Angus Energy Share Discussion Threads

[officerdigby] 29/6/2022 20:02

Is hedging do e with totally after September?Many thanks.

[officerdigby] 29/6/2022 20:01

Ok, someone tell me why is there the hedging? . Some unpaid debt or something like that? Part of some deal Because, as it is, it is lot if revenue lost. Who is getting the benefit? / The other side of the hedge?Thanks!

[chickbait] 29/6/2022 19:52

Seems like yesterdays 1st gas RNS is already priced in. Also, the market does not to like the fact of the hedge kicking in before 1st gas!

Market Summary
>
Angus Energy PLC
1.20 GBX
-0.12 (-9.09%)past 5 days
29 Jun, 18:36 BST • Disclaimer

[chickbait] 29/6/2022 19:46

3Put28 Jun '22 - 12:36 - 60 of 70
0 3 0
Here we go

Market Summary
>
Angus Energy PLC
1.20 GBX
-0.12 (-9.09%)past 5 days
29 Jun, 18:36 BST • Disclaimer

[shooter mcgavin] 29/6/2022 18:19

Stop spamming, its impossible to follow

[3put] 29/6/2022 16:20

Recently answered questions
Can we please have an update on all the relevant permissions needed for current and near future work. Asked on 14 June 2022
We will answer this question in the ordinary course of our Q&A, but as regards our recommissioning project at Saltfleetby we note that on 22 March 2022 we have already answered this question as follows:

“Angus Energy plc (AIM: ANGS) is pleased to announce that the Environment Agency has issued its Variation Notice for the existing Saltfleetby gas field permit. The site permit now encompasses the new activities of processing and compressing of gas for direct export to National Grid. No further regulatory or planning permissions are required before First Gas.”

Given the amount of seismic performed over the last 25 years in the field and the number of bore-holes and side-tracks drilled, providing good offset data, presumably the company and its contractors must be wholly confident of hitting the target zone. Putting that aside, what operational risks exist and could the programme be more complicated or expensive than planned? What lessons have been learned from mistakes by previous drillers in this formation? Asked on 31 May 2022
Thanks. The level of confidence about the target zone is indeed very high. We are addressing an area of the reservoir which was being produced from by an existing well, which was shut in due to a well-bore related issue.

An non-exhaustive list of risks, ever present in all drilling programmes is given in hxxps://www.researchgate.net/publication/317248002_Downhole_Drilling_Problems

Pertinent here are 1) hole collapse – this occurred twice in the Saltfleetby field and both times in the same layer, so we have introduced mitigation measures and will approach this layer with appropriate caution and 2) differential sticking ; 3) loss of bottom hole assembly – this occurred twice at Saltfleetby and 4) lost circulation fluids with reservoir damage. Many of these issues can be managed by reducing mud weight which is easier to do when well control is not such an issue as in a depleted reservoir.

It is wrong to characterise the historical drilling programmes at Saltfleetby as being especially prone to failure. Drilling was conducted between 1984 and 2017 by a number of Operators of varying competence. This being the UK’s largest onshore gas field, a great number of the earlier side tracks were in fact wholly exploratory. Some of the later drilling programmes did encounter problems which (by the common agreement of many specialists present at the time) could have been avoided with a relatively small degree of caution by the then drilling manager.

As we have advised before, this sidetrack has been planned with the benefit of enhanced 3D seismic and the oversight of a great number of independent drilling engineers and specialists. Some of the later side-tracks did not benefit from such oversight.

Angus’ drilling programmes have generally been well executed – albeit with disappointment about the target zone at Brockham and Lidsey. Angus drilled Horse Hill-1 successfully before selling out to partners and drilling programmes at the other fields either did not encounter the sorts of issues listed above or Angus was able to rectify them swiftly.

Was the deal to acquire the remaining 49% of SFB dilutive or accretive for shareholders when you add in all the associated funding?

Thank you. Asked on 30 May 2022
It was massively accretive and not dilutive at all. We acquired the 49%, which by the October P90 valuation was worth c.£25 million, for £14 million. We won’t call it the deal of the century, but it is an outstandingly good deal, especially when you consider that the average forward gas price in that October 2021 CPR has almost doubled today.

It is difficult to do the sums easily, since our own market cap prior to the announcement was only £17.5m (at 1.28p) and barely reflected the October CPR valuation of our 51% interest let alone potential (and now at Brockham actual production) at the southern oil fields. A decent estimate of 100% of Saltfleetby (just on the lower October CPR) and, say, just £10m for the oil fields would yield a value around the £60m mark and give a price per fully diluted share of nearer 2.5p. With current prices, the sky is the limit.

Yes we nearly doubled the number of shares outstanding but, taking into account the price paid for the asset, we more than doubled the value of the company.

Also unlike past placings only a small fraction (4%) of this issuance wss to market participants who might trade out. The rest is either locked up or part of a strategic stake.

Finally the raising of the £6m cash – done to ensure the assent of regulators and lenders – puts the risk of further placings out of people’s minds. Retail should be able to work in this stock with confidence.

Can the company please confirm the sidetrack schedule please. Asked on 30 May 2022
The precise spud date has not been set but is expected to be in the first three weeks of July.

As referenced in a recent interview with George Lucan, if all goes to plan with Saltfleetby is the company still hoping to pay long term shareholders a special dividend? Thanks. Asked on 30 May 2022
Thank you. The new strategic investors are advocating a regular dividend payout policy of 50%. The BoD certainly believe that large reliable dividends are still the best corporate communications that a company can make with shareholders.

Does the company continue to be in discussions with the 2 interested parties in Saltfleetby? Asked on 30 May 2022
We have kept an open line to three participants. Non-binding offers have been tabled but they did not reflect the true value of the asset or were contingent on various milestones being met.

It is one thing to low-ball ahead of proof of success, but to low-ball and make a bid contingent on proof of success seems to be having one’s cake and eating it.

In short we were being faced with the same issue that the old Angus had with Horse Hill – sell out the asset at an undervalue ahead of final proof of success, or press on alone and indeed increase our stake in the asset. On this occasion we chose the latter.

Can you briefly explain the current tax losses situation for Angus and what impact acquiring 100 of the Saltfleetby field will have on this? Asked on 26 May 2022
It is relatively simple. Angus has ring-fence (i.e. usable against hydrocarbon profits) tax losses of around £21m and these were factored into the P90 valuation. Saltfleetby Energy Limited has about £26 million of ring-fence, so a valuation with this included would yield some extra benefits.

During GLs recent interview with the LSE, it was noted the company would like to diversify and explore new sources of alternative energy.

Can you please confirm if you have identified any new potential locations that could be of interest, what you look for when scouting for new locations, plus what other sources of energy the company would be interested in moving into, given the opportunity. Asked on 6 May 2022
As regards deep geothermal we look for sources of heat and fracturing and these are mostly but not all in the southwest. Shallower reservoirs of heat exist, even in Lincolnshire, but these don’t lend themselves to heat for electricity generation but offer opportunities for local heating or assisted agriculture.

Many of the other energy initiatives looked at by ourselves and colleagues arise because the best sources of energy (whether gas, wind or geothermal) are often furthest from off-take infrastructure (pipelines or grid networks). Where grid and pipeline access is most abundant, problems of population density make local planning permissions very difficult. This stimulates research variously into gas to wire, hydrolysis of water for H2, waste to energy and storage.

Access to off-take, especially the electrical grid, is probably the biggest single hindrance to the development of alternative energy in the UK.

The British Energy Security Strategy identifies, further infrastructure is required to establish energy independence from overseas countries.

Can you please confirm, if framework opportunities to license from local authority owned lands, to generate energy arose, would Angus Energy be interested in being considered as the operator? Asked on 6 May 2022
Yes and our engagement with local councils has greatly improved over the last few years. The range of projects has also grown with geothermal, assisted agriculture and energy storage being some of the main points of interest. With our engagement in geothermal, we have found local authorities to be particularly welcoming and helpful.

