocco.
Located within Lixus Offshore licence in which CHAR holds a 75pc interest (with the Moroccan state holding the rest), operations discovered a ‘basin scale opportunity’, a 150 metre net pay across seven reservoirs estimated to hold recoverable resources of 1.4 Tcf (2C plus 2U). CHAR is working on the front end engineering design elements of a development plan with Schlumberger and Subsea 7; has signed a tie-in agreement with the Moroccan state giving access to the Maghreb Europe Gas pipeline; is engaged in ongoing offtake and strategic partnering discussions; and is aiming for a final investment decision (FID) as soon as possible to start generating material cash flows thereafter.
This year’s discovery has served to derisk a range of other targets at the Lixus licence, and surrounding acreage in the Rissana Offshore Licence secured by the company in February 2022. Early assessment of the areas in Rissana covered by 3D seismic projects a total 2U prospective resource of more than 7 Tcf, combining the high-graded Emissole prospect with the lower risk Anchois Tertiary gas play and multi Tcf prospects in a higher-risk Mesozoic play.
Earlier this month CHAR agreed the principles of a GSA with the company’s host nation, which will allow sales of up to 0.6 Bcm per year (around 60 MMscf per day) on a take or pay basis for a minimum of 10 years with gas to be delivered through the Maghreb pipeline. The deal will help secures direct, domestic supply for Morocco’s existing and potential longer term gas power plant infrastructure. Whille ‘there is no guarantee that these principles will be turned into a fully termed GSA’, the parties are progressing with the next stage of documentation.
In addition to forging ahead with the Anchois prospect CHAR has continued to develop the renewables side of its business. The company’s Transitional Power wing ‘is focused on providing innovative energy solutions for mining and industrial offtakers across the African continent in order to reduce costs, improve ESG performance, and deliver reliable and low-risk energy supplies.’ Working alongside French independent power producer Total Eren CHAR has secured two substantial new projects this year: a 40 MW solar plant now in development at Tharisa’s PGM and chrome mine in South Africa, and a 430 MW solar and wind partnership underway at First Quantum’s Kansanshi copper gold mine in Zambia. The parnership with Total Eren grants CHAR the right to invest up to 49pc in co-developed mining projects. Both of this year’s projects are flagship initiatives within their respective countries and aspire to a similar development path to that of IAMGold’s ‘exemplary’ operational 15 GW solar project at the Essakane gold mine in Burkina Faso, in which CHAR has a 10pc stake.
CHAR also has a Green Hydrogen business, partnering – again – with Total Eren in Mauritania to co-develop Project Nour, which has the potential to install 10GW of electrolyser capacity. CHAR says the 50-50 venture ‘could become one of the most competitive green hydrogen projects in the world’ due to the abundance of the country’s wind and solar resources, and could bring a range of sustainable economic benefits to Mauritania including greener industry opportunities and provision of clean power to the national grid. An MoU has been signed with the Port of Rotterdam International, a global energy hub and Europe’s largest seaport, a first step towards establishing supply chains.
Last month the partners agreed to work together on the development, financing, construction, and operation of a solar photovoltaic (PV) project that will provide competitive electricity for the Karo Platinum Project, in Zimbabwe. The project is expected to have an initial installed capacity of 30 megawatt peak (MWp) with a potential extension of up to 300 MWp. Construction of the Karo Platinum Mine is underway. They have also entered a new joint venture through a 25pc interest in a new South African electricity trading company, Etana Energy which has been granted an electricity trading licence by the National Energy Regulator of South Africa. Etana’s objective is to deliver unique renewable energy mix solutions at competitive prices to help address the significant power requirements across South Africa, the licence ‘opening up access to a range of high-volume off-takers including municipal, industrial and retail customers.’
CHAR undertook a major fundraising round in June, raising gross proceeds of $29.5m. At the end of H1 the company was debt free and reported cash of $23.4m. The highly encouraging discovery at Anchois, and encouraging news on other fronts, sent CHAR’s share price flying this year, up 107pc to 16.2p at the time of writing, taking its market cap to £155m. Note, though, that its stock was as high as 24p in April, indicating the value the company could reach again as it closes in on a FID at Anchois.
Coro Energy (AIM: CORO) this year decisively pivoted to South East Asia, entering into an option agreement to dispose of its producing Italian portfolio to focus on hydrocarbons and renewables prospects in Vietnam, the Phillipines and Indonesia.
