Investor Questions

We cannot release that level of material detail except by RNS.  However, given what has already been announced, we can say that if we were to hold production at around 90,000 therms against hedged volumes of 50,000 in, say, December then obviously at the higher price of 200p/therm our unhedged production alone would be £2.3 million of gross gas revenue versus £1.5m at current forward prices.  These figures are after allowing for maintenance time and are over and above revenues from our fully hedged production.  It is likely that a proportion of this would go to accelerated reduction in the remaining £7.3m of senior debt but would make a refinance obviously even easier if it is not already complete by then.

We are enjoying these right now and every day.  We have a considerable pool of historic tax losses, arguably worth in tax relief more than the market capitalization of the company on the basis of projected prices and production and current rates of taxation.  These losses are presently being used to shelter current profits against Petroleum Revenue Tax, Supplementary Charge and, to a more limited extent, the Levy.  We are also closely monitoring the thinking of the Treasury and the Prime Minister on the way in which the Levy tax may evolve.

One of the reasons we had wanted a global refinance in the first place, is that the current senior loan facility “sweeps” away excess cash to accelerated debt repayments which means that exploratory capex, as at Balcombe, will need to wait for a refinance and certainty that no appeal against the recent judgement will be made or accepted.

That said,  the refinance completed, this will be amongst the top priorities for 2024.  Assuming no appeal is accepted or successful, we will begin re-engagement with the local community regarding their concerns and with WSCC regarding satisfaction of planning conditions and the EA regarding permit conditions as well as upgrading our plans for what is, initially, a very minor intervention.

The second stage – a full well test spread – would only proceed if the winning of commercial volumes of oil was determined to be an exceptionally high probability in the relatively simple first stage of works but we cannot leave an indefinite pause between the two stages to seek finance.   Angus farmed into a 25% interest into Balcombe some six or seven years ago at the height of the broad-based enthusiasm for the Kimmeridge as a play in the Weald Basin and presently the Board is weighing the cost of the various stages of the operation versus our interest in the field and we have opened discussions with our partners in the field regarding those respective obligations and interests.

Thank you. There have been a great number of questions about the recent bridging debt conversion.  When I took on this job in April, I was aware that the cost overruns on the recently completed drilling programme and the well tie in could be substantial – particularly as the complexities of the tie in had not been fully appreciated by the Company’s existing technical team.  Managing these costs and overruns has proven to be very time consuming and challenging.

We sought debt over equity because, for the anticipated length of time of six months prior to a refinance, even expensive debt is generally a better option than rawly dilutive equity which has a permanent impact.  It is deeply regrettable that the time elapsed in finding a refinancing partner was greater than anticipated and co-incided with a dramatic drop in the commodity price over spring and summer with follow on impact on the share price in common with many of our peers in the North Sea.  At this low share price shareholders, such as yourself, have become understandably concerned about the risk of the remaining £6m junior debt converting at even lower share prices.

The first £3m bridge facility, raised in March, reached its maturity around the end of September.  Had we not reached an agreement with the debt holder, then that facility would have automatically defaulted by its terms and in turn defaulted the other facilities, senior and junior.  Such a situation, whilst manageable in itself as we are cash generative, would have made a refinance nearly impossible.  Instead the conversion, admittedly very painful at these prices, removed £3m of debt from the balance sheet and has upgraded the chances of a cheap and successful refinance from good to excellent.

What remains to be refinanced will be about the same sum as the £12m we raised in 2021 to develop the field in the first place, as by year end all but c. £6m of the senior facility will be repaid and the only other debt remaining is the second c. £6m bridging debt.  The difference between now and 2021 is that we have a pipeline connected, a site processing gas and a third well successfully delivering in a very high gas price environment.  Today, also, we are producing about 40,000 therms above hedged volumes, as can be determined from our accounts and the National Gas website, and so we are finally enjoying prices per therm for some of our gas which are well above 100 pence without the drag of a hedge.  This is a much lower risk proposition for capital providers and a great opportunity for equity investors too.

So the refinance is a smaller ask and an easier proposition.  At this moment in time we have every reason to remain very confident that we will be able to present to shareholders a refinance proposition for all of the remaining debt, at least in principle, before year end and at any rate before the other £6m bridging facility matures in late January.

Personally speaking I am not aware of, and I would not wish to be a party to, any arrangements to take this Company from all of its shareholders other than at the fullest value achievable and in the most transparent fashion. The Board and Management continue to work for the benefit of all Angus’s shareholders to unlock the significant value in the Saltfleetby Field and resolve the short term funding issues in the company.

Data collected since the field restarted production in August 2022 have confirmed that there is very little off-spec gas being produced. As a result, the gas generator would be burning predominantly sales gas, which at higher gas prices is economically less attractive than generating power from the field’s diesel generators. We continue to evaluate options for a more permanent and environmentally-friendly site power source.

Thanks.  The aim is to have the booster gas compressor installed in Q4 2024 in order to optimize recoveries from the existing wells in line with the expected decline in well head pressures as the reservoir depletes.  It is not so much a matter of cost savings as revenue gains as the booster will allow us to run the wells at higher flow rates.

As of this morning, we are currently producing around  93,000 therms a day as will be evident from the National Gas plc websites.  As previously announced, we produced an average of over 86,000 Therms per day in the third quarter, which included the impact of a planned 4-day shutdown. We are consistently producing well above the volumes which were hedged at low gas prices at the onset of the project. As explained in our recently published Competent Person’s Report (CPR), we do not expect gas sales to go above 100,000 Therms per day until new wells are drilled in the field in late 2024-25.

We cannot comment on the plans of individual shareholders.

We are still scoping the design of the booster compressor and evaluating the options available and pricing. Once we have made progress in the selection of the booster compressor, we will update investors.

We continue to engage with interested parties on the storage potential of the Saltfleetby Field and will update investors when there is solid progress to report but at any rate with an update before year end. We continue to see high levels of interest in the storage project.

As previously reported, engineering work for the installation of the permanent flowline is underway. Civil engineering work has been completed and fabrication of the flowline is well advanced. We had hoped to install and commission the flowline at the beginning of September, but contractor delays have pushed completion of the work into October. We plan to update investors on the timeline for commissioning of the permanent flowline soon.

We are still waiting to hear the result of the appeal against the Balcombe decision, but expect some news during the 4th quarter. We will keep the market informed as we hear any news.

The drilling of new wells or sidetracks in the future will use the learnings from past drilling in the field to minimize the impact of solids during clean up and initial production. We do not expect to see the same level of solids production as we have encountered in the B7 sidetrack and if we do, we will design temporary flow facilities that can deal with it.

The Southern Lobe area is smaller than the main culmination of the Saltfleetby Field, and the connectivity of the Southern Lobe to the rest of the field is unclear today. For this reason, the gas in the Southern Lobe is currently considered to be contingent resources, not reserves. Angus is working on a new subsurface model to remap the Southern Lobe and quantify the potential there.

The share price has been underperforming largely because of uncertainty around the short-term debt which the Company took on earlier this year to fund a shortfall in our hedge payments in 2022 and cost overruns on the drilling of the B7 sidetrack. We announced last week the conversion of £3 million of that debt into equity and are actively working to refinance the remaining £6 million bridge loan before the end of this year. We expect to update the market on our progress with the refinance soon. We believe the successful refinancing of Angus’s debt, combined with the strong cash generation potential of Saltfleetby Field and the long-term potential for gas storage will see a re-rating in the share price.

Work on the global financing is ongoing and we expect to be able to update investors on progress very soon. As part of this effort, we announced last week the conversion of £3 million of bridge debt into equity, reducing our leverage and avoiding expensive roll fees and future interest payments on that debt.

Angus’s hedge position extends to June 2025. All historical hedge payments, including the rolled hedge payments from July-August 2022 when the plant start-up was delayed, have been made and at current production levels, the company is comfortably meeting its hedge commitments.

A number of factors will affect daily and weekly production including ambient temperature, liquid management and flowing well head pressure.  The production plan for Saltfleetby has always been to deliver sustainable volumes to the National Grid and optimise recovery from the field.  This plan may well involve additional producer wells and will certainly include the installation of a booster compressor in early 2024 (as advised in our CPR of October 2021), which will allow for processing at well head pressures far below those seen today.   Therefore shareholders should expect some variability in production in coming months as we carefully and actively manage all of these factors.

Angus’s core asset is the Saltfleetby Field in Lincolnshire and our focus is on sustaining the safe, reliable operations at the field that we have been able to establish this year. Our short-term priority is to complete the installation and tie-in of the permanent flowline for the new B7 well, which will reduce monthly operating costs substantially over the present temporary flowline. We are evaluating options to purchase and install a booster compressor to allow us to fully deplete the reservoir and we are evaluating options to drill an additional well or wells to accelerate recovery from the field.

We are also evaluating the other assets in our portfolio, the Southern Fields, with a view to making a strategic decision on the future direction of the company. We will communicate more on this in the near future. Angus continues to look at other opportunities which could provide an attractive strategic fit to the portfolio.

We have also made progress in reorganizing the company to strengthen the technical and managerial capability of the company while maintaining a firm control on costs.

The pipework for the permanent flowline is being fabricated for installation during September, with a goal of commissioning the new line in early October. This will remove significant costs associated with the current temporary flowline – rented equipment, manpower and waste disposal costs, making our operating costs significantly lower and competitive.

As communicated in July, Angus is working on the refinancing of its current debt-position to establish a longer-term debt facility at lower cost than the current arrangements. We are talking to a number of potential lenders who are in a due diligence process with Angus. We will update the market when there is information to share.

The overriding royalty interest begins to be payable when the senior debt is repaid as previously announced in RNS of 30 November 2020 and the cost of this has been included in our CPR of October 2021 which valued the Field (as P50 and after debt and these royalties) at c. £70m.  Since we are engaged in an accelerated repayment schedule on the senior debt anyway, any refinance is likely to accelerate the first royalty payment date by no more than a few months.

Still in the hands of the Courts!

No that estimate did not include the Southern lobe of the Field.  The cost would obviously be spread over the period of construction and funding options are diverse including forward sales of capacity, grants, JVs etc.

The CEO and Board are very aware of the drop in Angus share price during the last 3-4 months and are fully committed to reversing the trend. We recognize that while some of the fall is linked to external factors, there has been concern about the company’s increasing debt and questions about our cash generation capability. Our increased debt position resulted from legacy cost and schedule issues which are now behind us; we are working to refinance our debt to remove the short-term, expensive debt which we were required to take on.

The Saltfleetby Field is now operating safely and reliably at production levels significantly above our committed hedge volumes. We are looking at strong free cash flow generation going forwards, once the permanent flowline from the B7 well is installed. This will allow us to pay down debt and strengthen the company’s finances. Angus is now strongly leveraged to gas prices, so any uptick in gas price as we enter the Winter months will have a big impact.

We have worked during the summer to raise the additional debt required to meet our legacy hedge commitments, establish solid operations at Saltfleetby and strengthen and streamline the Angus organisation. We fully understand the importance of open and regular communication with shareholders and will ensure that during the Autumn and beyond, we communicate regularly and effectively.

We will update the CPR at Saltfleetby at regular intervals. One we have completed the building of a new reservoir model, we will revise the CPR, likely in the first quarter of 2024.

Production has now stabilized from the B7 well and the amount of fines being produced has significantly diminished.   We could push B7 well harder, but to the detriment of the smooth running of the process plant with all three wells so, for the time being, we are content with the flow being achieved.

This remains an option for the future. We are remapping the reservoir with new seismic to help define further drilling opportunities among other things.

Installation will take place during August with commissioning at the end of the month, coincident with a planned plant shut down.

Point taken, there will be communication with shareholders after the summer on the direction which Angus is taking.

This will happen as advised.  Watch this space.

All interest received is under express or implied confidentiality at this stage.  What we can say is that the attraction of the field is the infrastructure and potential links direct to the Humber where a variety of H2 and CCUS projects are contemplated in addition to the possibility of using the field for natural gas/blended gas storage.

They are not that high! Nevertheless, running costs/month are not yet stabilized because of (1) additional costs related to commissioning the plant and optimizing performance; (2) the relatively high costs of producing the new B7 well through a temporary flowline while the well cleans up and the permanent flowline is constructed (expected to enter service at the end of August 2023); completion of the project to commission a gas generator in the next 2- 3 months will reduce energy costs and allow Saltfleetby to generate its own power. There will be a big focus on costs in the second half of this year.

We are producing about 160 barrels/day of condensate through the plant.  It is not something we have a choice on, as it is there in the reservoir in the gas and we need to remove it at the Saltfleetby facility before we can dispatch gas to the National Grid – one of the main purposes of the process plant in the first place.

There is additional condensate being separated from the temporary flow line which is not included in the above figure.  Managing this separate flow, whilst we prepare for the permanent flow line, has contributed to the higher opex we have had in recent months.

The traditional estimate for assessing the income generating capability of a storage facility was to take the winter summer spread and apply it to the amount of gas capable of being injected/extracted on a seasonal basis.  In this instance, Gazprom selected this field as it was/is the largest UK onshore gas field and they estimated between 700 and 800 million therms as working capacity.  The next biggest onshore storage facility is less than half the size of this field.

Gazprom decided not to proceed with the project in 2012 because the seasonal spread, traditionally about 40p (2006-2010) shrank to almost 5p (2011-2014).  Taking only 10p as the spread available to the Operator and the annual income generated on 750m therms would equal £75m.

However much has changed since 2019.  Volatility has risen, with lows of 7p and highs of 455p and with very limited Russian supply to Europe there is every reason to believe that volatility will remain elevated and not necessarily predictable on a seasonal basis.  Second there is growing interest in CCUS and H2 storage.   H2 storage is likely to present similar economics to natural gas but CCUS is a very different economical proposition – a one-off disposal but at vastly higher prices per tonne.

The economics show great potential profit and at this stage all that Angus is seeking to preserve is some optionality for its shareholders over this income stream whilst advancing our engineering designs and consultations with stakeholders and initial permissions from planning bodies.

A further Local Authority planning application is required to drill a new well, although further wells at site are covered by the existing Environment Agency permit.  Other interventions, such as booster compressors or velocity strings, can be dealt with under the existing permissions with non-material amendment applications.

The company is drawing up plans to install a third compressor, but this would be a more modest booster compressor to allow the wells to produce down to a much lower abandonment pressure while providing gas at an adequate pressure for the 2 main operating compressors. When the second compressor was offline, we still had the benefit of the other compressor, which kept our production at 2/3 of full production.

The £3.5 million derivative payment was the final payment for hedge volumes not delivered in Q3 2022 when production start-up was delayed. Since then, Angus has always met its monthly hedge commitments, so there are no other past months to consider.

The Aleph Group introduced a considerable number of private investors to Angus’ share register and as providers of debt capital both senior and junior.  Some of these holdings were held by Aleph Fin C – a special purpose company which acted as nominee for some of these investors.  As best we can determine from our register, the shares in question were simply transferred into the beneficial owners’ own accounts.  We have been told that this legal restructuring was long planned and on examining our register we have not identified any sales by Aleph introduced parties, but only purchases.

Angus’ long term solvency is presently unquestioned but liquidity is tight this year principally because of the temporarily increased opex, lower spot gas prices, historic hedge payments, the accelerated repayment schedule on the senior debt as well as the overruns on the drilling operations.  Many of these factors have gone away or will go away as we enter into autumn.  We have been open about our liquidity need, sensitive to shareholders concerns about dilution and clear about our plans to refinance all of the debt into a term loan of greater duration, and we consider this a reasonable target.  The lending community were prepared to advance £12m in May 2021 when the site had no connection, no process plant and no third well and gas prices were muted.  Now we have all three and steady production at or near our target and forward gas prices which are historically high.

At present Angus is conducting a project to reassess the subsurface model of the Saltfleetby Field, based on recently reprocessed 3D seismic data, and on the basis of that work, differing options to drill an additional sidetrack will be evaluated alongside longer term storage potential. It is likely to be late this year or early next year that a case is put forward.

As answered elsewhere we are already preparing an application to the local authority for permission but have the other long-lead permit in place.  The costs of new wells will certainly attract some relief from tax and potentially very high rates of relief from the Energy Levy tax at least as regards any well that is dual purposed for potential decarbonization injection, and this is a consideration which we will take into account when determining how we will finance any potential drilling programme.

We are working with the production history data and subsurface model to recalibrate the Saltfleetby model and determine the forward production curve and opportunities for additional investment to maximize production. We are very satisfied with the production to date since the plant was completed and the third well tied in.

Both compressors have required maintenance in their initial months of operation.

With production up at Saltfleetby, the Board’s priority now is to identify inorganic opportunities for growth which would provide the route to a £100m valuation. The Board is also evaluating the potential value in the longer-term of a gas storage solution at Saltfleetby.

Yes.  Third well.  Amended thanks.

There has been more extensive maintenance undertaken than originally planned on the B Compressor Caterpillar engine, to date involving only relatively simple replacement parts.  These are generally reliable engines but this is the first service after re-entering duty and just like a car, the first service is often where the most work has to be done.

You are right that cashflow from the field is obviously very strong but our repayment schedule on the senior debt also accelerates with that higher cashflow and this final rolled hedge payment (arising from late production in 2022), when netted with other rolled hedges,  turned out to be larger than expected.   Angus is taking on additional short-term debt to manage the settlement of that hedge as well as to provide working capital for Saltfleetby and evaluation of acquisition opportunities.  The alternative to this debt, which is necessarily subordinated to the senior debt, is equity – and that would be an expensive solution for what is only a short term cashflow issue.

The B7 well has continued to clean up over time, although it has taken longer than predicted, we believe because of the chemicals used in the reservoir section when the sidetrack was drilled. We are confident that the clean-up will be sufficiently advanced to allow the well to be connected to the facilities with the new permanent flowline when that line is expected to be ready by the end of August.

Yes, unless the Board considers them to be in possession of price sensitive information not yet released to the market – i.e. if management were evaluating disposals, acquisitions or approaches etc etc.

Releasing quarterly production RNS today/tomorrow and will detail production of gas and condensate.

We have seen a sector wide decline in share prices due to a) the commodity price falling from an unusually high level and obviously into the summer months, b) the punitive UK taxation regime; and c) continuing political rhetoric around the industry.  Recently we have seen recovery in forward gas prices and we expect sentiment to strengthen as we enter the autumn.   We have also seen the first steps toward a more equitable tax regime in the discussion of a threshold commodity price for the imposition of the Levy tax.  However the hot air blowing around the subject from politicians is probably a more reliable feature of modern life than the gusts around those offshore windfarms.

That’s the aim.  We had a great many questions around other assets (Brockham, Lidsey, Balcombe) and projects (Geothermal and Storage) as well a new seismic interpretation and a study on deliverability and volumentrics at Saltfleetby which will be informed a month or two’s flow and pressure data on the third well.  We will update with a full presentation to shareholders over the summer on these initiatives whether singly or with a combined presentation online.

We are bullish for a lot of reasons.  One is diminishing investment in new fields (already in evidence over the last four years) accelerated in Europe by punitive taxation and dramatically rising costs of acquisition and extraction.  We also see significant volatility ahead – Germany, UK, Denmark and the Netherlands have all invested in significant wind, hydro and solar – but it is pretty much the same regional rain, wind and sun that they rely on.  It goes off in one country for a month or so, it likely goes off in them all and there is nothing but nuclear, gas, and limited battery storage to fall back on.  Volatility is likely to increase with such obvious risk concentration across norther Europe.  We also doubt whether the national transmission electric grid can ever be sensibly upgraded to take on the duty of gas in 20 million domestic boilers or even just the charging of 33 million cars nationwide in place of oil.