Will the SFB sidetrack be drilled with continuous Gas production or will the gas production plant be turned off for the duration of the drill? Asked on 5 May 2022
Subject to final satisfaction of internal risk assessment SIMOPS are planned – i.e. simultaneous drilling and production. These is not an abnormal choice and indeed is common in far more restrictive areas such as offshore rigs. The plant when fully up and running benefits from a state of the art fire and gas leak detection, rapid blowdown and full set of monitoring and control instrumentation connected to a PLC as well as a full complement of alert operators.

Is there a forecast date for oil production at Lidsey oil field ?? Asked on 2 May 2022
We have been test producing at Lidsey and continue to encounter issues with the well-bore – including wax buildup and issues with pipe. We hope to update further on this field, including the possibility of side-track, when the team resources can be taken off Saltfleetby which is currently and rightly occupying our overwhelming attention.

Once the loan is clear,what would be the penalty costs to break the hedge as a rule of thumb. Thanks. Asked on 2 May 2022
There are not necessarily any significant penalty costs involved however the commercial cost is the difference between the forward curve prices for the period from the date at which the hedge is broken to the date of the scheduled maturity of the hedge versus the fixed hedge contract prices over that same period.

Thus the cost can only be known at the time the hedge counterparties determine to break or “counter hedge” it. In effect we would be taking out a new hedge for the residual period and amount but in the opposite direction – i.e. currently we are promising to supply Y therms for X pence/therm and to break the hedge we would be promising to buy Y therms for Z pence/therm. Z being the new forward curve prices and X being the original hedge contract prices.

In practice it would only make sense if we were interested in engaging in dynamic hedging – i.e. we felt we could do better trading in and out of positions over short contract months than the market. Generally speaking this is best described as gambling unless you have a large book of varied supply and distribution obligations and wish to balance it out in aggregate. At present we do not.

Hi, can I ask if the company is still in discussions with 2 interested parties for the sale of Saltfleetby, and if so, is the outcome of these discussions likely to be known and reported soon? Thank you. Asked on 2 May 2022
Discussions are continuing. Given the materiality of the disposal we are advised not to give further detail outside of RNS announcements.





Environmental impact appears to be one of the main concerns for individuals, who may have reservations on Angus expanding business operations, whilst satisfying the requisites of the Environment Act 2021 and associated legislation. Can you please provide an overview on what measures Angus have already taken and intend to develop upon, to ensure statutory compliance, corporate governance and innovative working practices, in regards to environmental sustainability. Asked on 2 May 2022
Thanks. Our principal regulators are OGA (NTSA), HSE and EA, and statutory bodies such as planning authorities. There is some overlap but less than might be helpful. Our compliance team now exceeds in number our technical team (excluding field operators), with two dedicated HSE liaisons, one EA liaison, one OGA liaison, one general planning and permitting lead.

We are a small company and the breadth of legislation, regulation, standards and so forth is daunting. Nonetheless our management systems have developed beyond recognition in the last two years and this is necessary when dealing with high pressure gas which is, after nuclear, one of the most hazardous businesses in the UK.

In terms of environmental compliance, the actual Saltfleetby Field presents fewer environmental hazards than a traditional oil field, as there is much less risk of fluid contamination to ground and water. Additionally electronic monitoring of flow has (for human safety) to be much more precise and involved than in traditional oil field practice. So on the whole we would regard the Saltfleetby Field as representing a much higher human safety risk but a much lower environmental risk than an oil field.

The exception is emissions to air. We require a flare at startup and some (but not all) maintenance events to acheive national grid specification gas, but otherwise we should not need to use the flare at all during the life of the field, although a tiny pilot flare is kept alight at all times to meet statutory requirements for emergency blowdown. Blowdown (i.e. flaring) for us means loss of principal inventory and commercial return – this is not an oilfield with associated gas as a headache. Gas is our reason for being here.

We have two scheduled group Zoom calls a day and, without any doubt, every day an issue of environmental compliance arises and is dealt with. At one level it is simply compliance (“what will EA think of this”) but at another level it is purposive (“what should we be doing or how could we do this better”). This is a sea change from the Angus of old.

We are committed to improving our carbon footprint – but we are led by an unforgiving Technical Director who rightly has regard to the “through-the-cycle” carbon cost of new equipment. Two innovations are planned – (a) a closed loop geothermal system for on site power generation up to 1MW and potentially retiring one gas fired generator and (b) a tie-up with a vertical farming operation which would take both heat, power for lighting and potentially CO2 emissions from the site for assisted agriculture.

We do, as a small company, adhere to the QCA. Up until December, on the strong encouragement of the Board, and whilst we awaited procurement and delivery of equipment to Saltfleetby, almost 50% of management time during 2021 was spent in developing our deep geothermal programme in southwest England. We are sincere in our desire to be an innovative part of Transition, but bear in mind that we are a small company at present focused on acting as a safe and responsible Operator in the immediate term and delivering good returns to those who have funded these operations..

Has a rig been ordered to drill the sidetrack yet?

Which month in 2022 do you expect the rig to arrive if so. Thank you. Asked on 2 May 2022
Yes. A rig was ordered in June 2021, considerable replacement parts for which were sourced from overseas. Although it was scheduled to be ready in October, none of the parts actually landed in the UK until December and as a consequence the rig itself would not have been ready until around now. This underlines the very real supply chain problems which we faced in H2 2021, and which continue to cause problems for many other Operators. If anything we think that the supply chain issues have gotten worse not better since then, and we are relieved to have our kit onshore.

There are alternative onshore rigs which we could have used for this side-track had we felt it necessary. The rig is undergoing testing and we do inspection reports and visits every three or four weeks. We are confident that it will be ready for moblisation at site at the end of June.

What would be a reasonable time frame for the steps for getting the Portland reperforated and producing oil? Asked on 1 May 2022
From Technical Director: “The work to recomplete the well to the Portland will involve abandoning the bulk of the well through the Kimmeridge to leave just the topmost part across the Portland. We would then perforate that section.

I am assuming 5-6 days work plus mob and demob and rig up and rig down. The perforated section may be fairly long as it is near horizontal which is good. The rig can be the small workover rig we used at Saltfleetby and we need little in the way of tanks and pumps etc, although achieving our targets on waste management on such an operation will involve additional cost.”

That is the “operationR21; but before that and in addition to local authority planning (obtained), HSE (BSOR) submission, NTSA notification (although agreed in our FDP), we will require the consideration of the EA. We do not believe that this should be a very complex affair as the well-bore was well-designed and recently spudded to modern standards, the hydrogeology of the area is thoroughly understood, not least by EA, and the target reservoir has been produced from for thirty years.

On current oil prices, and given a resulting flow of 100bbl/d, it would not be unreasonable to assume that the cost of the operation could be recouped within 5-6 weeks of flow. Operationally speaking, there would be no other upgrade to the site required.

Are there any revised updates for the Balcombe appeal please. P.S. I would like to congratulate GL for putting a very good case forward at the SCC meeting,well done! Asked on 30 April 2022
Having submitted our Statement of Case, WSCC submitted their Statement of Case during March and we responded with our rebuttal on 12 April 2022. The matter is now with the Inspector.

1. have the DSEAR Dangerous Substances and Explosive Atmospheres Regulations 2002 requirements been completed at Brockham?
2. will production from BRX2-Y resume at Brockham in May independent of the council decision regarding the portland perforations Asked on 25 April 2022
DSEAR regulations have an element of continuous assessment against ever higher standards but, yes, we are engaged in that assessment process and have achieved levels of compliance sufficient to continue safe operations and the production and export of of crude oil. As advised by RNS we will give further information on this in due course.

1.are they going to install a CHP? And never hopefully look at using the flare other then emergencies?,

2.are they going to look at investing in a AD plant so they always have a gas supply when the gas field Depletes?,

3. Would ANGS look at a investing in a CHP that can take natural gas?, and hydrogen?, maybe they need to speak to 2G as there at the top of there game in this Industry, and by having a a AD plant they would also get paid for the final cake dry matter and used as a fertiliser,,
Also I would be asking they could be getting paid from a local council to take food sate too!!, Asked on 31 March 2022
We won’t need to use the flare as part of normal operations although a tiny amount of gas is continuously burned in order to maintain a pilot light, much as on a traditional household boiler.