CORO’s reorientation is in service of its 15pc interest in the Duyung Production Sharing Contract (PSC) encompassing the Mako Gas Project, which, with 437 Bcf 2C resources is one of the largest gas discoveries in the West Natuna Basin offshore Indonesia. The project partners are working towards a Gas Sales Agreement (GSA) that CORO anticipates will be a ‘key inflection point’ for the company. The CPR projects compelling economics: first gas in 2025, NPV10 net to Coro of $87m ($577m gross) and plateau production of 120 MMscf/d for six years in the Best Case (2C) scenario, and 42 Bcf net entitlement 2C resources to Coro during the PSC life.
A plan for a two-phased development with six wells in phase 1 and a further two wells in phase 2 after five years of production, with sales gas transported via the West Natuna Transportation System pipeline for sales to the Singapore market, has been submitted to the Indonesian Ministry of Energy and Mineral Resources for approval. CORO expects to secure a Reserve Based Lending facility to fund its $38m share of capital expenditure to first gas. The Ministry approved the partners’ Plan of Development last month: the Project is in line with Indonesia’s stated objective of doubling domestic gas production by 2030, and importation of pipeline gas would provide secure and reliable energy to Singapore that is less carbon intensive than LNG.
CORO this year secured an option agreement with an existing operator in Italy ( to purchase the company’s Italian portfolio for up to €7.5m. Helped by soaring gas prices the portfolio produced 2,425,342 scm in H1 (H1 2021: 1,228,597 scm), revenue of €2,556,000 (H1 2021: €219,046) and a gross profit of $1,294,000 (H1 2021: gross loss of $191,000). CORO expects the option cash consideration, the retained NPI and the cash flows delivered by the Italian portfolio under CORO’s continued ownership in the current gas price environment, to be worth around €10m.
The company also has a lively Asian renewables business, in September finalising a 3 MW rooftop solar pilot project in Vietnam consisting of over 4,500 solar panels and other ancillary components installed across four factory roofs covering a total area of 16,120 square metres. The project is now delivering electrical power which is being consumed on site by Phong Phu Corporation, one of Vietnam’s premier textile manufacturers under a 25-year power purchase agreement and is expected, at current pricing levels, to produce net cash flows to the Group of approximately $0.3m per annum, equivalent to aggregate revenues of between $9m and $11m over the full duration. The venture, the company’s first installed and operated renewable energy project, offers proof of concept for CORO’s portfolio of rooftop solar opportunities.
CORO also has two development stage renewables projects in the Philippines, a 100 MW solar project and a 100 MW wind project which, allowing for permitting timelines and land access, could achieve ready-to-build status by the end of the year or the first half of 2023. The company is working to secure land access alongside regulatory permits and approvals.
Earlier this year CORO restructured its €22.5m Eurobond, now due to mature in April 2024. The company had cash of $1.6m at the end of H1 2022, supported by the free cash flow from its Italian portfolio and the Vietnam solar pilot, which is expected to be operational later this year. CORO’s share price rose sharply earlier this year after securing the Vietnam PPA, touching 0.5p, but has since subsided to 0.25p, taking the company’s market cap to £5.51m. Prospective investors may want to take a stake in anticipation of a Duyung GSA next year.
Eco (Atlantic) Oil & Gas
Eco (Atlantic) Oil & Gas (AIM:ECO) has significant holdings in some of the world’s most prospective fields in the Atlantic margin basins offshore Guyana, Namibia and South Africa. A major well offshore South Africa failed to find hydrocarbons last month, hammering the company’s share price. But there is more to ECO than that.
An updated CPR published earlier this year indicated 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. The company is most closely associated, perhaps, with its 15pc interest in the 1,800km2 Orinduik Block Operated by Tullow Oil in the shallow waters of the Guyana-Suriname Basin off the north coast of South America. With untapped resources of 13.6 billion barrels of oil and 32 trillion cubic feet of natural gas, the US Geological Survey ranks it 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, Orinduik Block offers 22 prospects, with 11 leads in the Upper Cretaceous horizon, most having a 30pc or better chance of success. ECO has an interest in another prospect offshore Guyana, the Canje Block directly adjacent to the Exxon-operated Stabroek Block, through a 6.4pc holding in JHI Associates, which has a 17.5pc interest in the Block.