We don’t believe that it is the marketplace that investors concern themselves with but rather the market capitalisation of the Company.  Getting above £100m market capitalisation is a key target to attract even the first wave of insitutional interest, and so improve more volume traded daily in the stock and broader retail interest as a consequence.

The permanent flow line programme is underway but won’t in itself improve gas flow rates from the well but it will increase our room for maneouvre in terms of mixing and matching the flow from wells, as well as our ability to measure condensate flows from each, and it will reduce the monthly opex.

Improvement in flow should ordinarily occur simply with ongoing flow of gas carrying drilling fluids and bridging agent back to the surface.  This was initially rapid and continues now at a slower pace.   Most wells on the field were never acidised and the oil based drilling mud was left to be thrown out by steady flow of gas, so full clean up of some past wells took a couple of months.  We needed to acidise because of the calcium carbonate bridging agent used and the heavy mud weight employed.  Nonetheless it is too early to give an update on flow rates and projections of final deliverability.

The Courts have given Frack Free Balcombe Resident’s Association and other parties an opportunity for  a two day hearing late July to present their arguments which we (and the Government Legal Department) do not believe to have merit.  Angus could have proceeded with the operation to clean up the well (incidentally demanded by West Sussex County Council as part of abandonment) but, whilst this is neither fracking nor drilling, we prefer to defer action until the Courts have made a final pronouncement.  We have invested a good deal into Balcombe, the site is sensitively set between commercial forestry, a sawmill and the London to Brighton main line and will be maintained to the highest environmental standards.  Yes, the Court permitting, we will pursue the entirely legitimate activity proposed of meeting the national need for hydrocarbons cheaply and with a lower footprint than oil imported from warmongers and dictactors the world over.

The initial planning application is for extraction from the Namurian and would be followed by an application at national level for repurposing that reservoir for storage to the extent that this is commercially feasible.  These activities could proceed even whilst extraction continued in the Westphalian above.  We have stressed that this is subject to a first full seismic interpretation of the lower layers of the Field.

Storage activities in the larger but less permeable Westphalian above would need to wait until the benefits of further extraction from the Westphalian were outweighed by the commercial advantages of operating such a large gas storage facility.  Given recent price volatility of over a £1/therm in a month, it is difficult to estimate when that might be the case or quite how profitable a strategic storage facility of around 800 million therms, as Gazprom originally envisaged, could be in the coming years.

The advantage of the route which we are proposing is that Shareholders will have an opportunity of incidentally supporting the drilling works necessary to evaluate an eventual storage project in the Namurian, which is not yet well understood or fully interpreted despite past recoveries of 1.5 bcf, with at least a reasonable prospect of more commercial recoveries of gas from that same reservoir and without interrupting simultaneous extraction in the Westphalian.

We are in a close period due to forthcoming interim accounts.  For general information this is the definition from the AIM Rules for Companies:

CLOSE PERIOD (i) The period of two months preceding the publication of an AIM company’s annual results (or, if shorter, the period from its financial year end to the time of publication); and ♦ if it reports only half-yearly, the period of two months immediately preceding the notification of its half-yearly report or, if shorter, the period from the relevant financial period end up to and including the time of the notification; or ♦ if it reports on a quarterly basis, the period of one month immediately preceding the notification of its quarterly results or, if shorter, the period from the relevant financial period end up to and including the time of the notification; (ii) any other period when the AIM company is in possession of unpublished price sensitive information; or (iii) any time it has become reasonably probable that such information will be required by these rules to be notified.

We see this as pessimism around the gas price brought about by typically low summer prices after last winter’s panic overfill of Europe’s storage capacity.  We are not alone  – see Hartshead, Kistos even Harbour share price charts in the last few months.  As answered elsewhere we think this is short sighted and would point to high winter month prices.

Principally tripping has been to do with increased flow rates but also load balancing around the compressors, the control systems and ongoing teething problems with the units as the flow from the third well is settling in.  The plant seems to have steadied now but we do have a two/three day shutdown planned for June, and will have shutdowns in future months.  They do not mean that there are any insurmountable problems and we aren’t budgeting for regular outages, beyond a day a month’s maintenance shut down.

We are engaged in a full end-of-well analysis and will meet with our drilling contractors to discuss the same.  We came to a solution of heavy mud weight with calcium carbonate as a bridging agent by expensive half-steps throughout the drilling process but we think it is the right solution for the special circumstances of the Saltfleetby Field – i.e. non-hydrocarbon layers which are prone to collapse and a depleted open hole hydrocarbon bearing section at risk of loss of fluid to formation.  Nonetheless there are doubtless other lessons that could be learned and the successful technique which we finally developed could itself benefit from further study and improvement.  Without prejudging that analysis, we would say we are tentatively more confident of drilling further wells here without the same issues or expense.

You can expect at least one interview in the next few weeks as we endeavour to advertise our increased flows to the wider market.  Thereafter we would expect to be giving a fuller update on Company strategy, by way of online/mediated presentation, likely during June.  We are conscious that in the past we have overpromised and underdelivered as regards timelines, so we are reviewing our corporate communications and use of Twitter in order to ensure that any statements can be made with a high level of conviction and so to build a deeper level of trust with shareholders. large and small.  Nonetheless we will make use all contemporary forms of communication.

The Company is certainly committed to paying a dividend as soon as reasonably practicable.

Yes this was always the plan.

On 18 April 2023 we announced the actual flow test results from the previous weeks’ multi-rate flow test.  The RNS went on to state that “whilst [the well will be] producing through a temporary connection, the new well flowline will be constructed to enable full plateau production this summer”.

Although the last reference to the summer has been misinterpreted by some investors as suggesting that there will be no commercial production from that well until summer, which is not at all expected to be the case, we believe that the announcements have not been misleading although the reasons require some technical understanding of how we expected clean up to proceed in the RNS of 28th March and how it actually did proceed.

During clean up operations we recovered a significant amount of drilling mud (with light base oil), but also aqueous hydrogen chloride (unspent acid), calcium chloride and trace amounts of calcium carbonate (the bridging agent), along with sand and other mineral particulate (formation).  In short we had deliberately performed an intense acidization to clean the productive wellbore of an equally heavy amount of calcium carbonate, which was employed during drilling to prevent hole collapse, leading to high levels of solids in the reservoir formation around the borehole.

It only became clear quite how long it would take for these solids to dissipate during the course of the well clean up and it should be understood that they also pose a risk of damage to the processing plant if they are not managed carefully.  For that reason, the new well is being introduced into production in a slow and careful fashion and earnest time has been spent in the last fortnight performing thorough and professional assesments and mitigations of any residual risks.

As of going to press, all of this equipment necessary to mitigate these risks has been procured and added to the temporary flowline and thus we stand ready to make the first attempts to flow gas into the system.  Given this is material information and we are in any event obliged to update our earlier timetable of sales gas by the end of April, we will make an announcement by RNS on Tuesday 2 May on the status of the connection.

The 2 existing producing wells, A4 and B2, are currently flowing at 5-6 mmscfd.  The recent multi-rate flow rate on the B7 well has shown the potential for this well to produce at 4-5 mmscfd at a flowing pressure of 30 barg, with potential to clean up further. With 2 compressors now available, and taking account of the condensate stabilization capacity of the plant, there is clearly potential to produce at 8 to 10 mmscfd from the 3 wells.  It will take some time to balance the plant to accommodate the new well and dual compressor operations and shareholders should be able to see a rise in exports from National Grid’s website over the coming days and weeks.

The duration of well clean up is highly dependent on the nature of the drilling fluids used during the drilling phase of the operation. In the case of the B7 well, the need to bridge the formation with calcium carbonate mud to prevent fluid loss to the reservoir and differential sticking has led to higher levels of solids flowback. These solids are a consequence of breaking down the bridging agent with acid to allow gas to flow into the borehole. Samples taken during the well test indicate a steady reduction with time in solids production and this is expected to continue during the production phase. We know from other Saltfleetby wells that clean up can take a number of months to achieve.

We will be reviewing the End of Well Report with all drilling counterparties in May and can report further then.  Drilling at the Saltfleetby Field is challenging because of hole stability problems in the section above the reservoir and the pressure depletion in the reservoir.

In the drilling of the B7 sidetrack, among other learnings, we found that calcium carbonate as a bridging agent in the drilling mud is an exceedingly effective tool both against hole collapse and losses to the formation.  Subsequent drilling programmes will benefit from this knowledge in terms of duration and cost.

Following acidisation and N2 lifting of drilling fluids any decent gas well can be expected to flow immediately.  Acidisation took place on Friday and N2 lifting was completed on the morning of Saturday 1 April.  We will therefore report initial flow rates for the first 36 hours via RNS on Monday before 7 a.m., however these rates are presently evolving and will be subject to further change (normally improvement) over the following 72 hours as the well continues to blow back residual mud and calcium carbonate.

We have a number of commercial and planning issues still to complete before activities can commence and our technical team has been 100% focused on SFB.  We will update the market on this matter in due course.

The final Measured Depth (MD or total length of borehole) was about 200 metres less than expected.  We had great gamma readings, and cuttings returns, all along the reservoir section and opted to conclude with a generous acquired length of productive reservoir rather than risk everything for an extra 100 or so metres.  Total Vertical Depth (TVD or simple depth from surface) should have been roughly as expected.

Yes, coiled tubing was always planned for in order to acidize the open hole/slotted liner section of the well.  This was particularly so as we were using Calcium Carbonate as a bridging agent.  The delay was in availability of the coiled tubing itself.  Once we were delayed in our programme our original supplier was unable to meet our revised timeline and so we turned to another supplier who only had this slot at the end of March.  In many past wells at Saltfleetby and elsewhere the wells have been left to clean themsleves (let the pressure of the gas blow back any oil based mud) but with a depleted field it was thought better not to risk any sealing of the formation by virtue of the mud and calcium carbonate.  You will be pleased to hear that the tubing did arrive and acidisation has been completed and we will follow with an RNS on the initial well performance on Monday.

We don’t provide monthly data on hedges but only quarterly data on production.   However you can glean information from nationalgrid on the production.

Our tax advisors have confirmed that the costs of the sidetrack are indeed eligible for deduction against the energy levy although the exact mechanics of the deduction are complicated.

Due at 7 am on 2 March.

Yes.  A further CPR is due to be performed.  We will need a good understanding of steady state flow rates to complete it.

I am happy to say that there should be an RNS tomorrow (i.e 2 March) that will provide a full update.  Apologies for the delay in answering monthly questions.

Both groups of major shareholders have informally expressed an interest in a high dividend policy.  This becomes possible as soon as the senior debt is repaid.  Assuming this sidetrack is successful and present gas prices hold around current levels all debt should easily be repaid this year which would pave the way for announcement and implementation of a realistic, but high, dividend policy.

Thanks.  They are a useful tool and we shall use them more often.  When this sidetrack is behind us, we will set out our aims.

Looks like a data error.  We nominated, produced and confirmed delivery of a normal amount on the Gas Day beginning 13th Jan at 5 am.

A second compressor would in theory allow us to push the existing wells a little harder (i.e. 6.5mmscfd and above) and let the well head pressure consequentially drop back, because we could bifurcate the overall gas flow into two compressors and each compressor would have a lighter volume duty but a bigger pressure uplift.  This has not been modelled in detail because we are not planning for a failure of the sidetrack, but it may exist as a contingency.

We haven’t released opex costs per therm across the plant or broken them down into specific elements of the process.  In general the opex cost of the compressors is maintenance and fuel (which is our own gas and we don’t tend to account for it as a separate cost).  So in some senses the additional compressor will double the therm throughput but there will only be a marginal addition to the opex.  So opex/therm should fall.  Looking across the plant the opex/therm will fall anyway as the bulk of the opex costs around plant are actually fixed, not variable.

We understand that we have an Inspector assigned from PINS but as of today nothing more.

No we had a normal week all week.

As advised our schedule has generally envisaged the second compressor being ready to take gas from this sidetrack when it is completed and that advice is unchanged.  One issue is the availability of gas for differing levels of wet commissioning.  In an ideal world we would wait for the testing sequence on the new well (through a test separator) to be completed before flowing the gas through the plant and this new compressor.  So we could have both new well and new compressor functioning this month but it may be tight so we cannot give, and have not given, firm advice to the market on this.

There are two parts to this Chance of Success – one is reservoir risk which we have always had a very high level of confidence ‘(i.e. 90%++) and continue to and the other is technical drilling risk.  This latter is never easy to set a number upon as every drill has an element of risk which can’t be mitigated.  Despite rumours to the contrary, drilling at Satlfleetby was, on a review of wells for 20 years, not particularly bad or good from a technical drilling standpoint.  However there are two complications to note in this Field.

Many drills by previous operators experienced hole collapse in the marine and coal bands just above the reservoir although in almost every instance these were overcome with a few days work.  In fact well 1U (drilled by Candecca in 1998) which ran a parallel track to this target well bore was itself the result of a sidetrack of 1V when 1V encountered similar (and additional) problems compounded by lost in hole equipment.  Well 1U was the Saltfleetby Field’s best well, hence our high confidence about the reservoir here.

The second complication is that the reservoir is depleted and not at virgin pressure, so the drilling assembly and mud is at risk of going off into the reservoir at an angle to the well bore track we want it to follow (differential sticking).  The calcium carbonate bridging agent we are using in our drilling mud has had similar usage in several Dutch offshore wells in the southern North Sea in similarly depleted situations so we know it works well.  It creates a temporary seal along the borehole which keeps the mud in the hole and the drilling assembly on path, so to speak.

This time round we are going in with plenty of additional tools to meet all of the exigencies which next few days may present and we now know more precisely what to expect at each level.  We can’t make an easy pronouncement by RNS on technical drilling risk but, if anything, we should be more confident with this second pass than with the first.

The sidetrack drilled before Christmas into the top of the reservoir encountered in January a very small fracture system which had not been captured by our seismic study.  This would not have been an issue had we not been working in small bore, or so-called skinny drill pipe, as a consequence of laying 5.5″ liner to secure the coal and marine band zone behind us.  The use of this smaller liner, rather than 7″ casing, was driven by the nature of the formation we had passed through and in turn this required us to use this lighter drill pipe.

Rather than try to clear or work around the fractured zone, as our predecessors had spent a fruitless month trying to do back in 1998, a decision was made to back up about 100 metres, mill a new window in the 7″ casing, set a second whipstock and re-enter the reservoir via 6″ open hole and more robust drill pipe and bits.  This was also the successful solution arrived at by Candecca in 1998.  This we have done and as of 31st Jan we are drilling forward in earnest along the timetable given in RNS.

In addition we are increasing the mud weight to secure each of these vulnerable zones, but using calcium carbonate throughout which will act as a bridging agent inside the Westphalian and prevent mud and drilling tools being displaced into the reservoir away from the borehole (differential sticking).  In short we have more room for maneouvre and even if we are forced to use 5.5″ inch liner again, we have more mitigations in terms of equipment selection and mud weight.

The 2nd Compressor arrived shortly before Christmas and is already being installed.  Installation will continue during drilling operations as all hot work is being completed off site and only flange fittings are being made up for in situ tie in.  Full electrical tie in will run concurrently with the drilling programme until mid January when the focus of the plant will shift to integration of new production from the well and good functioning of the compressor.

Some selective insulation and trace heating is in place and all methanol injection ports (there are five in total) are functioning.  Certain areas of the plant are also naturally sheltered and have innately generated heat.  However, even given all these measures, the cold snap did show up gaps in our winterisation programme.  It reached -11 degC which is close on a local record at the site and we were particularly vulnerable from non-weather related shutdowns slowly become temperature events as the plant cools down.  Normally we can restart within an hour but on several occasions during the cold snap it took us several hours to restart after a trip, with each passing hour throwing up a new temperature related problem.  We are installing additional trace heating in early January.  That said, it is in fact easier to achieve gas quality specification in cold rather than hot weather.

As stated elsewhere, we know the plant can handle 6.5mmscfd operating with one compressor as we have achieved these flow rates intraday for the last three months.  With two we should be able to double flow rates and the JT won’t be the bottleneck.  Our concern is actually liquid management across the plant.  The designers had reckoned on about 95 barrels a day of condensate from the combined flow of 10 mmscfd.  Whereas we are looking at nearer 120 bbl/day from about 6 mmscfd.  This higher condensate gas ratio may reflect the fact that historically the site never measured the actual condensate rates with any accuracy – stabilisation and cleaning the gas was left to Theddlethorpe refinery so they had the book on that.  It’s a real problem to have but a nice one as we don’t believe that the liquids will limit our gas production.

No but it is helpful to have as supportive strategic shareholders people who have day to day trading knowledge of commodity markets and undoubted expertise in the sector.

We are due to publish flow rates as part of calendar quarter end reporting.  At the beginning of December we actually elected to pull flow rates back somewhat (choke the wells) to see if we could determine a steady flowing well head pressure (FWHP).  This pressure level was still falling at a flow rate of 6.3mmscfd but looked to be stabilising around 31 barg at 5.9 mmscfd which is where we were producing at in December absent shutdowns.  The decline in FWHP was not large but it is useful to find the steady well head pressure state and we can revert to the higher flow rates at any time.

Over and above that, half way through the month we were managing a number of scheduled and unscheduled shutdowns arising from maintenance issues with the process plant and its computers.  This was then exacerbated by the weather.  In short although we did not overachieve in December as we did in November but we do expect more normal conditions to resume in January.

We are still very much committed to buybacks and dividends commencing in 2023 notwithstanding this raise, the timing of which was a difficult decision for the Board.  But consider the trade off.

Paying down our debt and meeting our hedge commitments are key obligations and clearly production started a couple of months late.  We had hoped that the costs of rolling the late summer hedges would all seamlessly be met by higher forward prices and this was possible for the bulk of the rolls.  However the lenders and hedge providers took the view that some of the costs of the rolls should be borne by shareholders this year as it is shareholders who get the bulk of the benefit.

There is according to CPR, about 18 bcf or very roughly 180 million therms of P90 reserves here and again 12 bcf or very approximately 120 million therms of C1 resources which we hope to be able to convert to P90 reserves soon.  At a forward price of £1.50 per therm you have a value of around £450 million of topline value on those 300 million therms.  Now some of that (less than 15%) is hedged at 41 pence per therm and some if is  going back to lenders in interest and principal (although the loan is already below £10m) and some has clearly been lost in extra costs – but what are we talking about on this raise: £7 million.  Shareholders get to keep several £100’s of millions.   It is not a daft trade.

It is the Board’s job to make sure that the Company keeps on the right side senior lenders and hedge providers but the reward is that shareholders, for wearing the equity risk, get to keep the equity upside unmolested.

Drilling operations will resume on 5th January.  These will involve from 7 to 10 days horizontal drilling and will be followed by 2-3 days of cleaning, involving dispersing acid throughout the open hole to clean the pores.  Then a completion will be set (a production tubing is lowered into place) over a couple of days and the well will be allowed to flow to a test separator and on to flare.

We will report meaningful flow rates as soon as they are clear to us – possibly within a couple of days.  After the well settles down (we expect initial pressures in excess of 85 barg) it is next connected to the existing plant, regardless of whether or not the 2nd compressor is fully commissioned.  This short tie in connection has been procured and is being installed over the next fortnight.  This allows us to continue stabilising the well head flow rates and also spreads the production draw over three wells thus equalising the higher well head pressure from the new well with the lower pressures from the old wells.

We know that the existing compression equipment can comfortably handle 6.5 mmscfd (very approx 65k therms/day) as we have tested it to that level, so this would be the smallest level of production we would be looking to maintain – and then rising to about double as much when the 2nd compressor is fully commissioned in February.  If we are able to hold that higher plateau (a term meaning the highest level of production possible given all other conditions being equal) for the year we would have at least 40 million therms in 2023, of which under half is hedged at around 40 pence and the rest might achieve an average price of perhaps (to make the math easy) 160 pence – i.e. total revenues of around £40m before operating costs.  This is what we are playing for and must not lose sight of.