We do have gas fired generating plant on site to drive the compressors and provide site power. This is the most efficient way of producing and using off-spec gas which cannot be sold into the national gas grid and is an environmentally friendly solution in a remote location without an industrial scale connecton to the electric grid.

We also have been in touch with local landlords regarding the site’s potential to provide heat, CO2 and surplus electric to support vertical farming operations in neighbouring fields. This is likely to be a programme for consideration a year’s hence, alongside a relatively inexpensive geothermal power generation scheme using the Sherwood Sands reservoir.

What method of water injection will be used at Brockham to get maximum production. Could we also have an update about the Lidsey well please. Asked on 31 March 2022
The water injection permitted at Brockham is pumped and is subject to precise daily and hourly limits. As well as providing a cheap and environmentally sound method of returning highly saline formation water to its native reservoir as compared to incineration, the water reinjected acts to support the oil in the reservoir and aid extraction.

Lidsey will be capable of resumed production from mid-June when site modernisation should be complete. In fact there has been intermittent production this year – but not at a meaningful continuous level. Production at the time of shut-in involved a relatively high water cut and so we have to address the issue of formation water disposal in the interim on the commercial market (where happily costs have fallen each year since 2019) and in the medium term via disposal at Brockham (our preference as it is environmentally more sound and cheaper) which latter route would require, amongst other permissions, a non-contentious EA permit (a so called RSR permit) which we should obtain later this year.

At these oil prices, however, Lidsey is profitable, even with a water cut on the high side, so we will be progressing each of those avenues to restore or increase flow. The level of profitability depends somewhat on the success of the hot-oiling and borehole remediation works undertaken last year and we will advise the market by RNS when this data becomes available after a period of continuous flow.

As regards the longer-term at Lidsey, we are formulating a commercial proposition to the neighbouring licence holder in order to exploit the side-track target which emerged from seismic studies last year. However our immediate focus is overwhelmingly to resume Saltfleetby production and we think we are supported by all shareholders in this focus.

Can the company update shareholders with the latest comprehensive timetable for arrival of equipment and commissioning and first gas? Can the BoD also update the status of any remaining regulatory permissions being specifically the EA application and the Local Authority planning variation? Asked on 6 March 2022
Hopefully these have been answered in RNS. We do expect further (positive and negative) variation in particular skid arrival dates – we are adding sound absorbent materials to some units and bunding others – but the end April date for delivery of the last skid is unchanged from that advised to market.

Assuming the side-track is successful, how much cashflow will be generated (including hedged production) in H2 2022. Asked on 6 March 2022
Without offering firm predictions but solely to assist shareholders in considering the range of outcomes: the existing wells, prior to shut in in 2017, were producing about 5mmscf/d (million standard cubic feet each day). Allowing for a 28 day month and a conservative calorific conversion to therms, 5 mmscf/d is very approximately 1.5 million therms a month. We have already advised that we expect the Field would produce 5mmscf/d or 1.5million additional therms a month from mid-August, arising from the side track, giving 3million therms/month or 10mmscf/d for the last four and half months of the year.

We have several caveats to trying to make such predictions over such a period: first, that gas prices are exceedingly volatile at present and may move in any direction and rapidly; second that whilst we do not regard the side-track as exploratory in the traditional sense, all drilling involves risk and the level of sidetrack production could be more or less than the 1.5 million therms/month suggested. Third the hedge profile varies a little from period to period. Lastly the foregoing and the following is not advice by the company – but an illustration of how to calculate different outcomes from production figures which the Company will be able to advise over time.

The average hedged sales price is 43 pence/therm over the life of the hedge and the unhedged forward prices are presently not far off 300 pence/therm for unhedged sales in H2 2022. On the basis of a side track completed and online by mid August then H2 gross revenues (Angus share 51%) might be in the region of £24m which would ignore any benefit of unhedged production during June, potentially w0rth a further £4.5m at 300pence/therm. Again we repeat that this is not advice to shareholders but guidance on calculation only and investors are urged to do their own research based on RNS advised production levels and prices.



Hi, whilst I appreciate that being in an Offer Period makes communications with shareholders exceedingly sensitive, as a supportive long-term shareholder I have to say I’m disappointed by the lack or PR regarding the Saltfleetby field. Given that gas prices have quadrupled in recent times, I would have thought that the company should be shouting from the roof tops about the game changing positive impact that the rise in gas price has on the economics of the Saltfleetby field. Asked on 6 March 2022
Noted and thank you. We have indeed been limited in public communicatiions by being in Offer Period, but have been more active both on Twitter and in interviews recently.

[3put] 29/6/2022 14:43

Recently answered questions
Can we please have an update on all the relevant permissions needed for current and near future work. Asked on 14 June 2022
We will answer this question in the ordinary course of our Q&A, but as regards our recommissioning project at Saltfleetby we note that on 22 March 2022 we have already answered this question as follows:

“Angus Energy plc (AIM: ANGS) is pleased to announce that the Environment Agency has issued its Variation Notice for the existing Saltfleetby gas field permit. The site permit now encompasses the new activities of processing and compressing of gas for direct export to National Grid. No further regulatory or planning permissions are required before First Gas.”

Given the amount of seismic performed over the last 25 years in the field and the number of bore-holes and side-tracks drilled, providing good offset data, presumably the company and its contractors must be wholly confident of hitting the target zone. Putting that aside, what operational risks exist and could the programme be more complicated or expensive than planned? What lessons have been learned from mistakes by previous drillers in this formation? Asked on 31 May 2022
Thanks. The level of confidence about the target zone is indeed very high. We are addressing an area of the reservoir which was being produced from by an existing well, which was shut in due to a well-bore related issue.

An non-exhaustive list of risks, ever present in all drilling programmes is given in hxxps://www.researchgate.net/publication/317248002_Downhole_Drilling_Problems

Pertinent here are 1) hole collapse – this occurred twice in the Saltfleetby field and both times in the same layer, so we have introduced mitigation measures and will approach this layer with appropriate caution and 2) differential sticking ; 3) loss of bottom hole assembly – this occurred twice at Saltfleetby and 4) lost circulation fluids with reservoir damage. Many of these issues can be managed by reducing mud weight which is easier to do when well control is not such an issue as in a depleted reservoir.

It is wrong to characterise the historical drilling programmes at Saltfleetby as being especially prone to failure. Drilling was conducted between 1984 and 2017 by a number of Operators of varying competence. This being the UK’s largest onshore gas field, a great number of the earlier side tracks were in fact wholly exploratory. Some of the later drilling programmes did encounter problems which (by the common agreement of many specialists present at the time) could have been avoided with a relatively small degree of caution by the then drilling manager.

As we have advised before, this sidetrack has been planned with the benefit of enhanced 3D seismic and the oversight of a great number of independent drilling engineers and specialists. Some of the later side-tracks did not benefit from such oversight.

Angus’ drilling programmes have generally been well executed – albeit with disappointment about the target zone at Brockham and Lidsey. Angus drilled Horse Hill-1 successfully before selling out to partners and drilling programmes at the other fields either did not encounter the sorts of issues listed above or Angus was able to rectify them swiftly.

Was the deal to acquire the remaining 49% of SFB dilutive or accretive for shareholders when you add in all the associated funding?

Thank you. Asked on 30 May 2022
It was massively accretive and not dilutive at all. We acquired the 49%, which by the October P90 valuation was worth c.£25 million, for £14 million. We won’t call it the deal of the century, but it is an outstandingly good deal, especially when you consider that the average forward gas price in that October 2021 CPR has almost doubled today.

It is difficult to do the sums easily, since our own market cap prior to the announcement was only £17.5m (at 1.28p) and barely reflected the October CPR valuation of our 51% interest let alone potential (and now at Brockham actual production) at the southern oil fields. A decent estimate of 100% of Saltfleetby (just on the lower October CPR) and, say, just £10m for the oil fields would yield a value around the £60m mark and give a price per fully diluted share of nearer 2.5p. With current prices, the sky is the limit.