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 is the majority stakeholder and operator of four Namibian licence blocks spanning 28,593km2 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.
Earlier this year ECO signed a Memorandum of Understanding to acquire the offshore asset portfolio of the Azinam Group, increasing the company’s interest in the four blocks to 85pc. The agreement also gives ECO a stake in the Orange Basin offshore South Africa, through respective 50pc and 20pc interests in Blocks 2B and 3B/4B. 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 250kms 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 17,581km2 and lies in water depths ranging from 300 to 2,500 metres. ECO signed a farmout agreement earlier this summer with Azinam to acquire an additional 6.25pc interest in Block 3B/4B, increasing the company’s stake to 26.25pc.
There was disappointment last month when Block 2B’s Gazania-1 well reached its target depth of 2,360 metres but failed to show evidence of commercial hydrocarbons. The venture partners, which had believed the well had the potential to establish a 300 million barrel light oil resource, will now move on to executing our plans for more exploration wells, including a two-well campaign on Block 3B/4B offshore South Africa planned to begin in 2023, and at least one well into Cretaceous targets on the Orinduik Block offshore Guyana. As announced by the Operator of Block 3B/4B, a collaborative farm-out process, up to 55pc gross working interest, has been ongoing. ECO said that while ‘it is naturally disappointing not having made a commercial discovery, the Gazania-1 well was only the first of four wells we have planned for the next 18-24 months across our wider portfolio.’
Elsewhere, ECO continues to assess options for progressing exploration and commercial activity on its Namibia acreage, and, together with its venture partners, is drawing up plans to drill at least one well into light oil Cretaceous targets in the next exploration phase at the Orinduik Block, which begins in 2023.
ECO’s results for the six months to 30 September stated cash of $24.6m and no debt after paying $11.3m – the company’s share of the Block 2B well. It had total assets of $67.3m, total liabilities of $5.7m and total equity of $61.6m. Last month ECO closed the sale of its 100pc interest in the Kozani Photovoltaic Development Project, raising $2.4m, boosting its cash to $17.5m.
After gradually building momentum through the year the company’s share price fell off a cliff last month after the Gazania-1 upset, plunging from 42p to 17.5p in the space of a day, where it has remained, pulling its market cap down to CAD$101m at the time of writing. Prospective investors coming fresh to ECO might regard that as an overreaction: the company has a cluster of other prospects, in South Africa and elsewhere. Perhaps now, while much of the market has turned away, might be the time to take a position.
Europa Oil & Gas
Though Europa Oil & Gas (AIM:EOG) suffered a setback this autumn when a potentially transformative appraisal well at the North Sea Serenity field failed to find the targeted horizon, the company continues to benefit from strong production from its onshore interests.
EOG balances exploration with a cluster of wholly or partly owned interests in producing onshore UK wells in the Humber basin, the most significant being a 30pc stake in the highly productive Wressle licence, where the Wressle-1 well has recorded one of the strongest flow rates in the UK since workover operations last year. The well is expected to easily exceed its current rate of around 800 bopd once current production restrictions are removed. The venture partners are currently focused on advancing a development plan to enable production from Wressle’s Penistone Flags reservoir, where gross mid-case contingent resources of 1.53 million barrels of oil and 2 billion cubic feet of gas are estimated.
The company’s 100pc owned West Firsby licence is also notable. Although only producing around 40 bopd, and late in its productive life, the field has been identified as an ideal candidate for geothermal production. EOG has entered into a MoU with Causeway Geothermal to assess West Firby’s potential as a geothermal test and commercial deployment project. The company has a pair of wholly-owned wells at Crosby Warren, producing around 30 bopd, and a 65pc non-operated interest in the Whisby W4 well, which produces 30 bopd net to EOG.
EOG also has exploration interests in the east Midlands, notably a 50pc interest in PEDL181, and a 30pc stake in Broughton North, a fault block immediately to the northwest of Wressle, which rated as having a relatively high geological chance of success of between 40pc to 49pc, and gross mean unrisked prospective resources of 0.6 million boe. It has a 25pc stake in Hardstoft, adjacent to the UK’s first ever exploration well in a historic field first drilled back in 1919, with gross 2C contingent resources of 3.1 MMboe and gross 3C contingent resources of 18.5 MMboe that the application of contemporary drilling technology may be able to unlock. EOG also has a 35pc stake in Cloughton, a gas appraisal opportunity in the Cleveland Basin on the coast north of Scarborough.