We have to think first and foremost about our neighbours.  We currently have 18 bcf (about 180 million therms) of P90 reserves, but there is another 12 bcf of reserves in the southern lobe and to address them means a further side track at some stage and being good neighbours at all times.  Drilling over the Christmas and New Year holidays is never going to win you friends anywhere but is particuarly daft if the consequences are flushing untold millions of shareholder value down the toilet – and that is a given if we treat neighbours and planners without care and attention.

To have progressed the programme safely over the Christmas period would also have meant retaining a spread of contractors, including many highly qualified specialists, on standby in northeast Lincolnshire over the holiday period.  For many such contractors, coming from as far away as Cornwall or Aberdeen, there was no financial inducement which would have changed their mind.

We have also had experience of forcing a programme around the holiday periods at high speed, with an exhausted crew (this time after savage weather) and the result is nearly always that mistakes are made.  We are right to pause and resume, however frustrating for everyone.

We are quite busy right now but will give full update in the NY (before end Q1)

No.  A number of lines pass by us running from the Humber down to the site of the old refinery at Theddlethorpe.  Some are disused, some are used for line packing.  We hope to connect to one of these lines and are preparing a trial connection in the next 3 months.  This would give the Field access to all of the interesting things going on in the Humber region with regard to CCS and H2 initiatives.

This particular CCS line runs on out to sea, we believe, to the old Viking fields for disposal of CO2 there.

Thanks.  We also hope to add a helpful infographic video on progress on the well in the next day or two.

Yes.  We will be engaging in a further CPR in Q1 2023.  This would be to take into account actual flow rates and pressures from the existing wells as well as the third or side track well presently being drilled and additionally the higher prices generally prevailing since October 2021 as well as the ever shifting fiscal landscape.

This would also explore the contingent resources available from the southern lobe.  To the extent that the Company is committed to drilling the southern lobe, with a funded plan and resonable expectation of permitting, a then a great proportion, certainly the majority, of these substantial contingent resources could be raised to the level of reserves.  By way of information this would increase recoverables by a significant factor as present P90 reserves are 18 bcf and C1 resources are 12 bcf.

Due around the middle of this month.  The control panel has already arrived.  It will take about 30 working days to tie in and contractors are standing ready for the arrival.  It should be noted that this will add little in itself to gas sales until the side track well is producing, since the existing wells should not be run too hard.  The presence of the 2nd compressor will allow us fall back should the first compressor require downtime.

At present our focus is on getting this well completed asap.  We are looking at hydrogen storage but in terms of technical study whilst this proposed Hydrogen Week is more about awareness raising.  We would note that Angus developed the first commercial connection to the National Grid which has utilised hydrogen tight pipe, so (subject to commitments) if we can attend and wave the flag we will.

None at all.  If anything can be read into this it is that the reservoir is a tiny bit higher here than elsewhere.  There is regional variation.  There is also some comfort perhaps that we are even further from risk of breaching any water zone below,  but there was little risk of that anyway.

This has always been a moving feast and it will be so even as we are drilling it.  Final open hole size could still be slightly adjusted, as equipment for both is available, but we will settle finally when casing operations are concluded in the next few days.  With a smaller hole size we may drill a little further to increase deliverability and vice versa.

None as of today.

No plans as of yet.  There is oil but we have never evaluated whether it has commercial signficance.

The sidetrack is running a parallel track to Well SF01U which was killed and shut in because of a technical failure in the well bore.  Prior to this event, this was the best producing well at the site and delivered well in excess of 5 mmscfd over a long period.  So we have every expectation that this area of the reservoir will continue to be highly productive.

We would go wherever commerce takes us.

We have never suggested that we have any plans to buy AAOG – nor do we.  As to the Chancellor, we know as much as you.

In common with most operators we don’t disclose the detail of hedging programmes as we believe that a hedge should be looked at strategically – rather than have shareholders trying to calculate day to day returns around a complex series of swaps.  We have have previously announced that we have comfortably met the hedge to date – and would have announced if that had ceased to be the case.  We provide gas quantities quarterly and financial reports semi-annually.  Essentially what you are suggesting puts us closer to quarterly financial reporting, which demands verification for RNS, and is normally a burden for large cap FTSE-100 companies.  Our finance and corporate function is two people.

Mentioned in the CPR is the acquisition of a booster compressor after a year or two.  Essentially the plant needs about 25-30 bar pressure of gas coming in from wells.  The wells, at full pelt, presently deliver much more pressure but that pressure is expected to decline naturally.  Eventually we will require a booster (a much smaller unit than the present compressor) but this depends on pressure decline rates and the success of the side track, which would add new pressure and reduce the draw on the the present two wells.

The facility is 24/7/365

We are discussing this with our Nomad.  It seems that a large number of shareholders are able to pull this information from the NTS website and it may be appropriate that we will change our quarterly reporting policy for the benefit of the less technologically savvy.  Presently we report at calendar quarter ends unless there is a severe disruption which the market should be aware of, other than planned incidental shutdowns.  Those shareholders with access to NTS data can already see that the Company has been completely transparent in its reporting to date.

79,303,236 representing under 3% of the total issued share capital.

It is very likely, but not certain, that we will complete a revised CPR early in Q1 to meet requirements of the loan facility.  This would take into account a much higher forward curve and better production rates than originally anticipated.

We have done a thorough analysis of the storage potential of the field (which is second only to Rough platform) and we have shared the results with official bodies.  Expanding into storage (battery, CH4, CO2, H2, even liquid HC) is a key aim of Angus as we believe that this is an area where we can make a commercially profitable contribution to transition.

Yes.  We are already meeting and exceeding the current hedge profile and already paying down debt.  With the sidetrack and 2nd compressor in place around the year end, the full year to September 2023 should show a company debt free and generating great profits for shareholders.

With the current two well profile, the designers estimated about 50 bbl/day of condy from Saltfleetby.  In practice we cannot advise firm liquid flow rates to the market with confidence as the wells have been shut in for so long, but for the past two weeks flow rates have been much higher.  No reliance should be placed on such a result as liquid flows can be highly anomalous in early days of production after a shut in.  We will give formal advice when we are confident that post-shut in reservoir conditions have normalised.  Following the forthcoming sidetrack the designers originally estimated 100 bbl/day as per our CPR and this is a more reliable figure to use looking ahead to Q1 2023.

Brockham at full capacity should be delivering about 50 barrels a day, although short term personnel issues is restricting that number to about 30.  Our aim is to reperforate the old Kimmeridge well before the end of Q1 2023to address the crest of the Portland structure.  So we would certainly expect more that double the current level of production.  Together a conservative target might be 125-150 bbl/day for the field (Angus share 80%).

There are several remedial works to be undertaken at Lidsey involving a new pump, changing out the production tubing, hot-oiling.  We do have some reasonable expectation that, taken together, these measures will yield a production rate of up to 50 bbl/day at first instance (Angus share 80%) and prior to more capital intensive works such as a side-track.  Again Q1 2023 would be a reasonable estimate for works completion.

So it is conceivable that we could be looking at liquid sales across these assets, excluding Balcombe, of 300 bbl/day by the end of Q1 2023.  We continue to await a response from the Planning Inspector regarding Balcombe.

Noted thank you.

We have never had a philosophical objection to hydraulic fracturing.  We merely noted that our oil fields, being in the densely populated south of England, were not good candidates for fracturing.  The issue turns more on traffic movements associated with multiple “fracs” rather than induced seismicity although greater local objections in densely populated areas can be expected, whatever mitigations are put in place, as the issue has become emotive rather than rational.

The issue with lifting a ban which had cross-party support is that another party will re-impose it two years hence.  It takes two years to get planning permission and other permits and up to five years to get a commercial return.  Who would fund such a venture?  We need – both in our transition projects, or with gas, or legacy oil:  a consistent and cross-party supported energy policy.

The summary outcome of our SIMOPS was that the plant should be tempoarily shut down and all inventory blown down during rig-up time and rig-down time (about 10 hours each) but that otherwise simultaneous operations will not present any additional hazard.  The concern during during rig-up/rig-down is the exceptionallly rare event of rig collapse.  The plant is equipped with extensive remote monitoring, automated alarm and shutdown systems, state of the art fire and gas detection and moreover inventory can be controlled, flared or contained at multiple points and wholly remotely.  So we are content that drilling whilst producing does not represent any hazards which cannot be simply mitigated and we have planned accordingly.

Mercuria had no part in proposing any such appointments and has expressed no interest in having any say and made no objections or otherwise before or after the appointments.

We are awaiting a full report on the Energy Levy from our tax advisors.  Our understanding is that the levy will apply to Angus but that in our first financial year capex incurred since the levy became active is such that little or no tax should be payable.  Thereafter yes, we do intend to bring forward drilling wherever possible as we understand that 91 pence in every pound of E&P is paid for by the state.  Principal targets are the southern lobe of Saltfleetby and at least one other onshore possibility.

Mercuria is a lender into the loan facility and provider of the hedge.  I have yet to have a request, other than information requests typical of any lender, from Mercuria.

Noted.

We consulted major shareholders about the detail and frequency of announcements and they said that they preferred to see less guidance and announcements restricted to achievable or actual results.  Frustrating as the last few weeks were, they are nowadays a function of working in high pressure gas under modern regulations – i.e. a great many professionals, difficult to source/keep over Covid-posponed holidays, whose job is overwhelmingly verification and safety testing.  There was little actual installation work to photograph and share.

The last CPR of 26 October 2021 gave a net cash flow to Angus for its 51% share of £31 million and we have now acquired the other 49% – so obviously there is that uplft.  That CPR was working on a weighted average forward price/therm of about 70p (see page 50) and the average forward curve out to 2025 (whilst exceedingly volatile) is currently around 300p, and has been higher in recent weeks.  Our working assumption is that an average forward price, which is double that used to value the asset in the CPR, is probably conservative.  So yes, without doubt, there has been a very considerable increase in value of the asset, even allowing for the mix of hedged and unhedged production.

Yes.  This is a first of a kind – a combined onshore gas processing and extraction site – in the last 30 or 40 years and comes at a time of national need.  We would certainly like to get our story across and at a national press level.

Hopefully more good PR to follow.

There is a dearth of new assets coming online so we would not be surprised to have further approaches this year.

Loxley looks to be an attractive asset and we will always look at attractive assets at the right price.

One

Only one side track is immediatly planned on well 7 and I refer you to earlier extensive answers already provided on these page – we view Chance of Success as extremely high.

A potential further side track into the southern hemisphere from another well has been carefully considered and planning and permitting work will begin shortly.  The Chance of Success here is definitely good but harder to evaluate at this stage but this further side-track would open up considerable new resources whereas the immediate side-track is merely accelerating production of known resources by re-entering a part of the reservoir which was historially highly productive ( and the old well addressing it was shut-in only due to a technical failure of the well-bore unrelated to the productivity of the reservoir itself).

That is not something we can look at under our current sales agreement.  The support of UK prices from the interconnector is of course good news for shareholders.

There have been specific issues around equipment but essentially the Company underestimated the installation hurdles arising from a sophisticated and all embracing computer control system and the sheer volume of testing, inspection and certification involved in dealing in very high pressure gas in the UK onshore.

There are no easy HSE parallels with offshore platforms in this regard – all of which have particular design and certification issues associated with dealing with confined spaces, yet we have found ourselves keeping pace with regulations which were largely designed for the offshore.

Equally the cost base for onshore high pressure gas is driven by transmission and distribution operators.  Given they can recharge all their capital costs ulimately to the unlucky consumer, over the last two decades both timescales for build and costs have ballooned.

We note that we are the only onshore combined extraction and gas processing facility connected to the transmission system to have been constructed in decades and we had few parallels to follow outside of the refineries themselves.

We did advise in April that we require a “few weeks of steady-state production prior to works” commencing.  This is to allow time to clear the site of post-commissioning personnel and focus the attention of the permanent site team on the drilling operation.  We have not advised the market of a specific revised spud date but will do so at First Gas.

We are definitely more confident about the economics of the field.  The forward curve is now considerably higher than at any time before in the history of prices at the balancing point.  We have also been fortunate in that we have been able to roll a portion of the hedge into future periods that enjoy even higher forward prices – this is not possible to do without incurring large upfront costs when forward prices are lower than front month prices.  Meeting hedge obligations had been a great concern of investors.

Yes.  All done

The hedged volumes were lower in the first quarter but as advised we have a rolled a portion to give us leeway in the even that commissioning is more protracted.  We have been fortunate enough to be able to roll hedged volumes into forward months with much higher prices without incurring upfront cost.  This is not normally possible to do as generally speaking forward months are lower than front end months.  So large is the difference at the present that this has been simple to trade.

The field having been shut in for so long, all the technical experts expect increased deliverability during the first six months of production.  Additionally it was always open to the old Operator to run the wells a bit harder.  Generally there are technical risks to pushing a well too hard, but we think that we could do better than 1.5m therms and, likewise the site equipment has some flex in terms of capacity but it would require some thought and planning.

Yes, although none planned for 2022.  We would like to open up the southern lobe of the field in 2023 where we see low cost side tracks for high potential returns.

We left space for a third compressor in order to handle any potential pressure drop in the two existing wells.  If the sidetrack pressure keeps the average across the three high, then we could use the third compressor to increase flow rates.  All of the units were sized around 10mmscfd (the target production after side-track) but were build with a degree of redundancy and subject to risk assessment we could increase flow beyond that amount.  That assessment will be easier to do once we have steady flow

The war in Ukraine has supercharged the continental European markets but in the UK we pay NBP not TTF.  Our UK market is heavily reliant for marginal supply on LNG cargoes from US and Qatar.  European markets facing supply constraints as a consequence of the Russia-Ukraine tragedy cannot easily switch to LNG because terminal capacity to receive LNG cargoes on the continent is limited.  So the UK is not as affected by the conflict as many others.

The real problem is the global dearth of investment in new supply.  Take it as read that the timelag from identfication to realisation of a decent gas field is a five to ten year affair.  The period of 2015/16 to the end of Covid in 2021 saw the lowest levels of investment in new capacity in 40 years in part because of the commodity price slide in early 2016 and then as a consequence of the impact of climate change activism.

The result is that we are unlikely to see new capacity added in great quantity until 2026 whatever the Russians do.  Unfortunately many of the largest fields were in Russia and smaller operators running smaller fields still struggle to raise funds – particularly for exploration or early stage development.

So Angus does see an ongoing high price for natural gas and, to help in our geothermal ambitions, for electricity production which still relies overwhelmingly on gas fired generation.  This will be good for shareholders.

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.”

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 https://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.

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.

The precise spud date has not been set but is expected to be in the first three weeks of July.

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.

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.

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.

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.

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.

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.

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.

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.

Discussions are continuing.  Given the materiality of the disposal we are advised not to give further detail outside of RNS announcements.

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..

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.

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 “operation” 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.

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.

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.

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.

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.

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.

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.

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.

We advised that these three skids could slip 20-30 days into April and we continue to strongly support that advice.

The economics of the field looking great – principally because the forward curve is so greatly improved.  See

https://www.cmegroup.com/markets/energy/natural-gas/uk-nbp-natural-gas-usd-mmbtu-icis-heren-front-month.html

(to get pence/therm from $/mmbtu divide by 1.35 for the exchange rate and multiply by ten).  Current prices are high at 225p/therm but they are even higher in March 2023!  Even as far out as March 2024 they are 130p/therm or over two and half times the 10 year average of 50 p/therm we made our initial projections on in 2020.

We are not bound to pursue the FSP until we have found a buyer.  We entered into it to see what the market was for Angus and its assets as we review all possibilities for our future direction whether in hydrocarbons and/or alternative energies.

Interest had already been expressed in Saltfleetby over the previous two years.  Continued interest and a formal approach for Angus shares encouraged the Board to open the doors to further buyers so as secure the best price for shareholders and to draw attention to our undervalued shares.  After all we had a market capitalisation of £6 million at one point last year, with an interest in Saltfleetby conservatively valued at £24 million.

Re Environment Agency. We believe that we can expect EA permission for Brockham in the near future.  Saltfleetby we reasonably believe should be available in draft form within a month.  Our Balcombe site is also under review by EA and we hope to obtain that permit in H1.

Re Local Authorities:  we are seeking permission to abandon the Kimmeridge and perforate the Portland at Brockham, but do not require permission to reinject water produced at Brockham.  Our appeal at Balcombe is likely to be heard before the end of Q3.  Our variations of existing planning permissions for Saltfleetby are very minor and are expected to be approved in March.

I don’t believe so.

Definitely.  To have tried to negotiate with purchasers whilst simultaneously dealing with senior debt providers and having the financial stability of the company in any kind of doubt, would have been very counterproductive for shareholders in the short and long term.

The piles are an integral part of the foundations for three pieces of equipment and are part of the existing approvals for the site.  There is no further requirement for approvals for this work.

We will get the best possible deal for shareholders – weighing in both the amount of any consideration and the nature of the consideration (cash or shares) whether for sales at an asset or at a company level.

The Company continues to believe that the CPR (albeit with small adjustments for timing of First Gas) as published is a true and fair view.  We are conscious that the NPV valuations shown are indeed well above our market capitalisation and we regularly point this out to interested parties.

That is certainly something we would consider doing.

We will bear this in mind.  Clearly we are in the happy situation of having many interested parties in this asset and therefore are in a position to seek the best possible bid for shareholders.

We have been notified that the Environment Agency is minded to grant our permit to re-inject water at Brockham but this is subject to a further period of public consultation, so we have not yet advised the market of this development.  Assuming the EA encounters no new information during consultation, the permit is likely to be granted during February 2022 and we would therefore expect to restart production at Brockham immediately thereafter as we have already upgraded the site to meet improvement conditions required of us.    Other permissions, mostly non-contentious or administrative, being available we would hope that Lidsey production would recommence during Q2 2022.

Alignment.  Yes the two are aligned.  The process is iterative as with all of the regulatory and planning bodies.  In this instance further HSE (compliance with PED/PSSR and ATEX/DSEAR) and EA requirements led to modifications in design and layout during the autumn which are now reflected in this application to Lincolnshire County Council for minor variations to our existing consent.

Progress on EA Permit:  We have dealt with a number of Schedule 5 notices requesting further information throughout the summer and early autumn and have, as we understand it, only two matters left to resolve.  One matter concerns establishing agreement on precise methods of noise modelling and associated software and the other the management of a low pressure, low volume incidental off-gas stream.  Both have a variety of highly technical solutions, the choice of which is being discussed with Agency and our various project engineers.  We expect to resolve these matters in early January and do not, at the present moment, see either as a roadblock to First Gas.

We target 200C at c. 5000m.  Super hot rock would be signficantly deeper  in SW England and could yield > 400C.  Some elements of our design incorporate elements common to Super Hot Rock so we follow developments closely, but our focus is on commercial well design – getting cost down away from the government funded figures we have seen to date.   Managing temperatures of 400C plus, whilst offering a much better energy yield, present significant cost increases in well drilling and construction and would not be our on our immediate agenda as we approach potential technical and financial partners.

Yes, the hedge is for a fixed term on a declining balance which roughly aims to decline wiith the scheduled loan repayments.  It would be very likely (asusuming we succeed in obtaining target production from the side track, itself 100% unhedged, and representing windfall gains at present forward gas prices) that the loan would repay earlier, but the hedge would be fixed on that scheduled loan amortisation profile.

However it would be open to the company to break or reset the hedge once the loan was repaid – although this would incur a normal mark to market charge – allowing for more dynamic hedging – i.e. picking particular moments to reset the hedge.  The amount of hedged production after, say, two years would be less than c 25% of total production (including production from the sidetrack).

