How much of the prize of success is not priced in for Tower Resources
“…The company is ‘looking closely at two possible rig availabilities’, one in this third quarter, the other in the fourth….”
Africa-focused exploration and production group Tower Resources (AIM:TRP) continues to struggle against the tide of exceptional industry conditions to commence drilling an enticing near term prospect offshore Cameroon. But as pressures on oil and gas service providers ease, 2023 may be the year the company is finally able to begin realising the potential of a highly prospective set of licences.
TRP is 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.
The company is led by industry veteran Chairman and CEO Jeremy Asher, who currently also serves as a director of AIM-listed Block Energy, and has held senior positions at companies including Pacific Drilling SA, Gulf Keystone Petroleum Ltd and Oil Refineries Ltd. Previously, Mr Asher ran the global oil products trading business at Marc Rich & Co (now Glencore AG), and played a leading role in the development and sale of the 275,000 barrels per day Beta oil refinery at Wilhelmshaven in Germany, and was also Group CEO at PA Consulting Group.
Near-term production at Cameroon
TRP is seeking near-term production and revenues through its 100pc interest in the shallow-water Thali Production Sharing Contract (PSC), offshore Cameroon. The Thali PSC covers an area of 119.2 km2, with water depths ranging from eight to 48 metres, and lies in the prolific Rio del Rey basin in the eastern part of the Niger Delta. The basin has so far produced more than one billion barrels of oil, and remaining reserves are estimated at 1.2 billion barrel of oil equivalent (boe), mostly at depths of less than 2,000 metres. More than 34.5 billion barrels of oil have been discovered in the Niger Delta, with 2.5 billion boe attributed to the Cameroonian section. The Thali Block has the potential to hold at least four distinct play systems, including two established plays in which three discovery wells (Rumpi-1, Njonji-1 and Njonji-2) have already been drilled.
TRP’s priority is to drill PSC’s NJOM-3 well in the Njonji structure as soon as possible, described by Mr Asher, speaking to TMS last month, as a ‘gateway’ to a much larger development. NJOM-3 will target the contingent resources within the Njonji 1 fault block (and the PS9 reservoir in the Southern Njonji fault block) with multiple objectives: confirming the thickness of the three reservoirs already penetrated by the NJOM-1 well nearer the crest of the structure; checking for oil in four further reservoirs which appear on the seismic interpretation but which were not present at the edge of the structure where NJOM-1 was drilled; establishing flow rates from all the reservoirs; and converting some or all of those contingent resources as well as any other reservoirs encountered into 2P reserves.
TRP believes this will facilitate pre-production funding for the development of the rest of the Njonji structure. A multi-well drilling programme is envisaged, beginning with the drilling of three further production wells with the objective of delivering first oil from the Thali licence in late 2024.
TRP’s efforts to start tapping Thali’s potential have been frustrated by difficulties in securing a rig, complicating funding negotiations. The company’s most recent results attributed the rig delay to challenging circumstances in the energy market over the past 18 months, the Ukraine conflict coinciding with a mass diversion of jack-up rigs to the Arabian gulf, thereby ramping up day-rates for rigs and associated services: jack-up day-rates have doubled since the end of 2021. Unsurprisingly, rig owners have locked in the new higher rates for as long as possible, reluctant to commit to riskier single well contracts.
TRP’s latest Cameroon update, which was published in April, and Mr Asher’s comments in the company’s recently released Annual Report, however, sound a more positive note, indicating that ‘it does now seem possible to fit our drilling requirements within other operators’ schedules.’ Discussions continue with rig owners and operators with the aim of securing rig availability in this year’s third and fourth quarters. The company is ‘looking closely at two possible rig availabilities’, one in the third quarter, the other in the fourth. Mr Asher said: ‘We are finally able to see viable rig slots appearing, and we are now working on the assumption that we will be able to get the NJOM-3 well spudded over the next nine months.’ A final schedule for the well ‘will be transformational for the Company.’
TRP is seeking to raise some $15 million for the drilling campaign through a combination of asset financing in the form of debt or equity, with asset-level financing preferred to issuing corporate level equity. The company says that this could take the form of a combination of bank financing and/or a farm-out, or financial investment in the company’s Cameroon operating subsidiary. Discussions are underway with ‘multiple credible groups’, all of which have signed NDAs and are currently working within the company’s virtual data room.
The April update also included updated resource estimates and risks for the reservoirs connected to the NJOM-1 and the NJOM-2 discovery wells. Detailed attribute analysis of reprocessed 3D seismic data has clarified the oil and gas elements of the reservoirs in the Njonji-1 and Njonji-2 fault blocks, allowing a clearer picture of the pay zones in both fault blocks. The improved risking has allowed an upgrade in risked pMean recoverable resources to 35.4 million barrels. Risked pMean recoverable resources in fault block 1 alone have increased from 10.5 to 12.9 million bbls, those in fault block 2 have increased from 4.1 to 4.9 million bbls, and those in the South fault block are unchanged at 17.6 million bbls.