The company’s interests extend beyond the UK to the Inishkea prospect in the Irish Atlantic Margin, a Triassic gas hydrocarbon play estimated as having gross un-risked prospective resources of a mean 1,528 billion cubic feet (high estimate 3,606). Gas infrastructure is already present at the nearby Corrib gas field, opening possibilities for a fast track path to commercialisation. The licence includes the Corrib North structure containing the 18/20-7 gas discovery well drilled by Shell in 2010, where a wide range of gas initially in place has been identified.
Though EOG continues to develop the full range of its interests, the company’s news this year has been dominated by the tantalising prospect of a transformative appraisal well at Serenity, a North Sea field in which it acquired a 25pc interest this April,raising £7m to pay for its share of the cost of funding the £14m well, a big commitment for a company with an £10m market cap. But the prospect is undeniable. A discovery well in 2019 drilled by operator i3 Energy found 31.7o API oil, matching the oil from the Tain, Blake and Liberator fields, allowing i3 to publish a P50 estimate of 197 MMbbls STOIIP (Stock-Tank Oil Initially In Place). The appraisal well was drilled this summer, designed to prove up additional volumes of hydrocarbons beyond those encountered in the original discovery well, which EOG estimated as having a gross value of more than $1bn, assuming a 35pc recovery factor.
So it was an undeniable let down when the well failed to fulfil that promise, EOG announcing that the well had not encountered the anticipated horizon. The one silver lining was that the expense was considerably lower than anticipated, costing £10.4m, with EOG’s share £4.8m. EOG said that although it was ‘a disappointing result the data gathered during the drilling of SA02 has improved our understanding of the Serenity field and we continue to interpret the well data which will help us establish a suitable development plan to maximise the value of the already discovered resources within the eastern area of the Serenity field.’
That financial cushion is in large part due to ongoing strong performance at Wressle. Pressure test analysis has indicated that unconstrained, Wressle-1 could produce approximately 1,200 and 1,500 bopd, and regulators have granted permission for a revised Field Development Plan to allow export of the gas into the local gas distribution network, thereby allowing the well to flow at unrestricted rates. EOG’s most recent annual report stated increased revenue for H1 of £6.6m (2021: £1.4m), a pre-tax profit of £1.4m (2021: pre-tax loss £0.85m), and cash of £8.3m (2021: £0.9 million).
Unsurprisingly EOG’s share price has been knocked back by the anticlimax at Serenity, standing at just over 1p at the time of writing, down from around 3p prior to the announcement. EOG continues to depend on Wressle’s strong performance but prospective investors might want to keep an eye on continued efforts to realise Serenity’s potential.
2022 has been something of a year of two halves for UK gas operator IOG (AIM: IOG).
The company achieved a major strategic milestone early in the spring, beginning the commercialisation of its Saturn Banks infrastructure in the Southern North Sea with first gas at the Blythe, Elgood and Southwark fields. But in the past few months it has had to work hard to reassure investors regarding a number of operations difficulties. Recent updates indicate that the issues are receding, and that the company, which holds it licences 50:50 with joint venture partner CalEnergy Resources, is looking ahead to Phase 2 of the project, which will seek to commercialise the Nailsworth, Goddard and Elland gas discoveries, all subject to future investment decisions.
Blythe and Elgood were successfully brought onstream in mid-March, achieving gross aggregate production of 34.0 mmscf/d from First Gas to 30 June 2022, and helping IOG to H1 revenue of £30.2m (H1 2021: $0) , EBITDAX of £25.9m (1H 2021: £0.1m), a post-tax profit of £11.4m (H1 2021: £0.2m), and cash of £12.3m. A GSA was signed with off takers BP covering the Blythe, Elgood, Southwark, Nailsworth and Elland fields up to at least September 2023.
And significant progress is being made towards first gas at Southwark, the Phase 1 field with the largest production profile, targeted for Q4 2022. A pipeline has been installed, and a production well is being drilled. After Southwark IOG plans a major appraisal campaign: a south-eastern extension of the Goddard discovery in the north of the company’s portfolio will be assessed to test potential for a larger field development; and the Kelham North and Central structures will be targeted through a dual lateral well, aiming to prove up a potential three-field gas hub with the existing Abbeydale discovery. The company will also begin implementing Phase 2 of the Saturn Bank Project, including Nailsworth and potentially other nearby assets. Once Southwark is onstream, the two appraisals are drilled and Phase 2 progressed, the company will be in a position to review the refinancing strategy for a €100m bond maturing in September 2024.