There are several parts to the civil engineering works programme, including earthmoving, new hardcore in places, piling, concrete pour, bunding for storage tanks and actual structural supports for pipe racks.  The first three have been awarded and much of the work already under way.  The latter three we have quotes on from several suppliers and will award in the early new year.

As regards Saltfleetby and as answered elsewhere, we think we should close out remaining issues in early January and do not see this matter as a roadblock to first gas.

This small rig was brought onto site to ensure that Well SF07 was fit for our particular side-tracking programme.  In particular the well head was nspected, tubing recovered, valves replaced and a cement bond log test was run to esnure that cement was duly in place and our choice of depth for whipstock and sidetracking was appropriate.  This was a successful and cheap operation done with a small rig which greatly derisks time and cost overrun on the main sidetrack operation in Q2 with a much larger rig.  See our Twitter account for pictures.

https://twitter.com/angusenergyplc/

We aim during January to give a further revision to the timetable with days not weeks set for target deliveries for each skid/programme element and follow this with a daily update of snapshots of our 3D visual model of the site showing progress as each element is closed out.

Roadblocks, if any, are likely to involve the supply chain for smaller components, rather than the build of larger vessels or equipment or construction of site infrastructure all of which is progressing satisfactorily.  Electrical, chip, motherboard and plastic components have been singled out as issues of concern by contractors.  The supply chain problems occasioned by Covid have probably grown worse, not better, in the last six months as the remaining pre-Covid inventory has been run down.  New component production has been interrupted, and where newly made, particularly in the Far East, delivery is being delayed by the acute shipping backlog.  In most instances we, our contractors and their subcontractors, aim to work around:  i.e. use air-freght, borrow or rent equipment, risk assess by-passes or reschedule to fit onto skids at site, employ overtime working etc.

However we would say that of all the companies out there looking to do new projects or recommission existing fields, Angus is fortunate in having been able to acquire most inventory off the shelf and delay, if there be any, is likely to be very limited i.e. of the order of a week or two rather than months, but we will update the market as soon as all suppliers have evaluated all options advsed us of final delivery dates.

Healthy debate is genuinely a positive for a company, but there have been a group of concerted individuals, using differing aliases, who have spent three years trashing the company’s previous management, the company and now its new management.

Looking back at their posts: our Saltfleetby Gas Field was first a sham or a fraud “Poundland” asset and not woth anything.  Then it was worth something, obviously, but not much and in any case would never be financed.  Then it was financed, but would never be built.  Then it was revalued at £25m P90 NPV (or expressed as 2P net cash flow to Angus, £55 million) fully financed and being built, but it would never be permitted by EA etc.  It goes on.

We are not a company which seeks to Cancel debate;   all we can do is steadily progress this project, restore to some value the legacy oil fields which were left to present management, and build out other, alternative energy, demonstratively scalable and commercially valuable projects for our shareholders.

As advised in RNS of 30 November, this is likely to be a few weeks after First Gas when the Field has achieved steady flow.

We have answered the civil engineering question elsewhere.  As regards specific equipment, our date of February 2022 for First Gas takes into account delays on the skids as detailed in RNS of 30 November.

Done.  Incidentally the civil engineering works are relatively minor, as the site already benefits from good foundations, hardcore, a geotextile membrane and thorough ground investigations from previous piling operations.  However work could not be commenced until each of the fabricators had finalised dimensions of each skid.  We have ample time to complete these works.

The planning appeal, including a complete Statement of Case, was submitted to the Planning Inspectorate  in September and other relevant parties were notified, but we have not received confirmation that an officer has been appointed to consider the case.  The next step is for West Sussex County Council to submit their response which we can respond to.  We will update the market as soon as there is a reasonable timeline to report on.

We are waiting on input from partners on our interpretation and will update on that and discussions with neighbouring licence holders as soon as it is received.

A.The lenders technical advisers and Angus evaluated the deliverability of the existing two wells as being likely to be greater than 5 mmscfd.  The reasoning was twofold.  In the last years of delivery to the old Conoco refinery, average production was constrained by persistent issues with the main compressor at Theddlethorpe.  Secondly it was the view of technical experts that, following a prolonged shut-in, the two wells should have improved deliverability in the first 18 months or so of operations. This is because prior to shut in there was an area of reduced pressure around the producing wells. Since then the pressure has equilibrated across the field resulting in significantly higher pressure around the producers.  So it is our view that the hedged production should be able to be covered by these two wells in the event of failure of the sidetrack

B.  Finger in the air:  Worst 7mmscfd,  Probable 10mmscfd,  Best 10mmscfd (but extended for a longer period of time) Note, the combined deliverability of the three wells will exceed the production rate during the plateau period which is limited to 10mmscfd by virtue of the process equipment.

C.  We believe that simultaneous operations are feasible on this site but we do need to do much more work on how such operations would be conducted.

With a successful side track we would hope to be debt free and dividend paying during the financial year beginning September 2023.

We have had discussions in outline with one potential set of partners – but we don’t expect to get partners to the table before getting a) seismic re-interpreted and evaluated and b) all planning and permitting consents for a side-track

We have responded to all questions from the Agency.  We are advised of the likelihood of further consultation once a preliminary decision has been arrived at but are still aiming for a final determination in Q4.

Whilst we have had the entire seismic package reprocessed, solely for the purposes of the sidetrack we have focused our re-interpretation on a narrower block.  This is merely to expedite the analysis.  A full field remapping will be done in due course.

As noted in a recent RNS, timing of the sidetrack is dependent on out of country machinery making safe passage into the UK.  We will update as soon as we are made aware of likely timelines.

These will be reviewed by partners in the Field during November and we would hope to release more generally shortly thereafter.

Yes.  We have in mind a further presentation this month on precisely this level of detail with a list of all suppliers and their best estmates of timelines etc.  EA approval is required for commissioning operations, or any operations involving flowing of gas or running of combustion equipment, not construction per se.

Thank you.

Yes, thank you.

Yes.  The hedged amount is fixed so incremental gas is unhedged.

As now already noted, all applicants for permits and permissions in any walk of life give themselves much more time to complete a task than is necessary.  This is because of the length of time and the cost incurred in obtaining the permission in the first place.  They will then advise to market, at commencement of operations, a shorter period and expect to come in on the short end of that.

Reabold for instance advised six to ten weeks for drilling the West Newton WNB1 and completed in 6 weeks before moving onto the sidetrack.  This was drilled to 2250 m.  We are side-tracking from about 1150m to a Measured Depth (including horizontal sections) of about 3000m or 1850 metres of drilling.  Nor are we doing a well test which might extend the programme, because we are moving straight from drilling into production here, so there is no need for a well test.

The hardest rock in Europe gives a rate of penetration of about 3m/hour (see page 6 of https://pangea.stanford.edu/ERE/pdf/IGAstandard/SGW/2017/Baujard.pdf).  That would imply 600 hours here or 25 days/3-4 weeks of continuous drilling.  Even assuming the drilling was no more than half of the time advised, then to drill through this much granite would be only be 7 or 8 weeks.

Granite of course wears drill bits faster and there is much changing of drilling equipment when addressing such hard rock.  We are not drilling through granite in Cornwall or Scotland but through sandstones, clays, coals and limestones in Lincolnshire.  We anticipate 20 odd days of 24/7 drilling – so a rate of penetration of over 12m/hour (verify by page 29 of Halco’s helpful graphs on rates of penetration https://www.halco.uk/wp-content/uploads/2020/06/A-Z-Drilling.pdf).  Of course drilling is not the only workstream here, and even if we were to more than double the time, to suggest five to six weeks of work, we would actually expect the rig to be down inside that envelope.  Things can go wrong and extend the timetable – we have always been frank about that – but this is a reasonable verifiable estimate.

What disturbs me about assertions by this poster (and concert parties) – and they are hardly the first instances of obvious falsheoods deliberately spread –  is that he holds himself out to be a knowledgeable investor and could have fact checked any of this with online sources in a matter of minutes.  Worse still by claiming to have discovered an “internal” company document he implies some great conspiracy by the Company and its Board, rather than sharing his source from the outset and pointing to the very obvious conclusion here:  that people give themselves ample leeway in any official permission!

Please see our latest presentation on this matter.

https://www.angusenergy.co.uk/wp-content/uploads/2021/09/Angus-Transition-Energies-Sept-2021-Final2.pdf

We would be surprised and disappointed if the drilling part of the programme exceeded 28 days and the entire programme involved more than 7-10 days either side.  On behalf of the Board, we have never heard or seen of any internal document which suggested we were planning for a 16 week side-track at Saltfleetby and we would challenge the poster to produce it.  For that matter I haven’t heard of a drilling programme anywhere to these depths which could conceivably take 16 weeks – except perhaps on Mars, which is possibly where your poster hails from.

Supplementally, one poster has pointed out that the Planning Application allowed for 16 weeks time.  This is not some “internal document” which the poster only had access to, but part of an application that is publicly available.  Every company puts in their application for more time than is absolutely necessary in every sphere of life.  This is hardly news.  We reiterate drilling to these depths does not take 16 weeks as every reasoning investor in this industry knows.

The other assertion is equally bizarre and must be challenged.  We have already clearly stated that the hedge was for “approximately 70% of the Company’s  future gas sales …. under a conservative projection” and this was prudently set by the lenders, based, as we understand it, on their own estmates of achievable flow from the existing wells and excluding the contribution from the side track.  Otherwise it would obviously not be a conservative projection.

No it would emphatically not delay First Gas by three months.  In fact there is no reason for it to delay First Gas by any material length of time and it is certainly not in the plan that it does.  We are planning to execute the limited foundation work required beforehand and move heavy equipment in both before and after the drilling programme and will be following this week’s HAZOP with further SIMOP (Simultaneous Operations) planning which will allow for sensibly risked continuous working on the site during the programme.  Again this poster may have misunderstood the nature of the equipment coming onto site, almost all of which is skid-mounted and pre-fabricated for immediate tie-in to the pipework and control lines.  Thus some of the equipment won’t come on until February but none of the units will require on-site fabrication beyond connection work.

We have argued recently for a sum of the parts valuation of nearer 3.5 pence.  That may seem ambitous but at current spot and forward gas prices the cash generating potential of Saltfleetby has been grossly underestimated merely by virtue of the lapse of time snce the last CPR was done on Saltfleetby in early 2020 when the gas price was near an historic low.  We are still confident of restoring value to the oil assets after the drilling results at Lidsey in 2017 and Brockham in 2018/19 and the difficulties with planning permissions at Balcombe.  This process continues unabated, albeit in a slow or sometimes difficult regulatory and planning environment.   Finally we believe that our venture into geothermal will come to form the greater part of the Sum of the Parts of Angus in the future and will meet with a more enthusiastic response from all stakeholders – regulatory, planning, financing and others.

The short answer is the field ,on the original CPR plateau volumes but at the latest forward curve prices, might generate £17 mllion over those four months with the side track and about £8.5m without it.  Angus share is 51%.  Ordinary opex might be about £0.6m excluding debt service.

The forward prices from https://www.cmegroup.com/markets/energy/natural-gas/uk-nbp-natural-gas-usd-mmbtu-icis-heren-front-month.quotes.html are given below in $/MMBTU (approx pence/therm equivalent in brackets).  Prices from ICE for contracts for Q2 in pence/therm in particular seem to be a penny or two better which is probably the £/$ exchange rate (see https://www.theice.com/products/910/UK-Natural-Gas-Futures/data?marketId=5188706)

Heren March $28.583 (213p); April $16.679 (119p); May $14.260 (102p); June $13.774 (98p), given a conservative conversion rate of volume (mmscf) to heat value (therms) – i.e. multiply mmscf by 10500 to get  therms –  the field would generate in total over those four months gross revenues for all partners of £17.1 million at 10mmscf/d (i.e. CPR plateau production with side track) or £8.6 million at 5 mmscf/d (i.e. CPR lower plateau production with no sidetrack).  Operating expenses for full year 2022 according to CPR might be of the order of £2.3m and therefore for this period would be c. £0.6m.

All of this information is already publicly available, and we stress these are presently notional numbers arrived at approxmately and that these prices are not hedged in any way and therefore might not be available come production in March etc.  However whilst the final outcome may vary considerably, we and our partners do anticipate strong demand for gas in the coming years regardless of short term price effects.

The Company has already engaged in a detailed submission and has received back formal questions in the form of Schedule 5 Notices requesting further detailed information.  This is a normal procedure.  We understand that our application and responses to the Sch 5 have been passed to the relevant national teams looking variously at noise, groundwater and air pollution and following that process will be passed to the local officers for final approval.  Grant of permit may be subject certain pre-operational conditions.  We cannot however assume a timeline.  There may be further enquiries but, to date, the application is following a normal course.

Whilst a natural gas processing plant is not uncomplicated, the site has been processing gas in a more modest fashion for 20 years, and we believe that the addtonal quantity of hydrocarbon fluid stored at any one time will not be of an order of magnitude as to require a major overhaul of groundwater protection (the site already has geotextile membrane, ditches and interceptor systems and we are supplementing this with further bunding and handling procedures).  Nor is there any anticipation of flaring or venting of gas other than in commissioning and emergency or maintenance situations.  Even maintenance flaring will be kept to a minmum by controlled shutdown procedures.  Noise pollution, where we are also subject to local minerals planning authority oversight, is also a focus of management and existing sound modelling will be supplemented by continuous improvement as we engage with the practical realities of different operating conditions.

The contract is still in place and the terms are unchanged.

We are lookiing forward to sharing this update during the first half of September and will endeavour to include all of these issues.  Our original presentaiton has grown in depth and detail during the summer and we hope that it will present a reasonable, achievable and financeable project with significant long term value for shareholders.

A. The drilling over the last 20 years at Saltfleetby, once the early exploration was past, was not especially difficult or unsuccessful.  Nor is it true that the reservoir presents greater hazards than any other gas reservoir.  It should be noted that the drilling strategy of the previous operators in the early years was to drill a pilot hole first and then side track horizontally it to increase the chances of hitting a productive layer.  Very often the pilot well itself was deliberately “hockey-sticked” to verify productivity of a previously encountered layer.

SF01, actually originally spudded back in 1986, was a pilot well.  This was sidetracked no less than six times between 1996 and 1998 when the field was poorly understood and just being explored.  The final side track SF01U was actually the most productive well on the field.

Thereafter the record was excellent until previous operators attempted to address the southern lobe of the reservoir.  SF02 did not require a side track at all and was a good producer.  SF03 required one sidetrack and was a good producer.  SF04 likewise a good producer, no side track required.  SF05 again no side track but a less impressive but reasonable producer.

Later drilling on the field, in particular exploratory drilling aimed at the southern satellite structure (via SF06 and SF08) did encounter both less productive zones and these boreholes did require no less than five side tracks betwen them (much as the original SF01 had) and had limited but not negligible success.  However with our side track we are actually addressing the better understood main reservoir again and not that southern lobe;  we are also aiming at an area within the main reservoir which we know with exceedingly high levels of confidence to have been both greatly productive and not exhausted by previous boreholes.

SF07, something of a special case, was originally drilled in 2003 and had four side tracks:  the first two encountered low permeability whilst the latter two, SF07X and SF07W were drilled in 2016 and were beset with operational difficulties which may be the source of the rumour that side-tracking in this field was particularly difficult.

The problems involved loss of part of the downhole assembly due, inter alia, to differential sticking  (note we are taking great care to avoid sticking and are supported by specialist and respected managed pressure drilling consultants as appropriate for a partially depleted reservoir) whilst the other issue involved hole collapse in a coal rich seam (prone to instability) just above the target Westphalian layer:  we are aware of this and we have adjusted the angle of approach accordingly.  It should be noted that the drilling manager at the time proceeded against the explicit advice of the drilling company and indeed the company’s own consultant engineer.

Again we go into this armed with previous operators’ experience and indeed a full audit of our programme by an Aberdeen based but internationally renowned engineering and drilling consultancy as well as the Lender’s own Technical Committee, manned by experts from a variety of backgrounds.  We also have fully reprocessed seismic to guide us past any localised faulting.

Nothing in drilling is without risk – but in terms of basics such as where to drill (finding the most productive layer) & how to drill (and avoid sticking or hole collapse), most seasoned operators would see this as much lower risk, in fact, than would be the case on any relatively newly addressed reservoir.

We cannot presuppose personal decisions by individual directors but we do expect to see further purchases.

The remainder of these questions will be answered by RNS pre-market Monday.

As regards Lidsey, we need to have this seismic reinterpretation complete and agreed with partners.  We should also consider a Competent Person update on the Field and finally complete local authority planning permissions.  Then there is a presentation to our shareholders, potential external investors and fellow industry partners.  Our large Licence holding of 80%, prudently increased in 2019, gives us more than usual flexibility, via farmout, in reducing or possibly eliminating any call on our own equity base for what should be a relatively inexpensive intervention on an existing site, with existing boreholes and supporting infrastructure.

As regards the Geothermal Programme, a great variety of financing structures are being discussed with our funding partners and we have had pleasing expressions of interest from there and beyond – particularly for the development stages of the project.  In the meantime our focus now is on reducing the cost of drilling and mitigating the risks around the drilling and building up in-house expertise and intellectual property as well as acquiring sites and interfacing with stakeholders around those specific sites.

We will be answering this question in a full RNS pre-market Monday.

We will be answering these questions by RNS pre-market on Monday.

Thanks.  Yes, we will be expanding our communications stream with what we hope will be more continuous imagery and detail on the forthcoming programmes at Saltfleetby, Geothermal and Lidsey/Brockham in particular – on both Twitter and, more recently, LinkedIn social media platforms as well as more regular RNS releases.  We do hope that the second half of this year will present a great opportunity for investors to see a company and its contractors in full speed on a variety of highly profitable projects and some of this positivity will drown out the more ridiculous rumour-mongering and disinformation.

This should be answered by RNS on Monday pre market.

We cannot make a determination on when EA approval will be obtained – although clearly the Q2 target has been missed.  The permit application for water injection is subject to public consultation which inevitably slows the process of determination.  Subject to there not being onerous conditions we could resume production/injection of site-produced water very shortly afterward.  We would certainly hope for a determination during Q3 or be able to advise at least on a narrower set of dates during Q3 (of the order of weeks).

As the term P90 suggests, we have a >90% level of confidence that the side track operation will be successful and it will find the payzone.  That high level of confidence exists because the Field is so well mapped by seismic, matched against a cutting record from 8 wells and a multitude of side tracks.  Whilst all drilling operation have operational risks, we see these at worst as giving rise to delay (and so increased cost) in the drilling programme rather than the impairing our ability to extract hydrocarbon at the approximate pressures and quantities which we have communicated to shareholders and are contained within our CPR.

Seismic has been reacquired and new and old lines must be reprocessed together and alongside the new depth conversion work performed last year.  We are hopeful this will be achieved within 6-8 weeks.  We will still need planning permission for a side track although we are confident that this site is a low impact site from a planning perspective and we have had initial discussions with planning officers and advisers.

Estimates of the cost of a side track (perhaps £1.5m depending on the final target destination within the reservoir) would steer us toward consideration of a farmout or some other royalty based financing arrangement, rather than burden the company with equity raising before First Gas.  This is particularly so as it is rare for licensees with an 80% interest effectively to sole risk such a drilling operation.  If we are to seek third party funding, or a farmout, then a Competent Person’s Report would be advisable on an asset of this potentially signficant size.  Before that point, and likely on completion of seismic reinterpretation, there will be a presentation to our shareholders on the financing options for feedback.