Yes we nearly doubled the number of shares outstanding but, taking into account the price paid for the asset, we more than doubled the value of the company.

Also unlike past placings only a small fraction (4%) of this issuance wss to market participants who might trade out. The rest is either locked up or part of a strategic stake.

Finally the raising of the £6m cash – done to ensure the assent of regulators and lenders – puts the risk of further placings out of people’s minds. Retail should be able to work in this stock with confidence.

Can the company please confirm the sidetrack schedule please. Asked on 30 May 2022
The precise spud date has not been set but is expected to be in the first three weeks of July.

As referenced in a recent interview with George Lucan, if all goes to plan with Saltfleetby is the company still hoping to pay long term shareholders a special dividend? Thanks. Asked on 30 May 2022
Thank you. The new strategic investors are advocating a regular dividend payout policy of 50%. The BoD certainly believe that large reliable dividends are still the best corporate communications that a company can make with shareholders.

Does the company continue to be in discussions with the 2 interested parties in Saltfleetby? Asked on 30 May 2022
We have kept an open line to three participants. Non-binding offers have been tabled but they did not reflect the true value of the asset or were contingent on various milestones being met.

It is one thing to low-ball ahead of proof of success, but to low-ball and make a bid contingent on proof of success seems to be having one’s cake and eating it.

In short we were being faced with the same issue that the old Angus had with Horse Hill – sell out the asset at an undervalue ahead of final proof of success, or press on alone and indeed increase our stake in the asset. On this occasion we chose the latter.

Can you briefly explain the current tax losses situation for Angus and what impact acquiring 100 of the Saltfleetby field will have on this? Asked on 26 May 2022
It is relatively simple. Angus has ring-fence (i.e. usable against hydrocarbon profits) tax losses of around £21m and these were factored into the P90 valuation. Saltfleetby Energy Limited has about £26 million of ring-fence, so a valuation with this included would yield some extra benefits.

During GLs recent interview with the LSE, it was noted the company would like to diversify and explore new sources of alternative energy.

Can you please confirm if you have identified any new potential locations that could be of interest, what you look for when scouting for new locations, plus what other sources of energy the company would be interested in moving into, given the opportunity. Asked on 6 May 2022
As regards deep geothermal we look for sources of heat and fracturing and these are mostly but not all in the southwest. Shallower reservoirs of heat exist, even in Lincolnshire, but these don’t lend themselves to heat for electricity generation but offer opportunities for local heating or assisted agriculture.

Many of the other energy initiatives looked at by ourselves and colleagues arise because the best sources of energy (whether gas, wind or geothermal) are often furthest from off-take infrastructure (pipelines or grid networks). Where grid and pipeline access is most abundant, problems of population density make local planning permissions very difficult. This stimulates research variously into gas to wire, hydrolysis of water for H2, waste to energy and storage.

Access to off-take, especially the electrical grid, is probably the biggest single hindrance to the development of alternative energy in the UK.

The British Energy Security Strategy identifies, further infrastructure is required to establish energy independence from overseas countries.

Can you please confirm, if framework opportunities to license from local authority owned lands, to generate energy arose, would Angus Energy be interested in being considered as the operator? Asked on 6 May 2022
Yes and our engagement with local councils has greatly improved over the last few years. The range of projects has also grown with geothermal, assisted agriculture and energy storage being some of the main points of interest. With our engagement in geothermal, we have found local authorities to be particularly welcoming and helpful.

Will the SFB sidetrack be drilled with continuous Gas production or will the gas production plant be turned off for the duration of the drill? Asked on 5 May 2022
Subject to final satisfaction of internal risk assessment SIMOPS are planned – i.e. simultaneous drilling and production. These is not an abnormal choice and indeed is common in far more restrictive areas such as offshore rigs. The plant when fully up and running benefits from a state of the art fire and gas leak detection, rapid blowdown and full set of monitoring and control instrumentation connected to a PLC as well as a full complement of alert operators.

Is there a forecast date for oil production at Lidsey oil field ?? Asked on 2 May 2022
We have been test producing at Lidsey and continue to encounter issues with the well-bore – including wax buildup and issues with pipe. We hope to update further on this field, including the possibility of side-track, when the team resources can be taken off Saltfleetby which is currently and rightly occupying our overwhelming attention.

Once the loan is clear,what would be the penalty costs to break the hedge as a rule of thumb. Thanks. Asked on 2 May 2022
There are not necessarily any significant penalty costs involved however the commercial cost is the difference between the forward curve prices for the period from the date at which the hedge is broken to the date of the scheduled maturity of the hedge versus the fixed hedge contract prices over that same period.

Thus the cost can only be known at the time the hedge counterparties determine to break or “counter hedge” it. In effect we would be taking out a new hedge for the residual period and amount but in the opposite direction – i.e. currently we are promising to supply Y therms for X pence/therm and to break the hedge we would be promising to buy Y therms for Z pence/therm. Z being the new forward curve prices and X being the original hedge contract prices.

In practice it would only make sense if we were interested in engaging in dynamic hedging – i.e. we felt we could do better trading in and out of positions over short contract months than the market. Generally speaking this is best described as gambling unless you have a large book of varied supply and distribution obligations and wish to balance it out in aggregate. At present we do not.

Hi, can I ask if the company is still in discussions with 2 interested parties for the sale of Saltfleetby, and if so, is the outcome of these discussions likely to be known and reported soon? Thank you. Asked on 2 May 2022
Discussions are continuing. Given the materiality of the disposal we are advised not to give further detail outside of RNS announcements.





Environmental impact appears to be one of the main concerns for individuals, who may have reservations on Angus expanding business operations, whilst satisfying the requisites of the Environment Act 2021 and associated legislation. Can you please provide an overview on what measures Angus have already taken and intend to develop upon, to ensure statutory compliance, corporate governance and innovative working practices, in regards to environmental sustainability. Asked on 2 May 2022
Thanks. Our principal regulators are OGA (NTSA), HSE and EA, and statutory bodies such as planning authorities. There is some overlap but less than might be helpful. Our compliance team now exceeds in number our technical team (excluding field operators), with two dedicated HSE liaisons, one EA liaison, one OGA liaison, one general planning and permitting lead.

We are a small company and the breadth of legislation, regulation, standards and so forth is daunting. Nonetheless our management systems have developed beyond recognition in the last two years and this is necessary when dealing with high pressure gas which is, after nuclear, one of the most hazardous businesses in the UK.

In terms of environmental compliance, the actual Saltfleetby Field presents fewer environmental hazards than a traditional oil field, as there is much less risk of fluid contamination to ground and water. Additionally electronic monitoring of flow has (for human safety) to be much more precise and involved than in traditional oil field practice. So on the whole we would regard the Saltfleetby Field as representing a much higher human safety risk but a much lower environmental risk than an oil field.

The exception is emissions to air. We require a flare at startup and some (but not all) maintenance events to acheive national grid specification gas, but otherwise we should not need to use the flare at all during the life of the field, although a tiny pilot flare is kept alight at all times to meet statutory requirements for emergency blowdown. Blowdown (i.e. flaring) for us means loss of principal inventory and commercial return – this is not an oilfield with associated gas as a headache. Gas is our reason for being here.

We have two scheduled group Zoom calls a day and, without any doubt, every day an issue of environmental compliance arises and is dealt with. At one level it is simply compliance (“what will EA think of this”) but at another level it is purposive (“what should we be doing or how could we do this better”). This is a sea change from the Angus of old.

We are committed to improving our carbon footprint – but we are led by an unforgiving Technical Director who rightly has regard to the “through-the-cycle” carbon cost of new equipment. Two innovations are planned – (a) a closed loop geothermal system for on site power generation up to 1MW and potentially retiring one gas fired generator and (b) a tie-up with a vertical farming operation which would take both heat, power for lighting and potentially CO2 emissions from the site for assisted agriculture.