TRP continues to receive solid support from Cameroon’s government for the venture. Last month the Prime Minister of Cameroon informed the company ‘that he has given instructions to the Minister of Mines, Industry and Technological Development requiring him to take necessary measures in order to accelerate the license extension process in response to the Company’s request.’
Progress at Namibia
TRP has also recorded progress offshore Namibia, where it has an 80 per cent operated interest in licence PEL 96 covering Blocks 1910A, 1911 and 1912B, spanning 23,297 km2 of the northern Walvis Basin and Dolphin Graben, 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.
Over the past year the company has undertaken encouraging basin modelling simulations within PEL 96 which have ‘significantly progressed … understanding of the hydrocarbon prospectivity of the license.’ The integrated analysis of the seismic, wells and the basin modelling results show ‘clear evidence of a working petroleum system’ present within the Dolphin Graben in PEL 96. TRP is currently undertaking an oil seep analysis to accompany the basin modelling work, and is reviewing the existing volumetric data on the prospects and leads that have already been identified.
Mr Asher said: ‘The conclusions indicate the potential for either of the giant billion-barrel-plus structures in the West of the license to be charged; furthermore, the migration pathways, coupled with the recent impressive industry successes in drilling stratigraphic plays in the Orange Basin to the South, enhance our interest in the similar stratigraphic leads that we interpret on the flanks of the Alpha Prospect structure in particular.’ The company’s next steps in Namibia include an oil seep analysis to put together with the basin modelling and possibly some further attribute analysis, to prioritise leads already identified in the licence area and to reassess their likelihood and expected volume of charge, allowing identification of the optimal area for the acquisition of new 3D seismic data.
TRP has a 50 per cent 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 true hydrocarbon prospectivity of the basins covered by the licence was largely unexplored by drilling until Total’s successful 2019 and 2020 wells in the Outeniqua basin, which intersects the deep-water section of the licence area. The other historical wells in the Algoa-Gamtoos area were in the shallower-water basins and drilled over 25 years ago, and all were located using sparse 2D seismic data and either failed to intersect valid closure and/or encountered only modestly developed reservoir sands. Many of the old wells did, however, encounter shows, residual hydrocarbons, and/or penetrated stacked wet gas to oil-prone shale source sequences. 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’s co-venturer and operator NewAge has based its assessment of this Outeniqua basin lead on 2D seismic data which includes continuous lines intersecting Total’s Brulpadda and Luiperd discoveries, and is continuing to explore options for acquiring new 3D seismic data over that lead, negotiating with potential contractors for data acquisition on either a proprietary or a multi-client basis. NewAge has also continued to explore farm-out options for the Algoa-Gamtoos block and discussions with interested parties continue.
TRP’s most recent results stated a cash balance to 31 December 2022 of $231,000 (2021: $10,000), but it has raised significant amounts of funds already this year: a January institutional placing with Energy Exploration Capital Partners, a US-based institutional investor, raised $1.25 million, and a public placing in May took in a further £2.3m, supported by a £50,000 investment from Mr Asher. The money will fund work programme commitments in Cameroon, Namibia and South Africa, as well as general working capital. The company’s efforts to manage costs are facilitated by technical-subsurface relationships with EPI and well design and management suppliers Bedrock Drilling.
TRP’s share price has bumped along below 0.5p over the past few years as it has travelled the long road of clarifying its prospects, negotiating a suitable rig contract, and securing funding. The company’s stock was 0.04p at the time of writing, and its market cap £3.6 million, which is a small fraction of the $305 million NPV10 of the company’s Cameroon project alone, according to the company’s June 2022 presentation of the license.
Why, then, is TRP’s market cap so low relative to the expected value of the projects? The company’s difficulties in securing financing for the NJOM-3 well have clearly weighed on market sentiment, seeding doubts that the company will be able to finance the well, or the rest of the development, on reasonable terms, thereby diluting or eliminating the asset’s value. TRP is also swimming against the prevailing tide of scepticism among AIM investors regarding small cap exploration licences, Namibia and South Africa being historically considered frontier exploration areas.
Commenting in TRP’s latest annual report, Mr Asher acknowledged that ‘it has been a frustrating time for all shareholders, as we would all have liked to see the NJOM-3 well drilled already’. But the company continues to stress the steadfast support of the Cameroon government for the project, and notes the recent success enjoyed by TotalEnergies in South Africa with its Brulpadda and Luiperd wells in the Outeniqua basin, and in Namibia at Venus-X1, which, together with Shell’s breakthrough in Namibia with its Graff-1 well, ‘all indicate that in Namibia and South Africa we have chosen promising countries for our exposure to high risk, high reward exploration’. Elsewhere, Eco Atlantic has demonstrated that capital can be raised at reasonable valuations for Atlantic margins exploration.
Prospective investors might also consider that TRP need only achieve partial success in Cameroon to generate significant value. A 10pc chance of delivering the project, or a 10x dilution, would still give substantial upside on the shares. How much of the risk of failure is already priced into the company’s present value – and how much of the prize of success is not priced in? As developments at Thali unfold TRP is one to watch closely this year.