Since 2019 the entire executive Board has been replaced, there is a new Director of Operations, a new Asset Manager across the Fields, a new Planning Officer, HSE Advisor, and EA Liaison officer.  The entire technical team, bar one, is new.  Additionally we have moved from the disappointments and exuberances of the Weald oil story into a more diverse transition company focusing on conventional and overlooked oil recoveries from legacy assets, gas supply via National Grid to offtakers such as Shell and geothermal projects in the south-west.   Nonetheless there is a group, clearly acting in concert, who continue to hold the company responsible for null results on drilling operations that either were completed or intiated before 2019, or planning issues, as at Balcombe, which were left in a poor state for the present Board to resolve. The amount of time spent by this group on the share boards, given they freely admit that they are not shareholders, is surprising and we can only presume that they are either professional share board (de)rampers or retirees.  Judge of them as you will, but there is no law against misrepresenting information.  We do monitor the Boards for gross libel otherwise continue to support freedom of expression and hope that these individuals, whether in their twilight years or not, find some more useful and rewarding outlet for their energies elsewhere on the AIM, ideally where they do have a financial interest.

No plans – or we would be constantly updating, but this winter’s pricing is very encouraging.  We aim to produce about 10mmscf/d which is equivalent to approximately 3 million therms a month, so every 1p uplift in NBP is worth about £30k a month gross on the topline (Angus share 51%).

Answered above.

Making adjustment to the CPR figures for different capex was relatively easy as the capex figures involved no further variation or discounting for time.  It would amount to a more substantial reworking of the CPR to estimate the hedged/unhedged production profile at 43p/xp (obviously positive) alongside the royalty payments (obviously negative), which themselves can vary in the event that production/unhedged pricing is at the top end and the loan repays earlier than term.

We could provide a rule of thumb, or different scenarios, but this would have no validity in the eyes of our Nomad or the AIM authorities.  If the Board believed that there would likely be a significant net diminution in the present value which might be arrived at by an updated CPR, the Board would have felt compelled to consider a further CPR.

We would only remind everyone of how greatly improved the overall pricing environment is for gas since this time last year and we are fortunate in not having needed to put in place the hedge last year.

Answer clarified following further quesitons received.

Two reasons:  1) the speed with which we can accumulate the necessary capital.  2) it is rare in the oil exploration world for a operator to go fully risked for 80% of the cash call associated with a drilling operation.  No operation is without risk and the better practice is to spread that risk across multiple parties.  The key point to get to  is to have all planning and regulatory consents in place, which as we have learned by experience, is half the value added in any licence.

Most of these questions have been superseded by our recent announcements:  in particular the hedge of c. 70% of target production is in place at 43p/therm, OGA approvals have been obtained.  We have already resumed procurement with further significant stage payments made on the day of drawdown.  The side-track of SF7 is targeted for autumn but, in any event prior, to resuming production.  We still aim to acheive commissioning and first gas within calendar 2021 but would prefer to release an RNS updating the full market on a more detailed timetable on both matters durng July.  By that time tendering on the side-track should be complete and supplier updates for process equipment will give us narrower delivery dates.

We have no firm timeline on this matter but have until Q4 on a statutory basis formally to lodge an appeal.  We have had discussions with planning experts on this and with our partners.

Following further comment and to clarify;  the next steps are to determine the points that the Planning Authority and Angus are in agreement with and those where they are not. Following initial consultation with WSCC the sole substantive disagreement seems to concern the definition of public interest. Now it is necessary to evaluate the avenues of appeal including making written representation on this point to the Planning Inspector.

The Facility make provision for changes in the ownership of working interest by Saltfleetby Energy Limited with transfers being made subject to similar terms as apply to Saltfleetby Energy Limited.

Saltfleetby Energy Limited guarantees the facility with its working interest and commits its share of field cashflows to service the facility/royalties but there is no further commitment from them.  So they are not a credit counterparty in the traditional sense and, if replaced in part or whole with another person under the same obligations, Angus is indifferent.

As a consequence the usual rules apply – i.e. we do not make comment on the commercial decisions undertaken by fellow AIM listed companies in which we have no shareholding.

We have made three hires since this loan facility was announced at the end of Q3.  One Health and Safety Lead, one Site Supervisor and most recently, a Lead Operator in late March.  We won’t take on further hires until commissioning.  These are essential staff who need to be thoroughly grounded in the specifications of all of the equipment which we are procuring, the site, existing wells and the plans for new site controls and safeguards.  They will be a key part of our HAZID and HAZOP meetings over the coming weeks and months.  They must also trained up (or at least ready to train future operators up) to full HSE competency in order work safely in a high pressure gas process installation.  This core group obviously cannot be brought in one month prior to commissioning.

Angus welcomes any industry body, particularly with supportive links with academia, which will draw attention to the benefits of geothermal energy – most particularly the baseload advantages of geothermal over wind and solar.    As we noted in a recent conference call, the price we, as UK citizens, are paying for our electricity has risen considerably over the last 15 years to accomodate the cost of idling gas fired power stations, manned 24/7 and on standby to make up the load when solar and wind power periodically fail.  We strongly believe that baseload or continuous generation, which does not require several pence/kwhr of that standby support, should be rewarded with improved long-term tariff rates to encourage us and other operators to invest further in this industry.

Angus sees a very profitable future for shareholders in geothermal with wide public support.  Our recently announced target of 50 MW capacity within 7 years may soon be updated and we have made real progress on reducing the risks and costs associated with the subsurface and drilling work, as well as site identification and acquisition and innovation in the application of traditional surface equipment for harnessing the heat energy.  We speak to many of our peers in the industry, all of whom recognise the considerable skills and century long experience which hydrocarbon drillers have to bring to this sector.

Our, and our peer group’s, well resourced effort to make Transition work has to be communicated better to the public at large and we welcome these associations.  Equally the fact that Transition is not an overnight shift needs to be better understood by local planning authorities as they mull our legacy hydrocarbon assets as it is these which will provide some of the cashflow needed to speed that Transition along by funding these long-lasting projects.

A number of reasons.  There isn’t anything particularly “usual” about senior secured lending in the UK’s onshore oil industry.  The bulk of operators and licensees fund out of equity.  We have a multitude of counterparties here: three borrowers inside the Angus group, a limited recourse guarantor in the shape of our Licence partner, a security agent, and a collection of private lenders, large and small as announced.  Certain parties have very unique documentation needs or wants and a single draft can take some time to circulate arond the various parties’ counsel.

Then, as a secured loan into a heavily regulated industry, there are a large number of reports to be collated, assets to be identified for charging, specialist bank accounts to set up, technical support, regulatory enquiries.  The trust deeds for the Licence alone stretch to well over 100 pages.  We have been frugal on our own legal costs, and restrained on the use of counsel, and we are not paying for any other party’s costs (excepting limited reports on property title) other than the commitment announced in November to Aleph as arranger.  Nonetheless the delay has been very frustrating for us and all our shareholders but we hope that we have made good use of the time we have without the full funding in hand.

As answered to another query this month:  We have been frugal on our own legal costs, and restrained on the use of counsel, and we are not paying for any other party’s costs (excepting limited reports on property title) other than the commitment announced in November to Aleph as arranger.

Progress has been steady but frustratingly slow.  Further detail would demand an RNS but we do hope that the next RNS will be the happy announcement we have all been waiting for.

Any material change to the RNS’d financing terms would have to be communicated by RNS promptly.  The existence of this vehicle for many weeks has been public knowledge.  There having been no such RNS advising of changes in terms, it is safe to say that this vehicle does not do anything more than act as a support for the overall financing.

We do filter or combine questions that turn on the same point.  We do correct mistakes in grammar and remove abusive commentary or foul language.  We do avoid “loaded” questions – designed merely to provoke a negative atmosphere with no real intent to be informed.  Equally we avoid planting positively “loaded” questions.  We do, but have not in this case, truncate questions when they evolve into statements or opinions.  We have to follow MAR and AIM rules on disclosure so material questions on potential raises or disposals obviously can’t be answered in this forum without a simultaneous release before market opens on the next market day.  In short, we do aim to be reasonable in our moderation of this forum.

We have had about a dozen questions this April and have answered six from this particular questioner!

The costs were identified in our RNS of 23 September and, at several millions of pounds, these were obviously beyond our capacity to raise equity on the AIM.  Moreover the decision to fund the side track costs and set aside a large sum for abandonment pushed the figure up to £12m.

As to your second question, we have endeavoured to ensure, with relatively modest deposits and sums set toward detailed design work, that our main procurement goals are kept at least ready to launch with some of the smaller items acquired outright.  Most large capital goods suppliers quite quickly want 30% instalments and this is not feasible without the debt financing.

Finally there have not yet been any mjaor roadblocks, but a few potholes as might be expected in a secured facility with many interlocking agreements:  the process of senior secured lending has actually grown more complicated over the last two decades just as has property and insolvency law whilst regulation generally has ballooned in every facet of modern life.  We detail this further in another investor question this month.

We do not believe so.  Instead we expect that the revised seismic will confirm the high water cut and low oil flow rates were both the result of the drilled section addressing the flank of the reservoir.  We expect much better rates and lower water cut in the main structure.

That said the facility of being able to re-inject water is useful for both the injection site (for pressure support and improved recoveries) and the source site (if it produces water) and was used at Brockham for many years and is currently used in many other sites across the UK.  The alternative of trucking and burning the produced fluid is environmentally sub-optimal and we look forward to being permitted to resume this more friendly alternative by our regulators.

To clarify – this is not new but was part of the placing announced in February.  At the time there was insufficient headroom to the allot the shares hence this followed after the AGM.  The amount is relatively modest – proceeds of £150k or less than c. 1.75% shares.

The operatives are at present, and are expected to be, drawn from the local area – in particular former operatives at Saltfleetby itself and the former Theddlethorpe Refinery.  Additionally most of the equipment providers have training built into the tender document.  Some specialist kit, entirely engineered for the site will require us to develop in house training modules.

This wasn’t HSBC – but, as announced in the TR-1, a nominee company (possibly representing a group of investors in the last placing) and is wholly unrelated to the debt finance, to the best of our knowledge.

No.  We are set up as an Operator/Licencee at present.  UJO is not an Operator.

We believe the market would like to see the financing completed before weighing in.  As regards Balcombe, we have already approached West Sussex County Council Planning team to discuss the decision and will update the market following those discussions.  We do believe that the prospects for the Company as regards Lidsey, Geothermal, the Brockham Portland and Saltfleetby are inifinitely better than they were  back in 2019 following the Brockham Kimmeridge result and that a steady stream of good news induring 2021 will prove this.

No.

We believe that this question was superseded by our recent RNS.  We believe that we are in the final furlong.

Yes and we have on contract on our team since February an experienced commissioning specialist who has commissioned over a dozen such fields the world over.

We agree and are not minded to walk away and nor are our partners Cuadrilla.  The Planning Committee’s decision rested on a view of public interest which we believe to be narrow and misguided.  We are a company that is clearly urgently engaged in Transition but we have legacy oil assets which shareholders have spent many millions of pounds on.  We are not asking for a new site at Balcombe but to recover what we have invested.  If every oil company engaged in Transition, from BP down, had all permits withdrawn for legacy oil business, there would be no Transition as everyone would be bust.  Oil companies need to fund generally more expensive Transition projects and this cannot be done if all legacy assets have to be tossed in the bin immediately and the Energy White Paper is clear about the intention of government to help us, and not hinder us, in Transition.

For year 2022 the CPR estimated 28k barrels which is about 550 barrels a week or two to three tanker loads depending on tanker size.  We have a better oil price, and condensate sits at a discount, so about £20k a week which is good but well less than 1/10th of projected gas sales on a like basis using the same report with updated prices.

As per RNS releases Saltfleetby Energy is contributing its security in the Field and allowing its share of revenues in the Field to be applied to service the debt.  Angus is however the primary Obligor and is leading the way on documentation although we and our partners are separately represented and endeavour to respond to the Lender’s counsel with a single voice.

We have given explicit updates via RNS.  We cannot update further on this platform without further RNS.  We can say that given the sensitivity of the matter, if there were any significant road block then we would be under an obigation to inform the market immediately.

We cannot think of a reason why our share should be unavailable for positions as against our similar sized peers in the industry.  We are in the process of making enquiries.

We would add to the list of headwinds we have faced in procurement, the extremely small number of functioning onshore gas fields in the UK.  Offshore compression is almost all turbine driven, but mid-sized fields like ours are barely extant onshore will typically use reciprocating compression.  Meanwhile the focus of OEMs in Europe is for either biomethane or LNG, with much less attention for the mid market segment.

Our procurement process, since we are not looking at a single turnkey provider, is ongoing and open-ended.  In order to attract debt capital, we needed to procure and be able to present definitive options back in the autumn.  That has not stopped us from looking to refine and improve individual tenders and for some second hand equipment, availability is a matter of patience and good fortune.   To date prices and terms have moved in our favour and we have also improved our understanding of the costs of recertification.

We started looking for debt finance or leasing solutions in March 2020 – not the most auspicious time – and whilst equity markets picked up in the summer, debt folk tend to be much more circumspect.  We don’t like to count chickens before they have hatched but we would say that the environment for debt finance of development opportunities is vastly better now than it was even in September 2020.  Funds and individuals can sit on their hands for so long before they start losing feeling in them.   What we can say is that, of the great number of counterparties we spoke to, two potential industry partners, and four experienced debt investors have crawled over the field (and Angus) and none have had any problem with the technical or financial proposition other than the relatively small size of the deal and their readiness to do anything last year.

The placing involved a warrant structure – priced at 1.2p, 1.35p and 1.5p and designed to reward placees but only when all shareholders had enjoyed benefit – which would have been administratively impossible to manage in an open offer environment involving thousands of shareholders.

We have planned in the weeks ahead a full presentation of Angus’ strategy going forward as a Transition Energy company and this will involve new projects.  However we don’t right now see these projects as involving signficant (>£0.5m) spend, and so large placings, before First Gas.  As to monthly income projections, we are not allowed to announce these outside of RNS and the number of variables across three oil fields and one gas field is in any case considerable.  The result would be very good indeed.

Near contracts for gas at National Balancing point have indeed spiked in recent weeks to close to 80 p/therm (according to my Bloomberg) and the day ahead contract is currently around 55 p/therm – although bear in mind that this is peak season and in summer months the price is likely to be significantly lower.  The present price also reflects the impact of a very cold northern hemisphere winter as well as structural demand/supply issues driven by rising demand for global LNG from the Far East.  About 20% of UK supply is now LNG.

The valuation of the field is highly sensitive to headline gas prices.  In our Reserves Report the exchange’s forward curve prices were used resulting in an average gross price of 38 pence per therm. At target peak production rate of 10 million standard cubic feet a day an extra 1 pence/therm is equal to about £350,000 per annum of additional revenue from the gas field, of which 51% goes to Angus.  Given Angus’ tax shield there is very little incremental cost associated with this improved revenue – essentially frictional supply discount, shipping and grid entry charges etc.

The potential debt participants in the facility  have indicated a strong preference for a buyng a “floor” (a seasonally adjusted option over a minimum price) at or around 30 p/therm over at least a majority of the production albeit on a declining balance related to expected outstandings on the loans.  The final hedging won’t be put in place until we are closer to precise supply dates, given it will be much easier (and cheaper from a credit perspective) to hedge against known production.

Outside of that likely requirement, generally speaking, companies who have tried to speculate outside of hedging defined production have tended to go spectacularly wrong more often than right in much the same way that in gambling, on average, the punter loses and the House wins.  Nonetheless our advisers at Aleph are exploring dynamic hedging strategies which would also allow some opportunistic fixing of future prices during the sorts of tight price environments which we have recently witnessd.

Our milestones for H1 2021 are as below.  In all of these goals we are dependent on third parties – regulatory agencies, suppliers and debt financiers and, even in this environment, we regard these goals as realistic.

1.To close Saltfleetby loan documentation before the end of January and begin drawdown very shortly thereafter.

2. To follow with the second stages of procurement for all of the kit during February with a view to having installation during Q2.

3. To begin commissioning Satlfleetby and work toward first gas around the end of Q2

4. To present to shareholders a commercially viable ESG project during Q1.

5. To obtain planning permission from West Sussex County Council, albeit with conditions, in the month of February to proceed with the welltest at Balcombe in H1.

6. To obtain Environment Agency approval for water injection at Brockham during Q2.

We have kept up with detailed design with the process facility designers, Optimus Aberdeen, and set up a good interface between them and major suppliers.  On most of the kit there is a lot of field specific re-engineering to be sorted out, so this interface is crucial.

We have also laid down deposits for some of the key equipment to encourage suppliers to be ready to produce to order as and when further payments can be made and to keep aside some calendar time for actual assembly. As said in previous communications, we have selected the so-called longest lead items for particular advance support.

However when considering the largest pieces of equipment costing in excess of £1m, suppliers will only commit to so much advance work before requiring further milestone payments, so there is obviously a time dependent relationship with the debt finance.

No recommendation received to date and nor will we bind ourselves to any course of action ahead of carefully reading and considering the final recommendation.  The Company remains in close communication with the Planning Department and is assisting them in answering their queries.  In view of the current Covid environment, we have not sought to press upon the 14 week statutory timeframe, and are more concerned to satisfy the Officers that our application does merit a favourable recommendation under both national and local policy frameworks and rules, as we believe it does.

A good question.  The economics of geothermal vary considerably depending on heat flow and proximity to urban centres or sizeable national or local grid connections.   Like hydrocarbon exploration, the initial phase is relatively high risk but, getting past that phase, anything which is lacking in immediacy of high return is made up for by the longevity of geothermal generating assets and the ease with which such long-term assets can attract sensible finance in the development stages.

We will be sharing details with shareholders of at least one of two geothermal projects in Q1 2021.  One project relates to an existing site, the other to a third party brownfield site.  Storage projects require largely depleted reservoirs and reman a potentially lucrative revenue stream in the more distant future.

On average we are finding lead times to be around 14 weeks for more substantial items.  There are however specialist, more highly engineered items or just simply components of packages which can take up to 24 weeks.  The exercise we have been engaged in for the last month involves identifying these longest lead items and either replacing them with more easily sourced alternatives or separating them out from the remainder of the package and using the immediate financial resources  we have to hand to ensure suppliers focus their efforts on manufacturing or re-engineering those parts alone.  Incidentally this swapping in and out of parts is more difficult to do with a standard lease or hire purchase package than the more flexible equpment finance facility which we are proposing.  All of this is done with a view to holding to the discipline of the overall timetable.

£12 m is the headline number for this facility.  Of that £3.9m (£2.4m of sidetrack for 2021 and £1.5m of Abandonment Resere) is unrelated to restarting production but is raised to give debt investors the comfort and assurance they require such that all needs of the Field Development Plan are covered at the outset.  Similarly the equity placement is there to a great degree as a cushion ordinarily expected by senior secured lenders over and above any contingency or planning and working capital allowance in the debt facility of £1.6 m

This leaves £5.7m for the process kit as against an approximate total of £2.7 m (the mix of lease and capex in the CPR).  This is clearly a significant overspend and we have made it clear that the overwhelming cause is EU regulation and the high additional cost burden it imposes on users of non-EU kit (the rules function basically as a 100%+ customs tariff).

High pressure gas facilities tend to be neatly tailored to the reservoir (its flow rate and pressure) and so with a “stick build” approach employing both used and new kit there is also a little luck, as well as skill, involved in obtaining the right equipment i.e. this may will depend on OEM lead times, factory utilisation or the random availability of other CE certified kit suitable for our field.

We have been asked (both by investors and industry suppliers) whether Brexit will alleviate things.  The problem is that as regards the very methods of safety testing, accreditation and verification, we are hopelessly reliant on EU law and it will take years to allow a return to British Standards or some broader acceptance of international standards (API and EU) – and right now any unilateral legislative move by the UK would complicate negotiations on exit.