All good: but operations issues forcing restricted production over the summer triggered investor concern regarding the impact on the company’s finances. Onshore liquids handling issues at a terminal connected to the Saturn Bank infrastructure required a week of downtime in late May, and unexpectedly high and saline produced water obliged the company to alternate production at the Blythe and Elgood wells, and to reduce its H2 gross production guidance from 45-60 mmscf/d to 30-50 mmscf/d.
IOG’s most recent operations update, published last month, said that production has been restarted from both Blythe and Elgood into the Saturn Banks Pipeline System as planned after completion of shutdown works, and that gas sales were expected to recommence today following full re-pressurisation of the line. ‘Additional modifications’ have been completed at the Bacton terminal to de-risk potential for future shutdowns. The update reported on progress regarding Southwark drilling, where hydraulic stimulation operations are underway and expected to continue into December, with first gas remains expected ‘around year end’, subject to stimulation progress and operational risks to final hook-up and commissioning. The company has also sought to ensure investors regarding its capacity to cope with any associated hit on its revenues, declaring a cash position as at 20 October of £36m, and commenting that its ‘internal modelling projects corporate cash flows in a range of risked scenarios, including lower production outturn versus forecast, longer than planned downtime and gas prices materially below the prevailing forward curve. In the current outlook based on these scenarios, no short-term incremental funding need is anticipated.’
IOG’s share price has reflected the company’s shifting fortunes, peaking at 43.5p in March before declining to around 16p at the time of writing, taking its market cap to £84.6m. At this relatively low price IOG may well be worth following in 2023, a new entrant to a UK market in dire need of native gas.
Founded three years ago with the aim of developing a full-cycle Norweigan North Sea exploration and production company through mergers and acquisitions and near-field exploration, Longboat Energy (LON: LBE) has been one of this year’s more interesting trades, twisting and turning in response to mixed news from the company’s growing portfolio of interests.
Over the past 18 months LBE has entered into a series of ventures with partners including Equinor, Spirit, Idemitsu and OMV to secure interests in nine, gas-weighted exploration wells on the Norwegian Continental Shelf close to established infrastructure. Drilling over the past year has yielded five discoveries with a respectable two-thirds success rate.
Drilling at the Egyptian Vulture, Rødhette and Kveikje projects got underway last year, uncovering three discoveries representing an estimated 12 MMboe of resources net to LBE, allowing the company to investigate multiple commercial opportunities. The company has a 15pc interest in the Egyptian Vulture discovery, which a CPR estimates to contain a gross 4-68 MMboe. A discovery last October at Rødhette, in which LBE has a 20pc interest, is estimated to hold gross oil and gas resources of between 9 and 12 MMboe. Another significant discovery was made in April at Kveikje, located close to the giant Troll field with significant infrastructure and multiple tie-back opportunities. Several third-party discoveries have been made close to Kveikje – in which LBE has a 10pc stake – during the last few years, where estimates indicate a preliminary recoverable gross resources of 28 to 48 MMboe.
But there was disappointment in June when the Cambozola exploration well, in which the company had a 25pc interest, found nothing, and in September, when the Copernicus prospect in the Vøring Basin, estimated to contain gross mean prospective resources of 254 MMboe, 25 MMboe net to LBE also drew a blank.
LBE has farmed into a separate venture with Austrian multinational OMV focused on two gas weighted exploration prospects targeting combined gross unrisked mean prospective resources of 223 MMboe (45 MMboe net). The deal included a 20pc interest in Oswig, investigating a high pressure, high temperature Jurassic rotated fault block with a pre-drill gross unrisked mean resource of 93 MMboe, one of the larger gas prospects being tested in Norweigan waters this year. Several additional fault blocks have been identified on-block which could contain further gross unrisked mean resources of 80 MMboe. Oswig is an analogue to Equinox’s nearby Tune field, which has produced around 140 MMboe over the past 20 years.
