WTI $70.49 +35c, Brent $74.36 +44c, Diff -$3.87 +24c, NG $4.81 -18c, UKNG 180.56p -6.57p

Oil price

A modest rally yesterday and this morning is another dollar+ better as the API inventory stats showed a 6.1m drop in crude stocks. The EIA numbers later today will be equally important if still somewhat distorted by hurricane Ida which has led to production and refining shortages.

On the subject of the weather there are two Tropical Storms in the Atlantic, Peter is headed towards Puerto Rico and Rose is also revving up right behind.

The FOMC meeting finishes today and many commentators are expecting some sort of what might be called taper teasing, what that will entail is uncertain but one way or another I’m sure by Christmas we will know one way or another.

Jersey Oil & Gas

Jersey Oil & Gas has announced it’s unaudited Interim Results for the six month period ended 30 June 2021. They show a material increase in resource estimates for the Buchan oil field following completion of extensive reservoir simulation modelling. 

Contingent P50 technically recoverable resources for the Buchan oil field are now estimated at 126 MMstb whilst contingent P50 technically recoverable resources for the Greater Buchan Area Core Area (Buchan, J2 and the Verbier discoveries) increased to an estimated 172 MMboe.

The Concept Select Report has been completed and submitted to the UK’s Oil and Gas Authority (“OGA”). The detailed report sets out a three phase development, with Phase 1 designed to develop the Buchan oil reservoir; Phase 2 the J2 West, J2 East and Verbier East oil discoveries; and Phase 3 the Verbier West oil discovery (the “GBA Development”).

The report also includes JOG’s preference for the GBA Development to be powered by electricity, which would significantly reduce the carbon emissions associated with production from the GBA Development.

JOG completed an oversubscribed placing and subscription to raise, in aggregate, £16.6m gross. In addition the acquisition of the remaining 12% interest in licence P2170 containing the Verbier discovery from CIECO V&C (UK) Limited to bring our interest to 100% across all of the GBA licences was completed. 

The appointment of Les Thomas to the Board as a non-executive director was in my view a  smart move bringing further experience to the board. Crucially, JOG launched the sales process to farm-out an interest in their GBA licences to secure an industry partner and funding towards the future share of costs in the development. 

The company has a very strong cash position of approximately £17m at the period end and since the year end an offshore survey to acquire geotechnical and environmental baseline data was completed. A technical and economic evaluation of P2497 (Zermatt) and P2499 (Glenn) licences has been completed, with JOG electing not to progress to the next licence phase and relinquish these non-core licences.

Finally, the OGA has approved JOG’s application to be the ‘Installation Operator’ for the ‘Design Phase’ of the planned Buchan platform. JOG say that the farm-out process is ongoing and that they are engaged in discussions with both industry parties and potential infrastructure funders.

JOG report that regional electrification collaboration within the Central North Sea is building momentum amongst industry parties, with the GBA ideally located to be an integral part of this initiative.

Andrew Benitz, CEO of Jersey Oil & Gas, said:
“The first half of 2021 has been a busy period for JOG.  Extensive reservoir modelling was completed leading to a significant increase in management’s estimates of the GBA’s resources and the delivery to the OGA of the GBA Concept Select Report, which includes our preference for a fully electrified platform.  The OGA’s approval of the appointment of JOG as OSD Installation Operator represents a significant endorsement of our capabilities and competencies to deliver GBA facilities of the highest technical integrity that will be both safe to operate and environmentally sound.

“Our GBA farm-out process was launched and is ongoing, with active engagement with both industry parties and infrastructure funders, the latter having expressed funding interest particularly with respect to electrification of the development and the potential regional collaboration opportunities that exist. We also launched our Carbon Policy and are targeting ‘Net Zero’ emissions from our GBA Development project at the start of first oil.

“I would like to thank shareholders for their ongoing support and look forward to providing further updates on our future progress.”

Jersey’s mammoth task in taking on the GBA development is really beginning to show that all systems are go and that the project is a meaningful facility with state of the art low carbon infrastructure. This report will give encouragement to shareholders who have seen the potential of the Buchan field unfolding and brings it another stage closer.

IGas Energy

Interims from IGas today produced revenue of £16.6m (10.5m), adjusted EBITDA of £2.7m (2.2m), giving a loss of £12.2m (loss 30m). Operating cash flow was £6.4m (1.4m), net debt was £13.2m (11.2m) leaving cash of £2.8m (2.6m).

Net production averaged 2,005 boepd in H1 2021 (H1 2020: 1,940 boepd) with operations, maintenance and project activities all being directly and indirectly impacted by COVID-19.  Excluding the total COVID-19 impact in H1 2021, which averaged c.180 boepd, production in H1 2021 would have been 2,185 boepd.

Full year net production is now forecast to be c.2,000 boepd, with underlying cash operating costs per boe anticipated to be c.$38/boe (based on an exchange rate of £1:$1.39).