The good news, as we make clear in our recent announcement, is that just as the debt investors insist that the facility covers all immediate needs, so shareholders are equally free of the burden of funding reserving or sidetracking next year.

We began approaching lenders during lockdown shortly after the publication of our CPR as we regarded this asset as eminently well suited to debt finance, in particular so-called Reserves Based Lending.  This is a specialist form of credit advanced by a now small number of international institutions.  Indeed none of the lenders we spoke to had issues with quality of the asset as security or the ability of the cashflows to amply service this level of debt.

Our principal problem was size – generally speaking the larger lenders have high fixed costs associated with evaluating, structuring and approving a loan and reserves based lending is complex and requires a significant time allocation.  The larger lenders tend to have a minimum “ticket size” of $20 m and above and ESG has become an issue for some as well.   We nonetheless spent the summer doing technical and financial due diligence with one well known institution and were only pushed back due to this size issue at the last minute.

Where we have had more palpable interest is amongst the smaller specialist lenders, funds and offices and Gneiss have a reputation for knowledge of this market segment and skills in arranging financing at the best possible pricing for all parties.  We have already had a number of instiutions express keen interest, had face to face meetings and a thorough examination of our data room;  so, at this stage, we remain confident of a successful conclusion.

Yes there are alternatives to this route – amongst them a varying mix of vendor finance and third party hire purchase or leasing.  We believe that this alternative in particular will be more time consuming and complicated to execute and possibly result in greater delays and a higher effective cost of funds.  Hence we are pursuing the present route.

At Brockham as announced we have submitted our EA application, after making use of that Agency’s Enhanced Pre-Application Advice service and we are confident that they will approve water injection which will enhance reservoir recoveries.  However timing of approvals is unknown.

As mentioned on the recent investor conference call, resumption of production at Lidsey has encountered downhole mechanical problems associated, inter alia, with the pump.  This has no great impact on shareholders given the immediate oil price but is nonetheless frustrating.  Prospective seismic work in anticipation of a side-track is on hold whilst we focus all of our human resources on Saltfleetby.

At Balcombe, our planning application was made in August is likely to be dealt with in December.  This is not exploration but a low cost well-test on a reservoir which has already “shown” oil.

Not quite.  The proposal is that Saltfleetby Energy Limited will contribute equally to and benefit equally from the facility, but that the limitation of their liability will be their interest in the cash flows of the Field and their working interest in the asset itself.  Hence they are not looked at by lenders as a credit beyond their interest in the Field.  Angus, and its financial strength, is more important to debt investors – less as an alternative source of repayment since the Field handsomely covers the debt burden – and more in its role as Operator to ensure the continued flow of gas revenues to service the facility i.e. the debt providers will need to know that they have a well-resourced Operator.

As mentioned earlier, we have heard pricing from other mainstream lenders to be of the order of 9% all-in for senior secured on comparable risk.  We would estimate the pricing to be higher  on this facility, as smaller debt counterparties generally expect higher returns.  That said the amortisation schedule under consideration is significantly tighter, so the cash costs might not be very different as we repay this loan faster.  Whilst final maturity is likely to be of the order of 4 years, loan duration (a measure of how quickly the investors recover their money through coupons and repayments) will be nearer 3 years.

We would hope to have soft commitments or so-called strong indications for the larger part of the facility during October, however we can’t guarantee third party timetables.  We would expect that the documentation should be significantly simpler and quicker to execute than a traditional Reserves Based Loan which tends to carry a lot of highly technical language suited to funding exploration opportunities, whiereas this is a single asset with a well understood existing production history and carries negligible exploration risk.

Yes.  This can be confirmed and even no informal correspondence.

As announced on 27th, our revised submission to the Environment Agency for water injection at Brockham has been lodged with the Agency.  This follows extensive pre-application work including enhanced pre-application advice on our application.  Whilst we are confident in the arguments which we have presented as regards the inherent safety and reasonableness of this activity, the timeline for approval is not one within our control.

As regards Lidsey, this was shut in for maintenance earlier this year and kept shut in during Covid-19 lockdown and the low oil price environment.  We expect to update the market formally in the forthcoming two weeks.

The Saltfleetby 7 sidetrack was drilled from the B site towards the West, as can be seen in Figure 5 in the CPR (Structural Map of the Top of Westphalian Reservoir (Unit 2b)). The well was first perforated in the Brinsley Abdy formation, but failed to flow oil. Thereafter there was significant differential sticking in the Westphalian unit and the well was sidetracked to penetrate the Namurian C which was thinner than prognosed due to faulting, and so another sidetrack (SF07Y) was drilled into a thicker Namurian C sand. After completion and perforation in 2003 the well flowed 2.4 mmscf/d of gas on test. However, once the well was linked up to production equipment it became clear the reservoir had suffered some form of permeability impairment  and the well gas rate was restricted.

With respect to the upcoming SF05 sidetrack, this is to be addressed from the B site in completely the opposite direction towards the East, tapping a prolific part of the reservoir. The well is to be drilled using techniques that will negate the impact of any differential sticking, and also in to an area where there is good well control (SF3z and SF5). Therefore we have good reason to be confident that we can avoid any of the issues seen in SF07.

Our new sidetrack is intended to accelerate reserve recoveries from this better understood and obviously prolific part of the reservoir rather than to address potential new resources in the Field.  We would also aim to reinterpret the seismic data over the line of the well to ensure we do not hit any unexpected faults.  We aim to begin this modest sidetrack operation in Q2/Q3 next year once the field has resumed production from the two existing producer wells, and all regulatory applications will be submitted in due course to try and achieve this target.

We believe that the chances of success are high to very high, although no drilling is without some risk.  We would prefer to give a fuller presentation to investors nearer the new year on the structure of the reservoir and how each section and each well was addressed historically, for which there is a considerable body of good data, as against what we are proposing here.  As regards local authority planning, the sidetrack operation will fall under existing permissions but we still need to seek the approval of HSE under BSOR for which there is a notice period of 28 days.  The sidetrack is already included in our Field Development Plan with the OGA.  Environment Agency, with whom we are already in discussions regarding the site, may also be involved in the final sign off.

We haven’t looked at this but will do.  The obvious issue with old oil wells is that they do not generally have the infrastructure to process natural gas let alone hydrogen.  That said there are a number of interesting smaller scale devices being developed around hydrogen so we are always on the look out for new ideas.

No.  Angus Energy North America Limited was a joint venture incorporated to explore opportunities in North America.  Jonathan Hill has had no active engagement in the Angus Group for some years and the vehicle presently has no activities.

Our apologies and that of our counterparty.  The document has been stuck with Covid-19 constrained legal teams but, as far as we are aware, all commercial issues were settled weeks ago and we look forward to clarifying the arrangement for shareholders during August.

The company records debtors on the balance sheet under FRS 102 (UK GAAP).  Debtors principally consist of partners in fields or off-takers of supplied hydrocarbons.  Terms of trade vary for off-takers but not normally by more than 14 days.  As regards partner payments under JOAs these do vary more and the mechanics of cost recoveries or profit sharing under JOAs can be complicated and subject to disagreement or even audit which can be time consuming.

UK accounting principles require the directors to make a reasonable provision in the profit and loss account for bad or doubtful debts particularly in circumstances when such amounts have been outstanding for a long period of time and so their chance of recovery is not beyond doubt.  These sums do not necessarily represent cash lost or foregone or debts forgiven.  Like any other company we do not generally discuss the detail of our debtors especially if some part of the sum is subject to ongoing commercial discussions.

We are hopeful of a positive planning decision for our pipeline extension on the following grounds:

1.  The area is not within an AONB and the pipeline is below ground for most of its route.
2. Much of the route will actually be horizontally drilled below ground.
3. There are no permanent surface structures on greenfield sites.
4. There are minimal number of nearby residences and none very proximate to the line extension.
5. The line is 100 metres, in parts, from Theddlethorpe Gas Terminal where the entire refinery is being demolished and
6. Our proposed works are relatively short in duration – not more than 3 weeks of heavy works and ideally less

These posters are ill-informed or deliberately misleading other investors.  We will clarify our view immediately:

Almost no significant independent gas producer will make cash profit from pure gas fields at 15 pence per therm.  Nor are the independent Major producers immune to prolonged price downturns:  each of them have net debt  levels (debt after deducting cash resources) of between $35 and $100 billion dollars and average abandonment liabilities of between $15 – $30 billion.  No-one is worried because these prices are unsustainably low and none of these companies or their auditors, would use these low prices for forecasting or asset valuation.  See notes to their accounts.

In June, Fitch ratings, an independent agency tasked with giving a credit rating to the Majors’ traded bonds, estimated a gas price of $3.75/kcf for 2021 (1 kcf = c. 1 MMBTU =  10.15 therms) rising to $5 for 2022 and $5.5 thereafter – that is roughly 30p, 39p and 43p respectively.  Our original presentation in summer 2019 did use the 10 year average of 50 pence but the more complete and independent Competent Persons Report in March of this year used forward curves from the Intercontinental Exchange (ICE) of 35p, 39p, and 41p respectively.

The prices are all for UK/Dutch sales (so called NBP or TTF) and please note carefully that US prices (so called Henry Hub) tend to be lower as they are more exposed to short-term gluts of locally produced cheap gas.  Please note also that ICE futures for summer months are traditionally very depressed – at least one misleading post deliberately quoted prices for only the summer/early autumn months.  For more balanced, educated and independent views we would steer genuine investors away from these posters to see for instance:

https://www.fitchratings.com/research/corporate-finance/fitch-ratings-cuts-european-gas-price-assumptions-raises-us-henry-hub-09-06-2020

Yes.  The principal constraints on pipeline internal diameter are the maximum designed operating pressure (which in this case is over twice the maximum anticipated delivery pressure of between 45 and 70 bar) and the velocity of flow of this volume of gas. Very high velocities result in higher temperatures and erosional issues and are generally avoided for that reason.   The resulting velocity increase at the narrower internal diameter of 4 inch vs 10 inch is still comfortably within normal ranges for the transmission of grid specification gas in the UK.

We believe it appropriate, given the sensitivities, to have full and careful consultation with the planning authorities and other statutory consultees before resubmitting.  This process is all but complete and we remain hopeful of resubmission in the near future and at any rate during August.

We intend to give up the lease on our London office (8 desks + meeting room) during autumn and select a cheaper option of 4 desks plus shared meeting room in a location yet to be determined.  We will be hot desking those 4 desks and expect to obtain considerable savings.  The bulk of our real estate expenses are related to the leases over operational sites and a small Louth office/warehouse on an industrial estate.

In answer to your specific question, as previously announced, we have had and continue to have no formal communication on this supposed action group which was talked about in the middle of last year.  So long has been the period of silence that we are sceptical of ever receiving any funded challenge.   We do respect the anger of some shareholders following the Brockham result.  Brockham was for us, and many other experts, a reasonable read through from the geology of Horse Hill and all of us at Angus were bitterly disappointed by the results of the drill last year.  Angus was then almost a pure exploration company.  It isn’t today.

As to the expertise of these very regular posters, we don’t know who they are and so whether they have any genuine professional qualifications either in finance or hydrocarbons.  Our technical team, which includes Operations, Business Development and Technical Directors, who between them have well over 80 years experience in oil and gas, would say that such posters show some real knowledge interspersed with some equally very real gaps in their technical understanding.

If the individuals on whom you comment were truly experts in their chosen fields then they would not hide their identities behind pseudonyms on message boards and would be happy to share their real-life bona fides with those that they seek to influence through the safe mechanisms of forums like linked-in. This is what all of the employees of Angus do.  This may open anyone up to abuse as has been received by many of the staff members, but it does ensure that other investors can estimate the value of their input more reasonably.

As MD, my own background in finance involved much larger hydrocarbon companies than Angus but my experience over the last few years tells me that smaller capitalisation stocks, particularly pure exploration stocks, tend to attract their fair share of manipulators and rampers.  We do monitor, as we are under some duty to all of our shareholders and the the AIM authorities, the more blatant inacccuracies and we look for the obvious signs of professional manipulators – i.e. presence on the site or forum more or less continuously through the working week, plausible and detailed but ultimately dishonest narratives, the use of techniques such as sock-puppets (alter personae that appear naive and bewildered but ask questions which are immediately answered by the manipulator), trading spikes before or during the development of long threads of narrative etc etc.  much of which regrettably has been in evidence in recent months.

In summary, whilst we support the rights of all our investors to freely express their opinions, we also encourage them to be very suspicious of those who claim to be acting in their interests while revealing nothing about themselves.  In the meantime we will continue to alert both the site administrators and, where appropriate, market authorities of any malfeasance or defamatory statements.

Our timetable was for connection in August and we still aim, subject to planning permissions, to initiate pipeline connection works in that month and complete in September as advised in our RNS of 1 May.    Our overriding aim is to have completed such trenching and drilling as is required before we are into the rainy season in this low-lying area of Lincolnshire.  Suffice it to say procurement of the relevant pipe, valves, vents and associated equipment together with contractor selection is well underway and we are now into finalising detailed design and conducting the important HSE mandated hazard identification steps for eventual approval from that regulator.

Whilst we do have planning approval for the processing plant at the Satlfleetby B site, there are many more moving parts to the project and some suppliers have been under pressure to respond in time in this Covid environment.  We anticipate initiating some works in the early autumn and complete the bulk in the latter half of Q4 – again as advised on 1 May.  First gas would follow after a typical commissioning period for a field of this size.

We would like to present to shareholders a more complete GANTT chart of both projects toward the end of July/early August.

Yes.  On 6 May 2020 and this was acknowledged by HSE on 13 May 2020.  It should be noted that this is the first of a multi-layered approval process the next steps of which involve conducting a HAZID & HAZOP and the development of a Safety Case for the pipeline and a Major Accident Prevention Document.  These latter two documents will require approval by the HSE before the pipeline can be operated and the HAZID is key to their development.  We begin the HAZID this week.

As regards other approvals, we still await Lincolnshire County Council planning approval  prior to initiating construction but understand, as regards OFGEM Licencing, that s.3 of The Gas Act 1986 (Exemption) (Onshore Gas) Order 2013 exempts the provider from the general prohibition on unlicensed conveyance in s.5.1.(a) of The Gas Act 1986 when the conveyance is “from an onshore gas processing facility to a pipeline system operated by a gas transporter” to the extent that the conveyance is not to any premises and also that the length of pipeline is under 16.043 km (i.e. c. 10 miles).  All these conditions are met.

No.  The Company has not been informed by the Operator of any immediate spending plans of note and there a consequently nothing beyond minimal expenditures in our budget and forecasts for this prospect.

We still expect to finalise this shortly and such delay as there has been is not due to any material problem but merely slow process during these peculiar times.

We will resume extraction from the Portland but only with the assistance of water injection which is subject to Environment Agency approvals.  It is difficult to determine how the reservoir will perform with water injection but the mere ability to re-inject produced water will substantially improve the economics of the field and reduce the environmental impact of trucking the produced water miles for disposal which, given its salinity, involves burning it!  As to timing, we have spent some time bringing the older wells and the site into good order during this lull, and we expect to resume production as soon as EA permit conditions allow but at any rate this year.

We have had a number of questions relating to events dating back before the present MD was appointed at the end of January 2019, including numerous technical queries about operations from two years ago and rumours about legal action groups, dating back a year now, which have never materialised.

Angus in 2018 was a very different company, with one executive Board Member and considerable disagreement between him and major shareholders – a wholly unsatisfactory situation that needed to be resolved swiftly and culminated in a resignation with an agreed termination package.  That outcome can hardly be described as unprecedented.

Angus today in 2020 is a very different company.  The entire Board, bar one, is new as is half of the technical team and the operations team is greater in size and considerably more experienced.  Operational and planning procedures are new.  Regulatory and compliance systems are being put in place or refreshed.  New assets, potentially vastly more profitable than those of old, are being brought into production and further acquisitions are being considered in a systematic and disciplined manner.

We do want this Q&A site to be a forward looking forum which informs investors well about the real prospects of the company, the day to day technical challenges, and the huge opportunities that lie ahead in a rapidly changing and unpredictable world.

As stated elsewhere in this month’s questions, we do believe that the fundamental objection by the Officer concerns an interpretation of national policy which we should be able to overcome.  On the whole we have had a good relationship with the Planning Department and previous applications, going to the actual Committee, have been successful.  On the traditional metrics of visual amenity, noise, highway management, risks to air, soil and water, our Application seems to have satisfied the Officers.  However there is always room to improve a Planning Application and in this re-submission nothing is off limits including duration of the test, further improvements to technical aspects, charitable donations and enumeration of other local socio-economic benefit, even restoration options.  We are have strong hopes that the new Application will be acceptable.

First of we have been successful in previous Applications to West Sussex County Council and found them to be a level-headed  Council supported by a professional team of Planning Officers.  In this case the Planning Officer recommended against on an interpretation of national policy on hydrocarbons versus the important status of an AONB.  Nonetheless in the course strengthening our arguments on this point, we have also looked harder at local benefit over and above paying rates and boosting local employment and suppliers.  So yes, good point and we will be considering charitable donations to good local causes.

George Lucan (MD Angus) was appointed to the Board of Challenger Acquisition Limited during the first half of 2019.  Challenger is a Guernsey based shell company, listed on the LSE, formerly engaged in the development of urban entertainment projects, similar to the London Eye, in major international cities.  Challenger is presently looking for so called Reverse Take Over candidates to bring in new lines of business.   All potential conflicts were disclosed to both Boards and Angus’ Nomad at appointment.  The position is non-executive involving occasional reviews of potential candidates and is not presently considered to detract from his duties at Angus to which he is, and expects to continue to be, fully committed.

We aim, as stated, to resubit our planning application to West Sussex County Council as soon as possible.  If the application is resubmitted during June and approved within the statutory 13 week period, the we should be on site in Q4.

Saltfleetby has two planning applications – one for the site, already submitted, and one for the pipeline extension which we advised would be submitted before the end of May.  Although we have not met this precise date, our expectation is that the deviation will not be significant – i.e. of the the order of days not weeks.

Again, the subsequent calendar remains in line with previous guidance although we continue to encounter some of the expected side-effects of the lockdown.  Our aim is to provide a much more detailed step by stem timetable before the end of summer.

As stated in earlier Q&A, given our capital situation we have gone for transactions where the prospect is low risk (i.e. in or near production) and we can add expertise and low cost execution rather than risk shareholder capital in further exploration.  We bid on Saltfleetby as is known, but also on one other UK onshore gas operation and further gas prospects in Oman and Ukraine – none of these required significant capital.  We explored in depth just under 10 transactions in Poland, the Baltic states, Romania and Tunisia and we have looked more cursorily at over 30 others.  Some of these transactions involve very sizeable contingent resources – many multiples larger than anything we encounter onshore in the UK – but where such resources are stranded and don’t qualify for treatment as reserves or the attention of the majors.  We have to weigh the high regulatory and planning costs and protracted timetables in the UK with the problems inherent at working overseas in unfamiliar systems.  We think that in the current oil price environment there are one or two game-changers and company-makers out there likely to be shed by larger players as being inappropriate to their cost base.  If we see one, we are ready to bid, but our main focus, as repeatedly said, is still delivery, delivery, delivery at Saltfleetby and Balcombe.

The Balcombe planning officer’s recommendation was a surprise given the permissions already received.  Balcombe is, however, in an Area of Outstanding Natural Beauty and has, along with other Weald projects, attracted considerable attention from protesters and locals alike.  We truly believe that our footprint is small here, barely visible from any public vantage point and we have been exceptionally careful as to noise, air and water pollution.  Nonetheless we have not made our arguments strongly enough and will need to continue discussions with the Council.