Drilling this autumn targeting has been a qualified success, initial exploration indicating ‘excellent correlation with the nearby Tune field’, with ‘preliminary gas in-place volumes (GIIP) in the Tarbert formation higher than the overall pre-drill expectations’, paving the way for a decision to drill a sidetrack well and perform a drill stem test (DST). Those operations, reported in November, were, by the company’s own admission, ‘at the lower end of pre-drill expectations ’, but sufficient to confirm a discovery.
The Oswig sidetrack, drilled to a depth of 4,726 metres to allow testing of the Upper Tarbert Formation, encountered a gas/condensate column of about 100 metres with no gas-water contact, ‘a well-defined structure with excellent quality gas and high condensate content.’ Average production of approximately 650 boepd during the DST period yielded of 2.1 MMscfd of gas and 280 bpd of condensate. A preliminary estimate indicates recoverable resources of between 10 and 42 million boe (gross) based on in-place volumes of 100 to 215 million boe and a condensate/gas ratio of 110-130 bbl/MMscf. The venture partners are evaluating the discovery’s potential with a view to setting the location of further appraisal drilling and well configurations, whether horizontal, multilateral or fracked. Drilling at the other OMV gas-condensate prospect, Velocette, in which LBE has a 20pc interest, is planned next year. Focused on Cretaceous Nise turbidite sands located within tie-back distance to the established Aasta Hansteen gas field, Velocette promises gross unrisked mean resources of 130 MMboe, with 26 MMboe net to LBE.
LBE’s most recent update estimated the company’s unaudited, year-end 2022 cash position will be approximately £9m. Current drawings under its Exploration Finance Facility (EFF) are £44m and will be repaid fully from its Norwegian tax rebate due in November 2023. LBE has agreed terms with its lending banks to increase the EFF to £65m and extend the availability period to the end of 2024 to finance the company’s drilling programme in 2023 and beyond.
LBE is positioned in a Norwegian North Sea industry that has replaced Russia as Europe’s biggest supplier of gas, becoming a significant seller of oil and electricity across the continent and the UK. Norway’s oil and gas sales had already reached record levels when the energy crunch began to bite last year, and rose ever higher in the wake of Ukraine. With the country’s gas supplies to Europe rising 10pc this year the Norwegian government has even mooted the possibility of introducing a price cap.
The company’s hit-and-miss record this year has been reflected in the company’s share price, which hit highs of 75p in April after strong results from Kveikje, but tumbled all the way to 33p by August in the wake of disappoint at Copernicus and Cambozola. Back to 47p going into November, the price fell away again to 17p moving the company’s market cap back up to £9m at the time of writing. Value triggers on the horizon include the prospect of further announcements regarding Egyptian Vulture, Rødhette and Kveikje, continuing operations at Oswig, and the (longer term) prospect of exploration at Velocette.
Nostra Terra Oil and Gas
Nostra Terra Oil and Gas (AIM:NTOG) an exploration and production company developing a set of low risk, producing assets in three different Texas basins, continues to work patiently to capitalise on surging demand for native US hydrocarbons.
NTOG’s assets in East Texas include 100pc ownership of Pine Mills, a 2,400 acre field which has produced over 12 million barrels of oil since its discovery in 1950s. Two years ago the company farmed out an undrilled portion of the acreage to Cypress LLC, retaining a 32.5pc interest, and carrying a 25pc interest in the first well drilled. Put into production early last year, Fouke #1 reached payback in five months and has continued to produce without decline. NTOG also has stakes of between 50pc and 100pc in the West Texas basin, accounting for 11pc of the company’s sales last year, and 100pc ownership of the producing Caballos Creek asset in South Texas, which contributed 10pc.
The company entered 2022 with plans for the drilling of ‘one new development well in Pine Mills’ and ‘two to three new wells in the Permian Basin’. Operations commenced in January at Fouke #2, targeting the same horizon as its predecessor, and after completion in May the well began flowing at a rate of 145 bopd. In August NTOG reported that Fouke #2 had reached payback (recovery of all drilling and drilling-related costs from net cashflow) within three months from production start-up, considerably ahead of pre-drill expectations due to a combination of higher realised oil prices and a production rate 70pc more than originally forecast. Production remains at 140 bopd, experiencing no decline since start-up and is 100pc oil. Fouke #1 was also producing 100pc dry oil at a rate of 110 bopd, the maximum supported by the current surface production equipment. Discussions were underway with Fouke wells’ operator on a third well in the farmout area.