We do, as a small company, adhere to the QCA. Up until December, on the strong encouragement of the Board, and whilst we awaited procurement and delivery of equipment to Saltfleetby, almost 50% of management time during 2021 was spent in developing our deep geothermal programme in southwest England. We are sincere in our desire to be an innovative part of Transition, but bear in mind that we are a small company at present focused on acting as a safe and responsible Operator in the immediate term and delivering good returns to those who have funded these operations..

Has a rig been ordered to drill the sidetrack yet?

Which month in 2022 do you expect the rig to arrive if so. Thank you. Asked on 2 May 2022
Yes. A rig was ordered in June 2021, considerable replacement parts for which were sourced from overseas. Although it was scheduled to be ready in October, none of the parts actually landed in the UK until December and as a consequence the rig itself would not have been ready until around now. This underlines the very real supply chain problems which we faced in H2 2021, and which continue to cause problems for many other Operators. If anything we think that the supply chain issues have gotten worse not better since then, and we are relieved to have our kit onshore.

There are alternative onshore rigs which we could have used for this side-track had we felt it necessary. The rig is undergoing testing and we do inspection reports and visits every three or four weeks. We are confident that it will be ready for moblisation at site at the end of June.

What would be a reasonable time frame for the steps for getting the Portland reperforated and producing oil? Asked on 1 May 2022
From Technical Director: “The work to recomplete the well to the Portland will involve abandoning the bulk of the well through the Kimmeridge to leave just the topmost part across the Portland. We would then perforate that section.

I am assuming 5-6 days work plus mob and demob and rig up and rig down. The perforated section may be fairly long as it is near horizontal which is good. The rig can be the small workover rig we used at Saltfleetby and we need little in the way of tanks and pumps etc, although achieving our targets on waste management on such an operation will involve additional cost.”

That is the “operationR21; but before that and in addition to local authority planning (obtained), HSE (BSOR) submission, NTSA notification (although agreed in our FDP), we will require the consideration of the EA. We do not believe that this should be a very complex affair as the well-bore was well-designed and recently spudded to modern standards, the hydrogeology of the area is thoroughly understood, not least by EA, and the target reservoir has been produced from for thirty years.

On current oil prices, and given a resulting flow of 100bbl/d, it would not be unreasonable to assume that the cost of the operation could be recouped within 5-6 weeks of flow. Operationally speaking, there would be no other upgrade to the site required.

Are there any revised updates for the Balcombe appeal please. P.S. I would like to congratulate GL for putting a very good case forward at the SCC meeting,well done! Asked on 30 April 2022
Having submitted our Statement of Case, WSCC submitted their Statement of Case during March and we responded with our rebuttal on 12 April 2022. The matter is now with the Inspector.

1. have the DSEAR Dangerous Substances and Explosive Atmospheres Regulations 2002 requirements been completed at Brockham?
2. will production from BRX2-Y resume at Brockham in May independent of the council decision regarding the portland perforations Asked on 25 April 2022
DSEAR regulations have an element of continuous assessment against ever higher standards but, yes, we are engaged in that assessment process and have achieved levels of compliance sufficient to continue safe operations and the production and export of of crude oil. As advised by RNS we will give further information on this in due course.

1.are they going to install a CHP? And never hopefully look at using the flare other then emergencies?,

2.are they going to look at investing in a AD plant so they always have a gas supply when the gas field Depletes?,

3. Would ANGS look at a investing in a CHP that can take natural gas?, and hydrogen?, maybe they need to speak to 2G as there at the top of there game in this Industry, and by having a a AD plant they would also get paid for the final cake dry matter and used as a fertiliser,,
Also I would be asking they could be getting paid from a local council to take food sate too!!, Asked on 31 March 2022
We won’t need to use the flare as part of normal operations although a tiny amount of gas is continuously burned in order to maintain a pilot light, much as on a traditional household boiler.

We do have gas fired generating plant on site to drive the compressors and provide site power. This is the most efficient way of producing and using off-spec gas which cannot be sold into the national gas grid and is an environmentally friendly solution in a remote location without an industrial scale connecton to the electric grid.

We also have been in touch with local landlords regarding the site’s potential to provide heat, CO2 and surplus electric to support vertical farming operations in neighbouring fields. This is likely to be a programme for consideration a year’s hence, alongside a relatively inexpensive geothermal power generation scheme using the Sherwood Sands reservoir.

What method of water injection will be used at Brockham to get maximum production. Could we also have an update about the Lidsey well please. Asked on 31 March 2022
The water injection permitted at Brockham is pumped and is subject to precise daily and hourly limits. As well as providing a cheap and environmentally sound method of returning highly saline formation water to its native reservoir as compared to incineration, the water reinjected acts to support the oil in the reservoir and aid extraction.

Lidsey will be capable of resumed production from mid-June when site modernisation should be complete. In fact there has been intermittent production this year – but not at a meaningful continuous level. Production at the time of shut-in involved a relatively high water cut and so we have to address the issue of formation water disposal in the interim on the commercial market (where happily costs have fallen each year since 2019) and in the medium term via disposal at Brockham (our preference as it is environmentally more sound and cheaper) which latter route would require, amongst other permissions, a non-contentious EA permit (a so called RSR permit) which we should obtain later this year.

At these oil prices, however, Lidsey is profitable, even with a water cut on the high side, so we will be progressing each of those avenues to restore or increase flow. The level of profitability depends somewhat on the success of the hot-oiling and borehole remediation works undertaken last year and we will advise the market by RNS when this data becomes available after a period of continuous flow.

As regards the longer-term at Lidsey, we are formulating a commercial proposition to the neighbouring licence holder in order to exploit the side-track target which emerged from seismic studies last year. However our immediate focus is overwhelmingly to resume Saltfleetby production and we think we are supported by all shareholders in this focus.

Can the company update shareholders with the latest comprehensive timetable for arrival of equipment and commissioning and first gas? Can the BoD also update the status of any remaining regulatory permissions being specifically the EA application and the Local Authority planning variation? Asked on 6 March 2022
Hopefully these have been answered in RNS. We do expect further (positive and negative) variation in particular skid arrival dates – we are adding sound absorbent materials to some units and bunding others – but the end April date for delivery of the last skid is unchanged from that advised to market.

Assuming the side-track is successful, how much cashflow will be generated (including hedged production) in H2 2022. Asked on 6 March 2022
Without offering firm predictions but solely to assist shareholders in considering the range of outcomes: the existing wells, prior to shut in in 2017, were producing about 5mmscf/d (million standard cubic feet each day). Allowing for a 28 day month and a conservative calorific conversion to therms, 5 mmscf/d is very approximately 1.5 million therms a month. We have already advised that we expect the Field would produce 5mmscf/d or 1.5million additional therms a month from mid-August, arising from the side track, giving 3million therms/month or 10mmscf/d for the last four and half months of the year.

We have several caveats to trying to make such predictions over such a period: first, that gas prices are exceedingly volatile at present and may move in any direction and rapidly; second that whilst we do not regard the side-track as exploratory in the traditional sense, all drilling involves risk and the level of sidetrack production could be more or less than the 1.5 million therms/month suggested. Third the hedge profile varies a little from period to period. Lastly the foregoing and the following is not advice by the company – but an illustration of how to calculate different outcomes from production figures which the Company will be able to advise over time.

The average hedged sales price is 43 pence/therm over the life of the hedge and the unhedged forward prices are presently not far off 300 pence/therm for unhedged sales in H2 2022. On the basis of a side track completed and online by mid August then H2 gross revenues (Angus share 51%) might be in the region of £24m which would ignore any benefit of unhedged production during June, potentially w0rth a further £4.5m at 300pence/therm. Again we repeat that this is not advice to shareholders but guidance on calculation only and investors are urged to do their own research based on RNS advised production levels and prices.



Hi, whilst I appreciate that being in an Offer Period makes communications with shareholders exceedingly sensitive, as a supportive long-term shareholder I have to say I’m disappointed by the lack or PR regarding the Saltfleetby field. Given that gas prices have quadrupled in recent times, I would have thought that the company should be shouting from the roof tops about the game changing positive impact that the rise in gas price has on the economics of the Saltfleetby field. Asked on 6 March 2022
Noted and thank you. We have indeed been limited in public communicatiions by being in Offer Period, but have been more active both on Twitter and in interviews recently.