Saltfleetby is in a rural area with low population density.  All wells are drilled and the extraction of hydrocarbon is overwhelmingly by buried pipeline.  The pipeline extension works are less than 300 hundred metres from the demolition work on Theddlethorpe refinery and, to any reasonable person, the brief former works could not be considered to be adding much to the temporary inconvenience expected around the latter more extended process.  The works at site of adding compression and dehydration equipment are a one-off event, again with little or no long-term visual impact or noise, water and air pollution risks and with flaring only in emergencies.  There is at least as good if not better local socio-economic impact from our proposed works.  Generally speaking gas producing fields attract less hardcore environmental protest because gas for domestic boilers and regional power generation is rightly perceived as the cleanest of hydrocarbon burning solutions and very difficult to replace in the near term.  On balance, in any reasonable world, the application should be a considerably easier one to obtain permission for than Balcombe.

As noted in an earlier question our application has been delayed by a supporting report from a third party contractor due to a bereavement.  Nonetheless we note that, to our knowledge, there are no further field reports which would require breaking lockdown which would be needed before submission.  We also note that most regulators remain very responsive in this lockdown and have embraced remote working and decision making.

ANSWER:  We have 3 executive board directors, a 3 man technical team and a 4 man operations team and two office support.  All happily remain healthy as do our key contractors.  We set up virtual private networks a month ago and sent staff home a over a fortnight ago.  Contingencies were put in place for regular monitoring and skeleton security staffing.  Oil & Gas workers are key workers which allows for some latitude in essential maintenance if need arises.

We have two daily videoconferences for all staff and a further operations, wells and site teleconference at the beginning of the day.  Our experience of remote working has been positive with an equal if not higher level of productivity at least in these first ten business days of lock-down.  The work in Saltfleetby planning has moved swiftly and we do expect planning applications to be submitted shortly – these have been very slightly delayed by beneficial developments which have opened up unforeseen opportunities.  Tendering for equipment, construction and commissioning is also expected to take place in the month of April although we are unlikely to be in significant cash spend until after council planning in late July.

As to delays: Saltfleetby works were not slated to begin until late summer and tendering at this stage would amount to identifying equipment and further planning on implementation.  If we submit planning application for Saltfleetby within a fortnight, there is a statutory 13 week period before a Planning Committee meeting is convened.  We are informed that these meetings cannot, by law, happen remotely, so if the lockdown is still in place at the end of July, we will have an issue.

The delay to West Sussex County Council Planning Committee meeting, on similar grounds, may provide a welcome opportunity for further engagement with Council members and officers albeit remotely.

Our submission to Environment Agency regarding water injection at Brockham has been delayed by a bereavement in the family of a key contractor engaged in preparing essential supporting documentation but we hope to submit this during April.

Generally speaking our experience with Oil & Gas Authority, Environment Agency and Health & Safety Executive is that these regulators continue to function admirably during these times and given that the caseload we put to them does not necessitate site visits at present, considerable work can be completed remotely.  We have been awarded a permission during this period of lock-down.

In answer to the second question:  Could we furlough (put onto half or no wages) staff during this period?  Possibly one or two but the impact would not be meaningful.  As stated the bulk of cash is held for capex and pipeline construction and 90% of this capex will not be expended until after Planning Approval in Sussex or Lincolnshire – or well after lockdown.  In fact, even without the Covid-19 lockdown the bulk of the expenditure would be due in Q3-Q4.  We are in many ways fortunate to have already allocated this time to engage in detailed planning at Saltfleetby and not be producing oil at rock-bottom prices, but instead tendering for equipment in a buyer’s market.

a) Planning in Lincolnshire – 13 weeks from submission in April.  Planning is critical and we will get some response from some regulators during the statutory consultations.  Allowing for a successful decision, OGA, EA and HSE follow and discussions with each have begun on different areas.  Ultimately HSE will not sign off until shortly before commissioning and will be integral even to the planning of that step.  Given we are not drilling for oil but processing and piping high pressure gas – satisfying HSE (and nationalgrid) during construction and commssioning will be key;

b) as regards kit, we believe that we are in a buyer’s market and delay will only increase that advantage;  nonetheless Covid-19 makes it diffuclt for us to do in situ inspections in far away places and doubtless transportation to site will be a chaotic affair come the removal of lockdown restrictions.  If we conclude the tendering process during early May, we should have good time to plan transport.

c).  As stated HSE (and nationalgrid) are key to commissioning although there is much collation of accreditations, certifications standards and verifications which can be done in advance;

d) nationalgrid are well within our broad timetable at present.

Other than Council at the start and HSE at the finish, most delays can be considered to be concurrent rather than consecutive – i.e. one month delay by one regulator + one month delay by a kit provider still equals one month delay and not two.  A costly delay is most likely from last minute failure in an accredation or in on-site performance of some tiny specialist widget, costing less than 10 quid, but which cannot easily be sourced elsewhere or otherwise worked around.

Delay is simply monthly cash burn unless you count the opportunity cost of not selling the gas.  Overspend potential is in three areas at present – tendering, contracting for pipeline construction, nationalgrid connection.  We have a good feel for the range on each but nothing firm.

We are presently pre-production at Balcombe and Saltfleetby and producing modest volumes at Lidsey, accordingly there is little immediate impact.  We do anticipate a major impact on US shale production of both gas and oil from these prices.  US shale producers were already facing a crisis of low return on new capital employed which will be seriously exacerbated by this price drop and will ultimately resolve itself in lower production and higher prices after a few months.  Accordingly the Board views this as favourable in the longer term.

In the more immediate term, whilst we procure long-lead items for both Saltfleetby and plan for a production spread at Balcombe, we are likely to be in a very favourable “buyers market” for significant equipment and processing facilities with hydrocarbon prices at these levels.

No mystery or conflict.  Paul Forrest who runs Forum Energy Services Limited is well known to Angus and, having bid successfully for the Saltfleetby Asset, brought Angus into the transaction on terms already disclosed. The joint Directorship has been disclosed to the Board of Angus and these arrangements do not present any conflicts or confidentiality concerns as the Orwell Group Limited is not involved in the hydrocarbon industry. As such there is no need to disclose any further information.

The Environment Agency had already laid an objection and WSCC was awaiting further communication from that Agency.  The objection has now been lifted and therefore our application should be considered at the March planning meeting.

Thank you JA51.  The RNS of 19th June is in fact quite clear.  Angus is liable for 100% of abandonment “excluding subsurface pipework” until first gas.  After first gas, the free carry for Saltfleetby Energy drops away and the provisions of the JOA apply such that Angus shares abandonment costs 51%/49% with Saltfleetby Energy but once again subsurface pipework abandonment is specifically excluded as the RNS makes clear:  “Saltfleeby Energy has agreed to retain the liability for all abandonment costs surrounding the subsurface pipelines from the two sites to the Theddlethorpe Gas Facility together with certain redundancy costs which would otherwise fall to be treated as expenses under the JOA.”

I sympathise.  We received yet another question from this overwhelmingly negative poster last month.  They are normally framed in the inflammatory language of an investigative journalist i.e. “Can you confirm or deny such and such” with dark hints of wrongdoings here, there and everywhere.  Much of the information presented on the Boards by him is either plain wrong or simply wrongly interpreted.  We attempt to answer all his assertions here, if only to rectify the misinformation and to show that we are genuine in our attempts to communicate openly with investors.  Success at Balcombe and Saltfleetby is the only thing which will silence such detractors.

The production target of 18 BCF over the field life is from the two existing wells that we will bring back in to production. This figure is being refined in the upcoming CPR, as well as the potential upside from further drills and production optimisation. We are very confident that we can extract significant upside from the field and are very much looking forward to sharing the CPR results with investors in due course. It would be premature to anticipate the results of the CPR but we hope to be able to show an increase in expected reserves.

Again, this will become clear in the upcoming CPR but the company hopes to achieve significant upside in future years. However, it is worth noting that even at the lower end of the production targets the asset is still highly lucrative for the company. We see significant upside may be possible from a new sidetrack as this would not so much add reserves but accelerate production of those reserves.

No.  The new facility should be understood to have replaced the old facility which is no longer available for drawdown, otherwise we would obviously have drawn down on it rather than arrange a new facility.  To be clear, as of 27th February the Company has drawn down £1m of the £1.5 million October 2019 facility, of which £100,000 has been converted and £900,000 remains outstanding.  At the same date cash at bank and in hand on 27th February 2020 was £3.5 m of which £650,000 is segregated reserving for eventual abandonment at Brockham and Lidsey.  Most of the balance of £2.85 million free cash is being held to meet significant capital expenditure commitments at Saltfleetby and, to a lesser extent, at Balcombe.

Yes

They didn’t.  The abandonment notice was issued to Saltfleetby Energy Limited and not to Angus and it was issued prior to Angus being approved as Operator.  It is not unprecedented, in cases where prior approval of change of ownership has not been sought, for an Abandonment Notice to be issued which gives the OGA time to assess the impact of the change in ownership. To the extent that Angus’ Field Development Plan for Saltfleetby is approved, the Abandonment Notice would need to be rescinded anyway.

A new Field Development Plan for the Portland Reservoir has been submitted to the OGA. Last year a presentation was made to the EA regarding the restarting of water injection. The EA require a revised hydrogeological risk assessment (HRA) to approve the restarting of injection. This document is being prepared and only when submitted can EA and OGA approval be granted. The HRA will take a further few weeks for preparation, submission and approval though we cannot speak for the EA approval timings.

The sites are already linked by a short pipeline which is suitable for continued use.  Gas produced from the A site will be transported to the B site via the existing line, and processed with the ‘B site gas’ before being exported to the National Grid. All the new facilities will be located on the “B” site where all the support facilities are already located and where the export pipeline leaves.  This greatly simplifies planning, permitting and construction, avoids duplication of equipment and reduces costs.  We hesitate to give final estimates of the cost of processing equipment as tenders have yet to be bid upon but as yet indications of cost haven’t thrown our budget.

The extended well testing approval with the OGA is still under discussion but a rate of 300 BOPD has been discussed as has the need for a long flow period to evaluate the reservoir properly.  However this does not limit our ability to flow the well at higher rates but rather offers an indicative flow rate to the OGA.

At present Horse Hill is not using gas for power generation and has been producing for a considerable time with flaring of gas. We cannot commit to gas utilisation in power generation at this time as we do not know the gas quantities to be produced and the gas quality. Both of these affect the design of a generator. The difference at Brockham was that the site is a production licence, and the Field Development Plan for the Kimmeridge Clay expressly identified a ‘gas to wire’ set up for the BRX4Z well, although even there it allowed for a short delay to determine gas quality and quantity. At Balcombe, the operation is purely a well test in the early stage of the field life and therefore the best available technique, as at Horse Hill, is to flare gas until such time as the site is deemed commercial and more permanent gas handling facilities can be installed.  It should be understood that our preference is not to flare but to use the gas, as it is valuable to us, but only when testing confirms the viability of the reservoir.  We do not rule out implementing gas to wire earlier should planners and regulators approve it and all technical and commercial parameters are met.

The discussions with the OGA are on the basis of gas flaring using an approved flare as currently in use at Horse Hill. Yes it would take some time to get the necessary approvals for gas to wire but we believe this should wait until we have sufficient data to get the design right. At Brockham we were required to use all gas during the operation and not flare anything, but this requirement created a problem because of the need to have a gas sample before ordering a gas to wire generator, and so the authorities allowed for a short delay before implementation whilst we determined the gas to oil ratio.  Given we had already negotiated access with the local power network, which was indeed time consuming, and had planned the connection and dug the trench, there would have been little time needed to complete connection.  In summary, Brockham involved going straight into production (which was packaged with non-instantaneous gas handling requirements) whereas Balcombe is a more traditional well test.

We do not know if Balcombe will produce formation water until the test is underway, we are however not expecting any. At Horse Hill we understand formation water has not been produced. Yes Lidsey produces water and we hope to use this to inject for pressure support at Brockham once that is approved.  Costs of disposal do vary from area to area depending on availability of disposal facilities.

You ask two questions 1) why the loan was taken and 2) the timing of the loan.  The loan was taken because the Board wanted to see the company being properly and intelligently provisioned against its abandonment liabilities.  Our stakeholders, landlords, neighbours, planners and no doubt regulators wanted to see that too. Our business requires us to engage with these groups almost constantly and we want to be able to do this from a position of strength rather than making excuses and avoiding the question.   However, in answer to your specific point, the OGA did not demand any such cash reserving.

The timing of the convertible loan was set in the light of the high level of confidence which we have in obtaining near term cash flow from at least two of our assets – Saltfleetby and  Balcombe.  BRX4-Z was a pure untested exploration well in an unconventional reservoir which is still poorly understood.  At the time at which the January 2018 convertible loan note was taken out this was the single asset on which the Company relied to supply cash flow within a one year horizon.  Saltfleetby is a known quantity and Balcombe is, in our view, by mere virtue of the short well test already performed, a much better understood and less risky endeavour than Brockham BRX4-Z.  In short you enter into a convertible only if you are confident of future prospects.

We have been looking at prospectivity within and outside the current licence area and we are indeed relying in part on new interpretation of much older seismic data, although discussions of “discovery” are meaningless in this context. Should part of the prospect extend out of the licence we would approach the adjoining licence holder for a commercial arrangement.  Note in this regard that nowadays, and particularly in the South-East, securing an acceptable site with appropriate planning permissions, rather than simply the Licence, is 9/10th of the battle to secure the oil or gas. However, due to the level of work on Saltfleetby, Balcombe and Brockham evaluation of Lidsey future prospectivity is proceeding slowly and our attention is rightly focused on bringing cashflow to shareholders.

Both figures are entirely to be believed.  Production at Saltfleetby shut down in December 2017 some several months before Theddlethorpe terminal formally shut down.  However through most of 2017 the main compressor at Theddlethorpe, which was newly installed, suffered teething problems which eventually resulted in it being taken off line in August.  When it was restarted in November, production was self-limited whilst the machinery was undergoing testing.  The problems with the compressor were well known to the many staff and contractors who worked there or supplied gas there.   Saltfleetby well deliverability, or the measured combined capacity of the two producing wells to flow, exceeded 5 mmscf/d throughout 2017.  That’s to say the wells produced 5 mmscf/d on the days they could actually be operated and the compressor was functional.  Since the Field was shut-in at the end of 2017, the reservoir pressure has equalised by a significant amount and locally increased, so the actual deliverability now will exceed 5 mmscf/d.  The condensate production forecast is based on the average condensate gas ratio for the year preceding the shut down.  We will have our own compressor on-site at Saltfleetby going forward!

Again both figures are correct – you have picked one month’s price but in our presentation we made clear that we were taking a 10 year average price and marked this line clearly on the OFGEM graph.  Gas prices are subject to cyclical, seasonal and finally local meteorological fluctuations, such as the recent relatively warm, wet winter.  Had you asked the same question in Feb 2013 you would have been quoting an OFGEM price of 85 pence/ therm but we wouldn’t based our presentation or our budget on it, any more than we would have taken the $26 barrel oil price in January 2016 and based a 10 year projection on that.  We took a ten year average price because the field possibly has about ten years to run.  Yes the project is viable and indeed highly lucrative even at prices well below the ten year average.

We have not had any formal correspondence.

In common with any other public company, we don’t disclose correspondence with our market and financial regulators, and note only that, when they deem it appropriate, they themselves will publish findings according to their own procedures.

Under the present Joint Operating Agreement, it is not the Operator’s duty to determine what provisioning arrangements co-venturers have in place let alone disclose those arrangements.

Much of this amount was intended for and has indeed been applied to advancing the A24 Prospect but this amount was never ring-fenced from other working capital and clearly, since 6 February 2017 when this transaction was announced in RNS, there have been a variety of more important changes to the capital structure of the company. As to how the OGA look at notional allocations from three years ago, we cannot comment.

The structure of the Balcombe operation is as follows. Stage 1 (removal of drilling fluids) will take place with a temporary bund installed around the equipment. Assuming this stage is successful a complete impermeable liner will be constructed under the site so as to offer suitable containment for a long term well test. The design of this liner is as per the Zetland document, with the civil and structural details already being worked out so that installation time should not be considerable..  Stage 2, being the extended well test ,will then commence.   Costs for Stage 1 are relatively moderate and are borne by Angus.  Most of the costs of Stage 2 will be almost immediately recoverable from oil sales and should represent a manageable timing issue.

No, as above and as publicly announced when we farmed into the field, Angus bears all costs until the well is proved capable of producing oil commercially – i.e. this should be close to the end of Stage 1 or the beginning of Stage 2.  However once we are into Stage 2 we can recover costs normally from oil revenues.

No. Balcombe is a bare site with only the wellhead and therefore requires bunding equipment. Both Saltfleetby sites are established sites with all the necessary liners, bunding and Environmental Permits in place, including local containment around pressure vessels.

We haven’t seen any mentions of Angus in non-trade magazines in the last six months.

Assuming planning permission is granted there will, as always, be various planning conditions attached and other regulatory permissions. We have as a company aimed to provide the council with updated versions of many of the documents required to satisfy previous planning conditions and hope that any new conditions are easily resolvable. We aim to do all in our power to begin operations as soon as is practicable. We are not currently aware of any wildlife protection issues which restrict seasonal operations. This was only an issue in preparing the various ancillary reports to the planning application which had to be undertaken during specific parts of the year to assess wildlife impact.

Angus still targets production in the summer of this year, and we have made substantial progress on the various permits and permissions required, as well as with processing facility and pipeline design/procurement.  Delay could involve regulators and planning as ever.  Also, as always with modification of existing facilities there are complexities in buying equipment compatible with the old plant and the new specifications for the additional process facilities. In short some very specialised components are required and if not “off the shelf” can have very long lead times. Sometimes this is not apparent until detailed design is completed and procurement gets fully underway, which it almost is. The company has obtained quotations on business interruption insurance to cover any significant loss of earnings should certain aspects suffer delays going forward but this is still being negotiated.

This is now done.  We expect to complete a Competent Persons Report during January 2020 on this Field which as previously announced is likely to show at least as good as, if not a considerably improved, commercial outlook for recoverabes from the Field.

In advance of completing a CPR on the Field we have estimated the maximum recoverable methane gas to be 180 million therms.  We have hopes, as announced, that it may be greater.  The ten year average price for a therm of gas  is approximately 50 pence which yields £90 million of gross value in the Field excluding a further £7 million of condensate – or £97 million in total of which Angus share is 51%.  This was from our presentation in December 2019.

Even allowing for a lower average price of 40 pence per therm gives £72 million gas recoverable or £79 million with condensate, and deducting £2.5m of reconnection costs and a further £2.5 million of abandonment costs at the end of life, and finally increasing previously announced running costs from £1.0 million to, say, £1.25 million per annum over 12 years shows a net value before tax of £59 million of which Angus net share is just under £30 milllion.

This figure of £30 million should be set against a market capitalisation of Angus and all of its other assets of just under £5 million at the end of 2019.

The company has immediately begun to address the important issues raised by the Environment Agency and has commissioned two experienced contractors to update the HRA and produce the accompanying documentation. We are looking to submit this as soon as is feasibly possible. However, we will not rush to submit half finished or sub-standard documents that will not satisfy the EA and will ensure that each and every one of the points raised is addressed correctly. It is perfectly normal for regulators and other consultees to request further information during the course of an application, and is particularly common for oil & gas submissions. Once the EA problems have been addressed and their objection lifted, we look forward to receiving a decision from WSCC and subsequently the planning committee before operations can commence.

Speaking on behalf of the Board we have not even discussed the matter.  Our 100% focus is on making the business work rather than in depriving shareholders of value by acquiring the Company on the cheap as would be possible given the present share price.