This year NTOG also began drilling at the Grant East lease at West Texas, pursuing a drilling and development plan focused on eight well locations, with the potential for eight more across the 160 acre site. Three permits have secured so far. The first well, Grant East #1, was intended to test the area’s producing Clear Fork (primary) and San Andres (secondary) formations, which NTOG believes have ‘the potential to be a bigger contributor to the Company’s net production than Pine Mills’. The programme suffered an initial setback when the well was ‘temporarily abandoned’ after encountering water. NTOG said that although the result ‘isn’t what we wanted’ there are ‘still 15 viable drilling locations within the Grant East Lease and the information obtained from the Grant East 1 well will be used to improve and optimise future completions.’ Analysis will inform the completion procedures of subsequent Grant East wells, which will be funded from existing resources.
NTOG’s progress at Pine Mills allowed the company to report a 34pc increase in production for H1, to 20,383 barrels oil (H 12021: 15,211 barrels), and average H1 production of 112 bopd (2021: 84 bopd). The company’s interims to 30 June stated a 108pc increase in revenue for the period to $2,003,000 (H1 2021: $963,000), and a 381pc increase in gross profit from operations for the period to $1,203,000 (H1 2021: $250,000 profit).
NTOG went on to issue a robust operations update in September, reporting a 33pc increase in Q2 revenue up to $1,141,739 (Q1 2022: $810,699), the highest quarterly revenue in the company’s history. Q2 average net daily production was up 22pc to 125 bopd (Q1 2022: 102 bopd), and the Q2 oil sales price was up 7pc to $98.28. The company’s increasing asset value allowed it this month to announce a significant expansion in its Senior Lending Facility, its borrowing base increasing to $4,350,000, 30pc up on the $3,350,000 base in March. The company’s future net income is projected at $34,350,110, a 6pc increase from March, and its NPV10 is up to $17,196,390, an 18pc increase.
NTOG, then, seems in the right place at the right time. It’s worth noting that the company has referenced a possible new opportunity in Tunisia, ‘a large block with existing discoveries, offering both exploration and appraisal activity’ for which the company ‘has negotiated terms and is waiting final approval’. But right now its focus is on continuing to generate organic growth through maximising the potential of its Texan resources. NTOG’s share price has fallen to around 0.25p at the time of writing, taking its market cap to £1.94m, the setback at Grant East knocking it back from highs of 0.7p touched in May. With the prospect of stable and increasing production at Pine Mills, further exploration at Grant East, and robust oil prices, NTOG may be worth a look at this price.
Union Jack Oil
The price of UK-focused oil and gas producer Union Jack Oil (AIM:UJO) has nearly doubled over the past 12 months, the outstanding performance of the Wressle licence in which the company holds a 40pc stake driving surging revenues allowing it to move into profit for the first time.
UJO has interests in a cluster of producing and exploratory assets in and around the UK’s Humber energy hub, home to a web of world-scale chemical and oil refinery operations. The most lucrative is its two-fifths holding in Wressle’s PEDL180 and PEDL182 fields, both operated by Egdon Resources. What proved to be highly effective coiled tubing operations last August at the Wressle-1 well kickstarted flow rates of nearly 900 bopd, well above pre-production expectations of 500 bopd despite a choke setting constrained by the 10 tonnes per day gas incineration boundary set by the operation’s current Environmental Agency permit. Analysis of bottom hole pressure data indicated that once the field’s surface facilities are optimised the well could flow at rates of 1,200 to 1,500 bopd. The well also produced 480,000 cubic feet of gas per day, indicating a hydrocarbons potential rivalling the prolific Wytch Farm in Dorset. An application to integrate Wressle into the local gas distribution network – and thereby remove production restrictions – was approved earlier this summer by the North Sea Transition Authority (NSTA). The project is scheduled for completion towards the end of the year, in time for gas sales next winter.
The performance of the well, which has produced more than 225,000 barrels of oil with no water cut, has supercharged UJO’s finances. The company’s most recent interim report reported soaring revenues for H1 2022, up from £241,467 to £4,384,254, facilitating a maiden profit of £2,034,086. Last month UJO said revenues generated since the Wressle workover had topped $11m, moving the company’s cash balance above £10m.