[3put] 29/6/2022 13:58

Recently answered questions
Can we please have an update on all the relevant permissions needed for current and near future work. Asked on 14 June 2022
We will answer this question in the ordinary course of our Q&A, but as regards our recommissioning project at Saltfleetby we note that on 22 March 2022 we have already answered this question as follows:

“Angus Energy plc (AIM: ANGS) is pleased to announce that the Environment Agency has issued its Variation Notice for the existing Saltfleetby gas field permit. The site permit now encompasses the new activities of processing and compressing of gas for direct export to National Grid. No further regulatory or planning permissions are required before First Gas.”

Given the amount of seismic performed over the last 25 years in the field and the number of bore-holes and side-tracks drilled, providing good offset data, presumably the company and its contractors must be wholly confident of hitting the target zone. Putting that aside, what operational risks exist and could the programme be more complicated or expensive than planned? What lessons have been learned from mistakes by previous drillers in this formation? Asked on 31 May 2022
Thanks. The level of confidence about the target zone is indeed very high. We are addressing an area of the reservoir which was being produced from by an existing well, which was shut in due to a well-bore related issue.

An non-exhaustive list of risks, ever present in all drilling programmes is given in hxxps://www.researchgate.net/publication/317248002_Downhole_Drilling_Problems

Pertinent here are 1) hole collapse – this occurred twice in the Saltfleetby field and both times in the same layer, so we have introduced mitigation measures and will approach this layer with appropriate caution and 2) differential sticking ; 3) loss of bottom hole assembly – this occurred twice at Saltfleetby and 4) lost circulation fluids with reservoir damage. Many of these issues can be managed by reducing mud weight which is easier to do when well control is not such an issue as in a depleted reservoir.

It is wrong to characterise the historical drilling programmes at Saltfleetby as being especially prone to failure. Drilling was conducted between 1984 and 2017 by a number of Operators of varying competence. This being the UK’s largest onshore gas field, a great number of the earlier side tracks were in fact wholly exploratory. Some of the later drilling programmes did encounter problems which (by the common agreement of many specialists present at the time) could have been avoided with a relatively small degree of caution by the then drilling manager.

As we have advised before, this sidetrack has been planned with the benefit of enhanced 3D seismic and the oversight of a great number of independent drilling engineers and specialists. Some of the later side-tracks did not benefit from such oversight.

Angus’ drilling programmes have generally been well executed – albeit with disappointment about the target zone at Brockham and Lidsey. Angus drilled Horse Hill-1 successfully before selling out to partners and drilling programmes at the other fields either did not encounter the sorts of issues listed above or Angus was able to rectify them swiftly.

Was the deal to acquire the remaining 49% of SFB dilutive or accretive for shareholders when you add in all the associated funding?

Thank you. Asked on 30 May 2022
It was massively accretive and not dilutive at all. We acquired the 49%, which by the October P90 valuation was worth c.£25 million, for £14 million. We won’t call it the deal of the century, but it is an outstandingly good deal, especially when you consider that the average forward gas price in that October 2021 CPR has almost doubled today.

It is difficult to do the sums easily, since our own market cap prior to the announcement was only £17.5m (at 1.28p) and barely reflected the October CPR valuation of our 51% interest let alone potential (and now at Brockham actual production) at the southern oil fields. A decent estimate of 100% of Saltfleetby (just on the lower October CPR) and, say, just £10m for the oil fields would yield a value around the £60m mark and give a price per fully diluted share of nearer 2.5p. With current prices, the sky is the limit.

Yes we nearly doubled the number of shares outstanding but, taking into account the price paid for the asset, we more than doubled the value of the company.

Also unlike past placings only a small fraction (4%) of this issuance wss to market participants who might trade out. The rest is either locked up or part of a strategic stake.

Finally the raising of the £6m cash – done to ensure the assent of regulators and lenders – puts the risk of further placings out of people’s minds. Retail should be able to work in this stock with confidence.

Can the company please confirm the sidetrack schedule please. Asked on 30 May 2022
The precise spud date has not been set but is expected to be in the first three weeks of July.

As referenced in a recent interview with George Lucan, if all goes to plan with Saltfleetby is the company still hoping to pay long term shareholders a special dividend? Thanks. Asked on 30 May 2022
Thank you. The new strategic investors are advocating a regular dividend payout policy of 50%. The BoD certainly believe that large reliable dividends are still the best corporate communications that a company can make with shareholders.

Does the company continue to be in discussions with the 2 interested parties in Saltfleetby? Asked on 30 May 2022
We have kept an open line to three participants. Non-binding offers have been tabled but they did not reflect the true value of the asset or were contingent on various milestones being met.

It is one thing to low-ball ahead of proof of success, but to low-ball and make a bid contingent on proof of success seems to be having one’s cake and eating it.

In short we were being faced with the same issue that the old Angus had with Horse Hill – sell out the asset at an undervalue ahead of final proof of success, or press on alone and indeed increase our stake in the asset. On this occasion we chose the latter.

Can you briefly explain the current tax losses situation for Angus and what impact acquiring 100 of the Saltfleetby field will have on this? Asked on 26 May 2022
It is relatively simple. Angus has ring-fence (i.e. usable against hydrocarbon profits) tax losses of around £21m and these were factored into the P90 valuation. Saltfleetby Energy Limited has about £26 million of ring-fence, so a valuation with this included would yield some extra benefits.

During GLs recent interview with the LSE, it was noted the company would like to diversify and explore new sources of alternative energy.

Can you please confirm if you have identified any new potential locations that could be of interest, what you look for when scouting for new locations, plus what other sources of energy the company would be interested in moving into, given the opportunity. Asked on 6 May 2022
As regards deep geothermal we look for sources of heat and fracturing and these are mostly but not all in the southwest. Shallower reservoirs of heat exist, even in Lincolnshire, but these don’t lend themselves to heat for electricity generation but offer opportunities for local heating or assisted agriculture.

Many of the other energy initiatives looked at by ourselves and colleagues arise because the best sources of energy (whether gas, wind or geothermal) are often furthest from off-take infrastructure (pipelines or grid networks). Where grid and pipeline access is most abundant, problems of population density make local planning permissions very difficult. This stimulates research variously into gas to wire, hydrolysis of water for H2, waste to energy and storage.

Access to off-take, especially the electrical grid, is probably the biggest single hindrance to the development of alternative energy in the UK.

The British Energy Security Strategy identifies, further infrastructure is required to establish energy independence from overseas countries.

Can you please confirm, if framework opportunities to license from local authority owned lands, to generate energy arose, would Angus Energy be interested in being considered as the operator? Asked on 6 May 2022
Yes and our engagement with local councils has greatly improved over the last few years. The range of projects has also grown with geothermal, assisted agriculture and energy storage being some of the main points of interest. With our engagement in geothermal, we have found local authorities to be particularly welcoming and helpful.

Will the SFB sidetrack be drilled with continuous Gas production or will the gas production plant be turned off for the duration of the drill? Asked on 5 May 2022
Subject to final satisfaction of internal risk assessment SIMOPS are planned – i.e. simultaneous drilling and production. These is not an abnormal choice and indeed is common in far more restrictive areas such as offshore rigs. The plant when fully up and running benefits from a state of the art fire and gas leak detection, rapid blowdown and full set of monitoring and control instrumentation connected to a PLC as well as a full complement of alert operators.

Is there a forecast date for oil production at Lidsey oil field ?? Asked on 2 May 2022
We have been test producing at Lidsey and continue to encounter issues with the well-bore – including wax buildup and issues with pipe. We hope to update further on this field, including the possibility of side-track, when the team resources can be taken off Saltfleetby which is currently and rightly occupying our overwhelming attention.

Once the loan is clear,what would be the penalty costs to break the hedge as a rule of thumb. Thanks. Asked on 2 May 2022
There are not necessarily any significant penalty costs involved however the commercial cost is the difference between the forward curve prices for the period from the date at which the hedge is broken to the date of the scheduled maturity of the hedge versus the fixed hedge contract prices over that same period.