In the much longer term, as our assets move into production phase and we have distributable reserves the Board would not rule out share buy back programmes if we continue to be persistently undervalued as at present.   It should be stressed that this is not likely to be an option during the time period mentioned and is a procedure circumscribed by extensive law and regulation.

Good question.  We do indeed believe that the Kimmeridge at Balcombe is in the sweet spot of the basin, and we are confident that the well will flow oil given that we have already seen this during the previous test. Rates in the Autumn 2018 test were, however, short lived as the dense drilling fluid in the well made sustained oil flow impossible. As a result we cannot accurately predict flow rates based on the limited information we have, and we are left to use geological information and analogous rates from offset wells. Horse Hill, which has a vertical well, has been flowing oil from the Kimmeridge at rates of 200 – 300 BOPD and being very conservative we would expect to match this. Given, as you correctly note, this well is a long lateral, one might expect rates to be 2 – 3 times higher than that of a vertical well and so we would certainly want to exceed the 300 BOPD rate, however, until we test the well we simply do not know for certain how the reservoir will perform.  We want shareholders to have understanding of our reasonable expectations but would also, as a company, prefer to surprise on the upside rather than overpromise and underdeliver.

1. What would be the minimum bod required to deem Balcombe commercially viable?

There is no set minimum flow rate. The commerciality of the well will depend not only on the flow rate, but also on the potential decline of any rates as this will control the future cash flows from the well. Once the rate and decline can be modelled sufficiently accurately, and compared against the cost of installing permanent production facilities, then a declaration of commerciality can be made. It is worth noting here that in general in the South of England many fields operate at relatively low flow rates due to the low lifting costs of onshore UK production.

2. If oil were to free flow after stage 1, would any type of flow measurement be made and compared with this minimum bod, in order to decide whether to proceed with stage 2 or not?

The purpose of stage 1 is purely to remove the spent drilling fluids, not to measure flow rates of the well, that is for stage 2 and the EWT.

3. If stage 2 verified that this minimum bod could be persistently exceeded, would an application be made to WSCC for a production licence?

Following the completion of a successful stage 2/EWT, and assuming that the well flow rates and decline rates indicate a commercial discovery then Angus would proceed to apply for full long term production. This involves a new planning application to WSCC, as well as a full Field Development Plan to the OGA with details of facilities and the drilling of any further wells.

4. Assuming a successful stage 2, would Angus consider increasing their stake in Balcombe?

Yes.  Again, assuming a declaration of commerciality can be made and that the site is developed, Angus would always look to increase its stake in cash positive projects, finance permitting.

Yes.  Our advantages are that we are a low cost Operator, nimble and flexible, capable of scaling up relatively quickly and cheaply to meet the challenge.  There are assets which are being shed by larger players with structurally higher cost profiles but which offer good profit to operators such as ourselves.  We review, on average, 5 or 6 such possibilities each month and about 1 or 2 tend to be real contenders and yes we have put in non-binding bids on more than one this year.  We aren’t eager to be diluting shareholders at this share price and would rather score some material successes at Saltfleetby and Balcombe before engaging in further acquisitions.  If however the right asset at the right price comes along ….

There is no legal requirement to set aside funds for abandonment but the issue of underfunded abandonment liabilities is coming to the fore across the onshore industry.  We wanted to satisfy many of our stakeholders – local councils, regulators, concerned neighbours to our sites, landlords – that we were serious about our responsibilities and adequately funded to meet them.  We face the task of obtaining planning consents and regulatory permissions on a weekly basis, but several particularly important ones concerning Balcombe and Satfleetby are immediately pending.  We are trying these days to stay ahead of the regulatory curve, rather than constantly catching up and, although we still haven’t got it right, we are engaging in more dialogue with stakeholders and earlier in any given process.  We still think that this was the right call.

We have commissioned a third party reserves report, or ‘CPR’, that will be completed in early Q1 2020, that will outline the existing reserves in the field from production of the two previous producing wells.

Investors are less familiar with gas pricing over oil pricing.  In gas we tend to speak of daily production in million standard cubic feet (mmscf) rather than barrels per day and we use billion cubic feet (bcf) for reserves.   1 billion cubic foot or bcf = 10.15 million therms and 1 mmscf = 10.15 thousand therms and each therm, taking the ten year average, trades at about 50 pence, although in the last five years, 40 pence might be a more conservative assumption.

So if, as per the last officially reported production figures, gross daily production is expected to be 5 mmscf, then that is worth between £20k and £25k/day  which is financially equivalent today to approximately 500 barrels of oil daily, and of which Angus is due 51%.  Equally if reserves were 10 bcf this would have a rough value of £40-50m, and 20 bcf would be worth about £80-100m and so on.   In that same RNS we gave a conservative estimate of 10 bcf gross recoverable (5bcf net to Angus or £20-25m) and an upside of 18 bcf (9 bcf net to Angus or £36-46m).  All of this ignores condensate, as estimated in that RNS, which may be worth between £1.8m and £3.4m to Angus shareholders.  All of this is also before ordinary field costs.

From more detailed modelling done since June we have not found any reason to be reducing either estimate but note that, in advance of the CPR, estimates is all that these figures are.  There are however a number of locations within the field and in the structural mapping that require further investigation as to possible upside … but let’s wait for the professionals.

Jonathan Tidswell has committed to repaying this loan before the calendar year end of 2019.

The permission to produce from the Portland Sandstone ended when we tested the Kimmeridge. To allow us to go back to the Portland Sandstone the OGA require us to submit a complete new development plan. Also a few months ago the Environment Agency changed their rules and banned water injection except after consideration on a case by case basis. We are waiting for the OGA to approve our new development plan for the Portland Sandstone reservoir and we are “in the queue” with the Environment Agency to consider our application for water injection for pressure support. When we get these approvals, we can start producing again.

Furthermore, the Portland Sandstone has been produced at Brockham for around 30 years. When the 1987 discovery well was drilled by BP the field flowed several hundred barrels a day, similar to the Portland at Horse Hill currently. However, over the 30 odd years of production the reservoir has become depleted and the pressure has dropped as occurs with all reservoirs over time. As such, production now is relatively low and it likely uneconomic to drill a new well into the Portland. However, it is still economic to produce the remaining reserves from the Portland once all regulatory permissions have been received.

Operating in the onshore UK we are working in perhaps the most highly regulated and controlled environment anywhere in the world. The four main agencies involved Planning, Oil and Gas Authority, Environment Agency and the HSE are there for all our protection and we must work within the rules and regulations they set out. This can frequently involve large amounts of work and many months of scrutiny, but this regulation is there for good reasons and we work hard to complete all the requirements in the minimum time.

At present we are planning for an extended well test of the sort currently being carried out at Horse Hill. This will result in the flaring of some gas, as at Horse Hill. This is however unavoidable as the use of gas for power generation requires the precise properties, volumes and composition of the gas to be known which we cannot measure until some production has occurred and we are assured of a constant reliable generator fuel gas supply of known heating value and properties.

The eventual development for long term production is highly likely to involve the use of a generator to make use of the associated gas but we cannot order that generator or the powerline connection till we know how big it needs to be.

We already know that the Balcombe area was mature enough to produce oil as it has already been produced. The number 1 well was tested in the late 1980s and produced dry oil and the Balcombe 2Z horizontal also produced oil during our test last year. Balcombe is near to the centre of the Weald basin and is therefore in its most mature part.

As noted in answers to other questions gas cannot be used for power generation during testing because the amount, quality, composition and heating value are not known until it can be sampled under stable flowing conditions.

We were planning a gas to power system for Brockham and had carried out preliminary design and were ordering some equipment and organising trenching for the line. When we realised that it would not be needed only limited work had been carried out and thankfully little money spent. So, yes it was started, no it was not completed and the reason is that it could not be completed until we had data from the initial well test.

To be clear, it had been agreed with the OGA that initial testing of the BRX4Z well at Brockham would occur without the generator, in order for a sample of produced gas to be taken had the well flowed. With this sample the exact specifications of the generator would then have been finalised and the generator mobilised to site contemporaneously with the finishing touches on the grid connection. The full production test would then have commenced with the generator in place.

The decision of the Environment Agency to disallow water injection has affected all operators and is a major issue for UK operators. They will grant permits now on a case by case basis and it takes time to have each case considered. We are seeking to get approval for the resumption of reinjection at Brockham and have now been granted an initial meeting with the Environment Agency in the near future. We will present our case and in due course they will consider our application. We would all like this to happen more quickly but In our experience these things take time and the regulatory bodies cannot be rushed.

We already have the information needed to make our presentation. We have two cement bond logs (CBLs) carried out at different times and do not see the need to go to the considerable trouble and expense to acquire any more. The problem is not information but getting the case agreed with the Environment Agency. Shareholders can be assured we are moving as fast as possible to resolve this issue and commence injection of produced water from Brockham and additional sources to enable pressure maintenance in the Portland Sandstone reservoir

It is true that we had logging equipment on site last winter but to run a CBL requires the tubing on the well to be removed which requires a workover rig on the well in question which is a very large expense. Furthermore, pulling production tubing and using a workover rig would have required a further set of permissions from regulators at considerable time and expense and these were not in place when the logging equipment was on site.

Angus have not spent any money on 2D seismic in the past on Lidsey. We are considering the acquisition of a limited amount of 2D seismic to fill in gaps in the exiting data. The reason we are not acquiring 3D seismic is twofold.

1)    It is very expensive comparable to the cost of drilling a well.

2)    It is extremely difficult if not impossible to acquire in a relatively urban built up area such as around Lidsey.

The parts of the Rathlins West Newton licence covered by 3D seismic have a relatively lower density of buildings roads and other obstacles than along the Sussex Coast.

As discussed in the answers to previous questions we believe the problem with the Brockham Kimmeridge is more fundamental. The location is too close to the margin of the basin to be mature to generate enough oil to fill the limestone reservoirs. The well produced fluid from the Kimmeridge Limestone but it was formation water not oil.

Nitrogen lift is a very common technique used in wells across the world, and actually acts to unload and empty the well encouraging fluid flow. If the fracture system had been blocked then no fluid would have been produced at all from the well, given that the permeability of the matrix rock is very low. Therefore, it follows that the fracture system itself was not the problem, but rather the lack of oil within the fractures.

As time moves on the roles of founders within companies often change.  With regards to Angus and Jonathan Tidswell, Jonathan is now employed as Business Development Director.  Essentially this is an entrepreneurial role which involves, amongst other things, developing new business leads, contacts and ideas.  The Board believes that the position is exceptionally well suited to his extensive skill set, that the compensation is sensible and competitive and the demonstrable value he has already brought, and continues to bring, in this role will add significantly to overall shareholder value over the long term.

The Saltfleetby Field produced gas for many years until the export route via the Theddlethorpe Terminal facility was closed. We are merely reconnecting it to resume production. As far as the reservoir and wells are concerned nothing has changed except the reservoir pressure will have recovered a little while shut in.

We cannot give a precise answer at this time as we have not yet finalised the length of line to be acquired and agreed a price with a contractor. We have talked with a contractor though and intend to achieve the best possible price while onshore UK activity is very low.

We have explored this possibility but at present are planning to put the Portland Sandstone reservoir back in production when the EA grant us approval to resume water injection and the OGA approve our new development plan.

During the initial testing of Balcombe we produced considerable amounts of water but after analysis we are now sure that all of this was either water we had injected during operations, spent acid from treatment, or lost drilling fluids from the original drilling i.e. not the formation water such as was encountered at Brockham.

After the last test we went back to the records to forensically examine for fluid losses and found that we had still not recovered all the fluids lost during the drilling of the well. We can be sure that the water we produced was lost during drilling because the salinity matches the drilling water used not the formation water.

Furthermore we produced a considerable amount of oil during the previous test, some 100 barrels.  This figure is not to be confused with our conservative target of 300 barrels per day (or gross revenues of c. £5 million of which our share is 25%). The original vertical Balcombe 1  well on the same site was tested in the late 1980s and produced only oil on test. This is why we are much more confident about Balcombe especially as it is much closer to the centre of the basin than Horse Hill and therefore is more mature for the generation of oil.

Our geochemical work that we have carried out also confirms that Balcombe is not marginal with regards to its location in the basin, as opposed to the location of Brockham further north.

There is no difference between the applications, save for the length of time we are requesting for the test. However at the time of requesting to carry out more testing of the Balcombe well we were advised that our planning consent had expired with the ending of that activity.

Each activity requires new approval. As the time taken to get planning approval including all the preparatory work is around nine months to a year new reports had to be prepared as the previous ones have a short shelf life. As discussed above the onshore UK oil and gas industry is very highly regulated and we must accept the time taken to meet all the various requirements of the different agencies.

The planning authority have 13 weeks to respond so we anticipate their findings by the end of the year. Once that is through then we can order equipment and make the final applications to the OGA and HSE. The EA authorisation already covers the initial stages. The HSE require 4 weeks to consider and we also have to carry out some site work so our expected start date for initial works is in February.

While the application is currently under the consideration of the planners, we are preparing to tender for equipment and services, as well as remaining in communication with the regulators.

We endeavour to keep the time between planning approval and the start of work to an absolute minimum, however this will depend on any pre-operational conditions imposed by planners, EA and other regulators.

The preparation of a planning application such as this requires numerous other studies and reports to be prepared. So for example the local populations of bats must be studied in detail so that our activities do no disrupt them. This work can only be carried out at certain times of the year. There around twenty reports attached to the environmental part of the application alone, each one taking many weeks of work. It takes a long time and we slid back a few weeks due to some failed environmental monitoring equipment and delays to subcontractors collating data. As a company we certainly would have liked to have submitted the application at the end of August, however we were not prepared to submit a substandard application early, but rather chose to ensure that all reports and text were of the highest quality.

We are currently in the process of remapping the Lidsey field from the existing seismic lines covering the field and the surrounding area plus the data from the number 2 well. When we have completed this work we can make a final decision on the new seismic to acquire. In general, it is easier to acquire seismic in the winter as there are fewer crops in the fields, roads are quieter and there is less extraneous noise to affect to sound recording.

The oil in the Kimmeridge in the Weald basin was generated when these rocks were at a considerably deeper depth than they are at present. At that time the shale was at a high enough temperature and pressure to begin generating oil. The further towards the centre of the basin the hotter it became and the more oil was generated. The Brockham location is slightly further towards the edge of the basin than Horse Hill and although geochemical work suggests that it reached the required temperature it is now clear that limited volumes of oil were generated and not enough to fill the limestones in the Kimmeridge as at Horse Hill. A few miles to the North or South making all the difference. Originally it was believed that the oil generated would have filled the limestone reservoirs completely but now it is clear that only the structural highs such as at Horse Hill are full. So, the answer is that it seems the Kimmeridge Limestones in the structure at Brockham did not fill. And yes, we did attempt the same washes carried out at Horse Hill to encourage the well to flow, but in this case, it produced water not oil. Angus did not reach this conclusion hastily or without careful consideration of all the available information.

The accusations that Angus knew that Brockham would not flow and hid this information from shareholders is complete nonsense. For the company to hide such information would not only be illegal but also totally pointless and the idea that company executives would deliberately break the law to mislead shareholders is simply ludicrous.

In reality, the company continued to believe that Brockham would flow commercial oil right up until the point where we had exhausted all options to make this happen. Until the decision was made to abandon attempts at getting the well to flow, all required kit for an Extended Well Test was either on site or on standby to be mobilised to the site immediately should the well begin to flow. This was an expensive contingency which we would not have engaged in had we been pessimistic on the final outcome.

As clearly announced in RNS releases available to view on our website, multiple techniques including nitrogen lift, washes and two perforations of the highest quality part of the reservoir were used to initiate oil flow.

Up until the logging and isolation of a water zone it was quite reasonable to assume that the water zone was suppressing the flow of hydrocarbons and up until the final wash, it was also reasonable to assume that communication with the remaining exposed layer may have been partial. This last, in particular, was the experience at Horse Hill just prior to final success.

It was only after both final operations that it became clear that the entire perforated section of the well was producing formation water and still without any discernible trace of oil.

The declaration that efforts to produce oil from the Kimmeridge at Brockham had been discontinued came as soon as we had examined all of this evidence and concluded that the well would only ever produce water. We were extremely reluctant to give up on Brockham and to the very end we continued to try every technique in the book to recover commercial amounts of hydrocarbons.  There simply were none.

Once this decision had been reached, we declared this and have now put in hand efforts to resume production from the Portland Sandstone.

Generally speaking, the Board views bulletin boards as neutral and legitimate places for shareholders to express their views, exchange information and vent frustration.  Litigation to suppress such comment is repressive, always expensive and generally backfires. We do not wish to be the kind of company that litigates against the very people who fund us and we accept that our shareholders are entitled to their opinions and entitled to criticise us when we get things wrong.  We would however point out, and ask others to point out, to those who claim to be mounting or about to mount legal action – that they should either get on with it or get over it.

Angus have done nothing illegal, dishonest or intentionally wrong and, will very much look forward to proving this in open court should it become necessary.

This is still the target we are working towards. We have very recently had confirmation that the NTS will endeavour to meet this deadline and we are sourcing other equipment for the new production facilities also to meet this target. It is true that the work is considerable: involving:

1)     The construction of a small gas treatment facility at Saltfleetby.

2)    Tthe laying of up to one kilometre of pipeline to the new connection point.

3)    The construction of a new pipeline connection unit to the national grid.

This is a lot of work, but we are going flat out to achieve it. We have engaged process engineers, planning consultants, and a specialist contractor who deals specifically with connections to the National Grid.

The key milestones are:

1)    The delivery of the NTS Feasibility Study due to be delivered before the 1st November.

2)    The approval by Angus of the preferred connection option shortly after Nov 1st.

3)    After the approval in early November the NTS will commence detailed design and ordering of long lead equipment and we will place the contract for the design of the pipeline extension and commence ordering pipe.

At a recent meeting with the NTS team a summer 2020 target for completion was agreed.

The NTS grid are required to accept gas provided it meets the requirements for saleable gas. This includes the properties of the gas itself plus its content of water and liquid hydrocarbons plus a few other minor considerations.

Since the Saltfleetby gas has been supplied into the grid for many years the gas properties are not an issue. We do however, need to install equipment to meet the other gas quality requirements. Formerly this was carried out at the Theddlethorpe terminal until that was closed.

We are planning to:

1)     Install separation to remove hydrocarbon liquids known as condensate (these will be sold separately).

2)    We will also install dehydration equipment to ensure no water vapour is carried into the grid with the gas.

3)    We will have compression to enable the gas to be introduced into the grid at the required pressure.

4)    Lastly, we will be installing metering approved by the NTS to measure the volumes of gas we are introducing.

All this equipment we are currently designing and sourcing for the summer 2020 target.

The field produced gas for many years until the export route via the Theddlethorpe Terminal facility was closed. We are merely reconnecting it to resume production. As far as the reservoir and wells are concerned nothing has changed except the reservoir pressure will have recovered a little while shut in.

We have taken considerable care to plan for the ultimate abandonment of the Saltfleetby Gas Field, probably in ten to fifteen years from now, to ensure we have not acquired a significant liability. That work is complete and is under discussion with the OGA. We also aim to complete the decommissioning of two partially abandoned wells at an early stage. We expect however to fund the eventually liability from the considerable revenues generated by producing the remaining gas in the field.  First full year gross revenues are expected to be in excess of £7 million and to greatly exceed total abandonment costs of £2.5 million.  The Company’s general approach to abandonment provisioning has been comprehensively laid out in an RNS release of 24 October 2019.

Yes, we are going through the processes for agreement by the OGA that Angus can operate the field. This process is proceeding as expected and we hope to have updates for investors in the near future.