IGas as one of the sector’s leaders in the space, have made material progress on deep geothermal activity with planning approval received for  Stoke-on-Trent and MoU with SSE to deliver the heat network. In addition there have been constructive discussions with Government in respect of downstream financial support. In addition, there has been a geothermal Ministerial roundtable and a Westminster Hall Debate – on ‘Opportunities for geothermal energy extraction.’

An MoU has been signed with CeraPhi to jointly develop geothermal energy projects which repurpose and utilise IGas’s existing wells and other infrastructure and use CeraPhi’s patented technology, CeraPhiWell, a closed loop downhole heat exchanger.

IGas has also moved on small scale distributed hydrogen with  ‘significant Government support’ and the planning applications for the Albury and Bletchingley hydrogen projects have been submitted and validated by Surrey County Council.

A full CPR was published in February 2021: 2P reserves replacement ~ 250% (1P ~275%) and 1P NPV10 of $150 million: 2P NPV10 of $204 million.

Commenting today Stephen Bowler, Chief Executive Officer, said:
“The health, safety, societal and economic impacts of the COVID-19 pandemic have presented a unique set of challenges for our production business.  Despite these challenges, production remains robust. We continue to focus our technical and operational expertise on offsetting the underlying natural decline in our fields through the execution of incremental production opportunities that demonstrate commercial benefit via our delivery assurance processes.

The Group’s existing operational expertise as the UK’s largest onshore operator gives us the opportunity to use our existing business platform to play an important role in the UK’s transition to net zero. Our sub-surface expertise is relevant both to drilling for geothermal resources, and assessing the potential for carbon capture and storage.  We have extensive experience of dealing with onshore regulators and planning authorities. We have predictable operating cash flows to help fund new initiatives and assets to repurpose in a readily accessible onshore environment.

We have progressed our low-carbon projects during the period. We have submitted planning applications to produce hydrogen from two existing sites in Surrey – Albury and Bletchingley.  Should we be successful in developing these blue hydrogen projects, IGas is on track to produce the UK’s first blue hydrogen ahead of other, refinery scale projects.  This demonstrates that small-scale, distributed hydrogen production will allow blue hydrogen to be offered to the market rapidly and will build resilience into new energy networks.

In geothermal, the Stoke-on-Trent project could be the first in a new generation of British-backed heat plants. It will support the decarbonisation of heat, move us along the path to net zero and help tackle climate change.  Whilst we await the necessary Government support for the Stoke-on-Trent project, we are receiving an increasing number of enquiries from local councils and other large-scale users of heat.

We believe there is significant commercial potential for geothermal energy production and the development of localised hybrid energy systems generating both heat and power.”

IGas is continuing to do well with its traditional business ironically doing pretty well given the oil and gas prices. But IGas is moving fast to diversify into ‘the wider UK energy market whilst leveraging our core competencies as a UK onshore operator’.

As experts in the UK onshore with landowner and community relationships, as well as the rising profile at Westminster for geothermal and hydrogen gathering pace IGas management certainly can’t be accused of not playing to its expertise.

IGas has performed very strongly recently as its geothermal and hydrogen investments have excited the market and the shares raced past their highs only to fall sharply on profit taking after these figures. To be fair they deserve the higher rating and accordingly investors should make IGas a stock for energy transition onshore UK.

Longboat Energy

Interims of no significance for LBE today but plenty has been going on and at last the drill bit is spinning for the company. They have secured three bilateral transactions to acquire a significant, near-term, low-risk exploration drilling programme on the Norwegian Continental Shelf (“NCS”) which gives them seven firm wells drilling over the next 18 months.

The deal totals net mean resource potential of 104 mmboe with a total net upside case potential of 324 mmboe. Also they completed a £35 million equity raise and NOK 600 million (£50 million) Exploration Finance Facility so are fully funded through the seven well drilling programme.

Qualified as licence holder on the NCS one of only 38 companies qualified on the NCS (versus >130 on the UKCS) and new status removes transaction hurdles, positioning Longboat for further value accretive M&A.

Drilling has already commenced on two exploration wells: Rødhette (Longboat 20%) and Egyptian Vulture (Longboat 15%), Mugnetind (Longboat 20%), expected to commence drilling by the end of September with drilling at Ginny/Hermine (Longboat 9%) expected to commence in December.

A rig is confirmed for Kveikje (Longboat 10%) and Cambozola (Longboat 25%) wells, to be drilled in 2022 and the Copernicus well site survey to be acquired shortly, to facilitate 2022 drilling, following well commitment decision.