Thus the cost can only be known at the time the hedge counterparties determine to break or “counter hedge” it. In effect we would be taking out a new hedge for the residual period and amount but in the opposite direction – i.e. currently we are promising to supply Y therms for X pence/therm and to break the hedge we would be promising to buy Y therms for Z pence/therm. Z being the new forward curve prices and X being the original hedge contract prices.

In practice it would only make sense if we were interested in engaging in dynamic hedging – i.e. we felt we could do better trading in and out of positions over short contract months than the market. Generally speaking this is best described as gambling unless you have a large book of varied supply and distribution obligations and wish to balance it out in aggregate. At present we do not.

Hi, can I ask if the company is still in discussions with 2 interested parties for the sale of Saltfleetby, and if so, is the outcome of these discussions likely to be known and reported soon? Thank you. Asked on 2 May 2022
Discussions are continuing. Given the materiality of the disposal we are advised not to give further detail outside of RNS announcements.





Environmental impact appears to be one of the main concerns for individuals, who may have reservations on Angus expanding business operations, whilst satisfying the requisites of the Environment Act 2021 and associated legislation. Can you please provide an overview on what measures Angus have already taken and intend to develop upon, to ensure statutory compliance, corporate governance and innovative working practices, in regards to environmental sustainability. Asked on 2 May 2022
Thanks. Our principal regulators are OGA (NTSA), HSE and EA, and statutory bodies such as planning authorities. There is some overlap but less than might be helpful. Our compliance team now exceeds in number our technical team (excluding field operators), with two dedicated HSE liaisons, one EA liaison, one OGA liaison, one general planning and permitting lead.

We are a small company and the breadth of legislation, regulation, standards and so forth is daunting. Nonetheless our management systems have developed beyond recognition in the last two years and this is necessary when dealing with high pressure gas which is, after nuclear, one of the most hazardous businesses in the UK.

In terms of environmental compliance, the actual Saltfleetby Field presents fewer environmental hazards than a traditional oil field, as there is much less risk of fluid contamination to ground and water. Additionally electronic monitoring of flow has (for human safety) to be much more precise and involved than in traditional oil field practice. So on the whole we would regard the Saltfleetby Field as representing a much higher human safety risk but a much lower environmental risk than an oil field.

The exception is emissions to air. We require a flare at startup and some (but not all) maintenance events to acheive national grid specification gas, but otherwise we should not need to use the flare at all during the life of the field, although a tiny pilot flare is kept alight at all times to meet statutory requirements for emergency blowdown. Blowdown (i.e. flaring) for us means loss of principal inventory and commercial return – this is not an oilfield with associated gas as a headache. Gas is our reason for being here.

We have two scheduled group Zoom calls a day and, without any doubt, every day an issue of environmental compliance arises and is dealt with. At one level it is simply compliance (“what will EA think of this”) but at another level it is purposive (“what should we be doing or how could we do this better”). This is a sea change from the Angus of old.

We are committed to improving our carbon footprint – but we are led by an unforgiving Technical Director who rightly has regard to the “through-the-cycle” carbon cost of new equipment. Two innovations are planned – (a) a closed loop geothermal system for on site power generation up to 1MW and potentially retiring one gas fired generator and (b) a tie-up with a vertical farming operation which would take both heat, power for lighting and potentially CO2 emissions from the site for assisted agriculture.

We do, as a small company, adhere to the QCA. Up until December, on the strong encouragement of the Board, and whilst we awaited procurement and delivery of equipment to Saltfleetby, almost 50% of management time during 2021 was spent in developing our deep geothermal programme in southwest England. We are sincere in our desire to be an innovative part of Transition, but bear in mind that we are a small company at present focused on acting as a safe and responsible Operator in the immediate term and delivering good returns to those who have funded these operations..

Has a rig been ordered to drill the sidetrack yet?

Which month in 2022 do you expect the rig to arrive if so. Thank you. Asked on 2 May 2022
Yes. A rig was ordered in June 2021, considerable replacement parts for which were sourced from overseas. Although it was scheduled to be ready in October, none of the parts actually landed in the UK until December and as a consequence the rig itself would not have been ready until around now. This underlines the very real supply chain problems which we faced in H2 2021, and which continue to cause problems for many other Operators. If anything we think that the supply chain issues have gotten worse not better since then, and we are relieved to have our kit onshore.

There are alternative onshore rigs which we could have used for this side-track had we felt it necessary. The rig is undergoing testing and we do inspection reports and visits every three or four weeks. We are confident that it will be ready for moblisation at site at the end of June.

What would be a reasonable time frame for the steps for getting the Portland reperforated and producing oil? Asked on 1 May 2022
From Technical Director: “The work to recomplete the well to the Portland will involve abandoning the bulk of the well through the Kimmeridge to leave just the topmost part across the Portland. We would then perforate that section.

I am assuming 5-6 days work plus mob and demob and rig up and rig down. The perforated section may be fairly long as it is near horizontal which is good. The rig can be the small workover rig we used at Saltfleetby and we need little in the way of tanks and pumps etc, although achieving our targets on waste management on such an operation will involve additional cost.”

That is the “operationR21; but before that and in addition to local authority planning (obtained), HSE (BSOR) submission, NTSA notification (although agreed in our FDP), we will require the consideration of the EA. We do not believe that this should be a very complex affair as the well-bore was well-designed and recently spudded to modern standards, the hydrogeology of the area is thoroughly understood, not least by EA, and the target reservoir has been produced from for thirty years.

On current oil prices, and given a resulting flow of 100bbl/d, it would not be unreasonable to assume that the cost of the operation could be recouped within 5-6 weeks of flow. Operationally speaking, there would be no other upgrade to the site required.

Are there any revised updates for the Balcombe appeal please. P.S. I would like to congratulate GL for putting a very good case forward at the SCC meeting,well done! Asked on 30 April 2022
Having submitted our Statement of Case, WSCC submitted their Statement of Case during March and we responded with our rebuttal on 12 April 2022. The matter is now with the Inspector.

1. have the DSEAR Dangerous Substances and Explosive Atmospheres Regulations 2002 requirements been completed at Brockham?
2. will production from BRX2-Y resume at Brockham in May independent of the council decision regarding the portland perforations Asked on 25 April 2022
DSEAR regulations have an element of continuous assessment against ever higher standards but, yes, we are engaged in that assessment process and have achieved levels of compliance sufficient to continue safe operations and the production and export of of crude oil. As advised by RNS we will give further information on this in due course.

1.are they going to install a CHP? And never hopefully look at using the flare other then emergencies?,

2.are they going to look at investing in a AD plant so they always have a gas supply when the gas field Depletes?,

3. Would ANGS look at a investing in a CHP that can take natural gas?, and hydrogen?, maybe they need to speak to 2G as there at the top of there game in this Industry, and by having a a AD plant they would also get paid for the final cake dry matter and used as a fertiliser,,
Also I would be asking they could be getting paid from a local council to take food sate too!!, Asked on 31 March 2022
We won’t need to use the flare as part of normal operations although a tiny amount of gas is continuously burned in order to maintain a pilot light, much as on a traditional household boiler.

We do have gas fired generating plant on site to drive the compressors and provide site power. This is the most efficient way of producing and using off-spec gas which cannot be sold into the national gas grid and is an environmentally friendly solution in a remote location without an industrial scale connecton to the electric grid.

We also have been in touch with local landlords regarding the site’s potential to provide heat, CO2 and surplus electric to support vertical farming operations in neighbouring fields. This is likely to be a programme for consideration a year’s hence, alongside a relatively inexpensive geothermal power generation scheme using the Sherwood Sands reservoir.

What method of water injection will be used at Brockham to get maximum production. Could we also have an update about the Lidsey well please. Asked on 31 March 2022
The water injection permitted at Brockham is pumped and is subject to precise daily and hourly limits. As well as providing a cheap and environmentally sound method of returning highly saline formation water to its native reservoir as compared to incineration, the water reinjected acts to support the oil in the reservoir and aid extraction.