Unsurprisingly, perhaps, expectations were sky high for a Wressle Reserves and Resources Report commissioned from energy consultancy Gaffney, Cline & Associates, which stated that the licence’s Ashover Grit and Wingfield Flags reserves (as at 30 June 2022) stood at 1P 320,000, 2P 670,000 and 3P 1,030,000. A ‘Speculative Deeper Oil-Water Contact’ assessment of Ashover estimated an increased STOIIP (Stock Tank Oil Initially in Place) of 10.12 million barrels of oil (MMBbl) and a recoverable resource of 2.43 MMBbl. An Illustrative Production Scenario indicated a five year constrained plateau production rate of 800 barrels of oil per day. Though the report was, as expected, positive, some investors unsure how to assess the highly technical content. But UJO insisted that, should ‘the Deeper Oil-Water Contact potential of the Ashover Grit reservoir become proven, the incremental value of Wressle as a development would be transformational for the Wressle partners.’ Last month the company reported on positive progress with a two-stage gas utilisation scheme to enable the oil production limit at Wressle to be lifted. The site diesel generator will be replaced with a gas microturbine for site electrical power before a separate gas engine is installed to generate and export up to 1.75 MW of electricity into a local private power network. Installation of the microturbine will be ‘completed by year end’.
Wressle has, understandably, been at the forefront of investors’ minds this year, but UJO has reported significant developments regarding the company’s other major interest, its 16.665pc stake in the WNA-1, WNA-2 and WNB-1z discoveries at the PEDL183 field in West Newton, majority owned by Reabold Resources. The wells are on-trend with the established offshore Hewett gas complex, and target Permian Basin carbonates analogous to those extensively explored and produced onshore in the Netherlands, Germany and Poland. Extended well testing undertaken last year reported ‘substantial hydrocarbon discoveries’ within the prospect’s Kirkham Abbey formation. Gas and light oil/condensate was recovered to surface from both the field’s WNA-2 and WNB-1z wells, and multiple samples gathered for analysis. Best estimates of the reservoir’s in-place oil and gas volumetrics indicate thicknesses of 68 to 75 metres at depths of around 1,700 and 1,800 metres.
A conceptual development plan, to be tested by an appraisal well planned for H1 2023, envisages a phased eight well gas development that will target recoverable hydrocarbon volumes of 35 million boe with a sales gas component of 203 Bcf. An initial five well development drilling campaign, with first gas anticipated as soon as 2025, estimating plateau production rates of 44 Mcf per day of sales gas. A CPR estimates ‘Best Case Gross Unrisked Contingent Technically Recoverable Sales Gas’ at West Newton at 197.6 Bcf, with an unusually high geological chance of success of 85.5pc. The gross NPV10 risked value of the contingent gas resource was set at $396.1m.
UJO has interests in several other projects, most of them, like Wressle, operated by Egdon. The company has a 45pc interest in the PEDL253 field at Biscathorpe, situated within the proven hydrocarbon fairway of the South Humber Basin, and on-trend with the Saltfleetby gasfield prospect. It has a 55pc stake in the PEDL005(R) field at Keddington, located along the prospective East Barkwith Ridge, an east west structural high on the southern margin of the Humber Basin, and currently producing from Carboniferous Westphalian sandstone reservoirs. The company also has a 50pc interest in the PEDL241 field at North Kelsey, a conventional oil prospect along trend and analogous to the Wressle oil development. UJO expanded its portfolio into the North Sea last year by taking a 2.5pc interest in the Claymore Piper Royalty Complex, which has so far produced more than 1.8 billion barrels of oil and 262 Bcf of gas.
The company has a speculative interest in fracking through its ties with Egdon Resources, which holds a material shale-gas acreage position in Northern England covering a net area of 664km2 with estimated mean volumes of undiscovered gas in place of 37.6 trillion cubic feet of gas. Though the industry flickered briefly into life when the short-lived Truss administration said it would review fracking’s status, the door seems to have been closed by new PM Rishi Sunak. Keir Starmer’s Labour has long favoured a complete fracking ban.
UJO’s share price has doubled this year to 27p at the time of writing, taking its market cap to £31m. It’s worth noting even that is will down on the 50p peak reached in September prior to the Wressle Reserves and Report. So, with Wressle continuing to go strong, and other prospects on the boil ready to serve a vibrant UK market, UJO’s shares could rise again next year. Indeed he company has felt confident enough this year to issue a Maiden Special Dividend of 0.8p and implement its first share buyback programme.