Helge Hammer, Chief Executive Officer of Longboat Energy, commented:
“I am pleased that we are already under way with exploration drilling so soon after the completion of our first transactions last month. We expect to be drilling three wells over the next few weeks with the Rødhette and Egyptian Vulture wells already under way and Mugnetind expected to spud shortly, in an extremely busy and exciting time for the Company. Drill results from these first three wells are expected before the end of the year and have the potential to create significant shareholder value.

“The exploration programme over the next 18 months offers shareholders a unique opportunity to gain exposure to a drilling portfolio of seven wells targeting net mean prospective resource potential of 104 mmboe1 with an additional 220 mmboe1 of upside which provides the potential to create a Net Asset Value of over $1 billion based on precedent transactions in the Norwegian North Sea for development assets.”

As I mentioned before Longboat has taken longer than at least the market wanted to get underway but now it really is well placed to do well in its own back yard. There have been problems to overcome not least the tax changes that are happening right now but as explained in some detail at the meeting overall they are not too bad.

At the meeting I felt a really good feeling of confidence from the team and now things are getting going there is much to get excited about. Over the next few months there are a number of really meaningful well results and I’m going to guess that at least some of these will come in and make this a very valuable company indeed, memories of Faroe indeed.

Advance Energy 

Advance has provided an update on the Buffalo project offshore Timor-Leste ahead of the drilling of the Buffalo-10 well. The Buffalo-10 well is on schedule to spud in early November 2021 in shallow water depth of 30 metres, with reservoir depth between 3,200-3,300 metres.

The mid case recoverable volume estimate is 34 million barrels (gross, 2C contingent resource) in the Buffalo field and Buffalo-10 is considered by RISC Advisory to have an 85% probability of confirming a sanctionable development project based on the minimum economic field size.

Buffalo-10 is to be retained as first production well in development program and discussions are underway to seek to facilitate accelerated first production. Equipment currently being mobilised for drilling should confirm a November spud date.

Leslie Peterkin, CEO of Advance Energy, commented:
“Advance Energy is pleased to note from that everything is on track for the Buffalo-10 well to spud in early November.  As noted in this update, the joint venture has been working hard to ensure everything is lined up to enable the safe drilling of this material well for the Company.  The joint venture is confident of Buffalo-10 being both a geological and economic success, and is therefore laying the groundwork to bring the field into production on an accelerated timeline. We look forward to providing a further update to confirm that the rig is in transit to location in due course.”

I am exceedingly excited about the arrival of Advance and looking at the numbers for Buffalo I find it difficult to think of it as anything less than a very real chance of making proper money. Given that RISC Advisory has estimated that the well has an 85% probability of confirming a development, including a 95% chance of technical success I’m trying to see the downside in investing right now.

President Energy

President has announced a drilling and workover update on various of its assets. Puesto Guardian Concession, Salta Province, Argentina the Company has signed a drilling services contract for three firm wells to be drilled at the Puesto Guardian Concession before the end of this year. The contract also includes an option to retain the rig into the New Year for a further two wells after drilling of the third firm well.

This will enable continued drilling in the Concession, should the results from the ongoing seismic reprocessing confirm two additional prospects that have been previously identified.

The first three wells will be drilled in the Dos Puntitas field and the two contingent wells for 2022 in the Pozo Escondido field.
Each well is estimated to cost US$3.5 million and have a drilling time of 45 days with a mean success case initial projected oil production of 40 m3/d (250 bopd).

Site clearance for the first well has begun with the rig due to be mobilised during the first days of October. Drilling of the first well is now expected to commence by the end of the third week in October with drilling of all three wells expected to be completed by the end of the year with the final well in that sequence expected to be on stream in the first part of January 2022.

Triche and Simmons 2 wells, Louisiana, both these wells remain offline as they have for the last three months awaiting workover of the Triche well to reinstate production. The operation of the Triche well is required for the Simmons 2 well to operate, as the Simmons 2 well used the gas produced from the Triche for gas lift.

The Triche well has not performed optimally all year due to the progressive breakdown of the downhole gravel pack in the well used to constrain sand production. The frustrating delay in fixing the problem has been materially exacerbated by the effects of Hurricane Ida which devastated the locality.

A rig is now available, but the Company is awaiting barge availability. It is hoped that the workover will be completed by the end of October and the wells will work at the levels enjoyed last year namely at 300 boepd net to President half being oil. Realisation prices are robust with oil currently at approximately $70 per barrel. Reserves levels are unaffected with lower than expected depletion due to the constrained production.

Peter Levine, Chairman, commented:
“We look forward to the drilling campaign in Salta. With current prices there comparable to Rio Negro and fixed opex already covered by existing production, the incremental production will make a good contribution to Group.

“Louisiana, for various reasons out of our control, has been frustrating for much of this year. However we are close to being back on track. Nevertheless, the events have given management cause to assess the future of our Louisana assets within the Group and we will do so at or around the end of the year once the wells are back online and have been producing for a period”.

KeyFacts Energy Industry Directory: Malcy's Blog