Lidsey will be capable of resumed production from mid-June when site modernisation should be complete. In fact there has been intermittent production this year – but not at a meaningful continuous level. Production at the time of shut-in involved a relatively high water cut and so we have to address the issue of formation water disposal in the interim on the commercial market (where happily costs have fallen each year since 2019) and in the medium term via disposal at Brockham (our preference as it is environmentally more sound and cheaper) which latter route would require, amongst other permissions, a non-contentious EA permit (a so called RSR permit) which we should obtain later this year.

At these oil prices, however, Lidsey is profitable, even with a water cut on the high side, so we will be progressing each of those avenues to restore or increase flow. The level of profitability depends somewhat on the success of the hot-oiling and borehole remediation works undertaken last year and we will advise the market by RNS when this data becomes available after a period of continuous flow.

As regards the longer-term at Lidsey, we are formulating a commercial proposition to the neighbouring licence holder in order to exploit the side-track target which emerged from seismic studies last year. However our immediate focus is overwhelmingly to resume Saltfleetby production and we think we are supported by all shareholders in this focus.

Can the company update shareholders with the latest comprehensive timetable for arrival of equipment and commissioning and first gas? Can the BoD also update the status of any remaining regulatory permissions being specifically the EA application and the Local Authority planning variation? Asked on 6 March 2022
Hopefully these have been answered in RNS. We do expect further (positive and negative) variation in particular skid arrival dates – we are adding sound absorbent materials to some units and bunding others – but the end April date for delivery of the last skid is unchanged from that advised to market.

Assuming the side-track is successful, how much cashflow will be generated (including hedged production) in H2 2022. Asked on 6 March 2022
Without offering firm predictions but solely to assist shareholders in considering the range of outcomes: the existing wells, prior to shut in in 2017, were producing about 5mmscf/d (million standard cubic feet each day). Allowing for a 28 day month and a conservative calorific conversion to therms, 5 mmscf/d is very approximately 1.5 million therms a month. We have already advised that we expect the Field would produce 5mmscf/d or 1.5million additional therms a month from mid-August, arising from the side track, giving 3million therms/month or 10mmscf/d for the last four and half months of the year.

We have several caveats to trying to make such predictions over such a period: first, that gas prices are exceedingly volatile at present and may move in any direction and rapidly; second that whilst we do not regard the side-track as exploratory in the traditional sense, all drilling involves risk and the level of sidetrack production could be more or less than the 1.5 million therms/month suggested. Third the hedge profile varies a little from period to period. Lastly the foregoing and the following is not advice by the company – but an illustration of how to calculate different outcomes from production figures which the Company will be able to advise over time.

The average hedged sales price is 43 pence/therm over the life of the hedge and the unhedged forward prices are presently not far off 300 pence/therm for unhedged sales in H2 2022. On the basis of a side track completed and online by mid August then H2 gross revenues (Angus share 51%) might be in the region of £24m which would ignore any benefit of unhedged production during June, potentially w0rth a further £4.5m at 300pence/therm. Again we repeat that this is not advice to shareholders but guidance on calculation only and investors are urged to do their own research based on RNS advised production levels and prices.



Hi, whilst I appreciate that being in an Offer Period makes communications with shareholders exceedingly sensitive, as a supportive long-term shareholder I have to say I’m disappointed by the lack or PR regarding the Saltfleetby field. Given that gas prices have quadrupled in recent times, I would have thought that the company should be shouting from the roof tops about the game changing positive impact that the rise in gas price has on the economics of the Saltfleetby field. Asked on 6 March 2022
Noted and thank you. We have indeed been limited in public communicatiions by being in Offer Period, but have been more active both on Twitter and in interviews recently.

[dillydally2] 29/6/2022 13:19

StillDumping

[sincero1] 29/6/2022 13:12

gasman there is a much stronger word you could use !

[gasman10] 29/6/2022 13:10

Still at it on here and LSE what a loser

[sincero1] 29/6/2022 13:09

hits "and explains the utterly underwhelming performance of the ANGS share price since yesterday's RNS." but the share price is still much higher than your 1p sell at a loss... and that is what drives your obsessive negative posting ... are you sure you don't need some psychiatric help ?

[headinthesand] 29/6/2022 12:58

George Lucan interview with LSE on March 28th this year:-

"Angus MD George Lucan predicts 1.5M gas therms in May"



How has that prediction turned out then? After all, it was only made three months ago...

About as well as the other notorious March one where George was confidently mentioning that the entirely unhedged sales of June production would at the then gas pricing bring in £7.2 million of revenue...

Except there's been no gas production at all in May. Or in June. And the hedge starts in 2 days' time.

The above neatly encapsulates everything anyone needs to know about ANGS - and explains the utterly underwhelming performance of the ANGS share price since yesterday's RNS.

[1347] 29/6/2022 12:53

Talking of ratty smells....

[sincero1] 29/6/2022 12:49

new twitter pics , that explains why the grey old stale urine smelling nobodies are posting so much today ... happens every time .. the humiliation makes them do it.....

[gasman10] 29/6/2022 12:35

You stink thats for sure

[jtidsbadly] 29/6/2022 12:33

1347: thanks for this. It’s hard to imagine that even Anguish would tell a porky on something like this, isn’t it? They must have got the permission, surely? As you know, I think the wording re SIMOPS is evasive. And there’s no question that Aleph has not yet bought the shares for which they only needed shareholder approval. That ratty smell is pervasive, what?

[1347] 29/6/2022 12:19

JT Yes, in my experience the EA put the updated permit on their portal fairly quickly once they have given approval, which they have (allegedly). It's absence, like tranche 2 of the Aleph subscription and their TR-1, along with the absence of a clear statement of what is, or is not allowed, in SIMPOPS remains unexplained.

I don't know about Knowe, they could already be selling down the shares they already have to replace them with conversion shares at an appropriate point, who knows but them and their broker?

[gasman10] 29/6/2022 12:16

https://twitter.com/angusenergyplc/status/1542102518569869317?t=qmLdRZuR5nLXYKDRxRjekg&s=19

[idriveajag] 29/6/2022 12:05

SENX about to start drilling for gas onshore Romania:Serinus Energy PLC29 June 2022Romania Drilling Programme UpdateJersey, Channel Islands, 29 June 2022 -- Serinus Energy plc ("Serinus" or the "Company") ( AIM:SENX, WSE:SEN) is pleased to announce that the two-well exploration programme in Romania continues to progress towards commencement of drilling. The roads and drilling platforms at both the Canar-1 well and the Moftinu Nord-1 well have been completed, including the installation of the drilling conductor pipe at both locations. The drilling rig inspection and certifications have been completed and final acceptance and rig mobilization is expected to be completed the week 4-7 July. Permitting for both wells is nearing completion with all permits expected to be granted imminently. Subject to the timely receipt of all permits, the drilling of the Canar-1 well is expected to commence on schedule in mid-July, and once drilling is completed, the rig will move to the Moftinu Nord-1 location and commence drilling.The Canar-1 well is located 4.0 km to the west of the Moftinu gas plant, while the Moftinu Nord-1 well is located 5.2 km to the northwest of the Moftinu gas plant. With success, production from each well will be connected to the Moftinu gas plant, utilizing current excess plant capacity.

[jtidsbadly] 29/6/2022 11:55

1347: is the EA usually prompt in updating permissions on its site? And when do you think Knowe may think about starting to short their converted shares?

Gasman: SIMOPS are planned. Subject to final satisfaction of internal risk assessment. Or, to put it another way, “we don’t want to give a straight answer to this or other difficult questions. Read into this statement what you will.”

[gasman10] 29/6/2022 11:40

Will the SFB sidetrack be drilled with continuous Gas production or will the gas production plant be turned off for the duration of the drill?Subject to final satisfaction of internal risk assessment SIMOPS are planned – i.e. simultaneous drilling and production. These is not an abnormal choice and indeed is common in far more restrictive areas such as offshore rigs. The plant when fully up and running benefits from a state of the art fire and gas leak detection, rapid blowdown and full set of monitoring and control instrumentation connected to a PLC as well as a full complement of alert operators.