Member Info for Exploration

Deltic out

In the earliest days of the strategic review, the Board concluded Capricorn's near-term strategic focus should be primarily on Egypt , and to farm down, monetise or exit exploration concessions outside Egypt. As a result, Capricorn will need a substantially reduced headcount in the UK and will therefore shortly enter a redundancy consultation process which is expected to result in an organisation of less than 40 people in the UK. Capricorn anticipates the majority of these changes will be made in the coming two months.

https://www.nstauthority.co.uk//news-publications/news/2023/nsta-gets-tough-with-firm-suspected-of-undermining-uk-energy-security/

https://www.nstauthority.co.uk//news-publications/news/2023/nsta-gets-tough-with-firm-suspected-of-undermining-uk-energy-security/

Will UKOG be booted off the Loxley licence if they don’t drill?

On March 15th ONE-Dyas has moved Valaris-123 to drill another appraisal well at Crosgan in 42/15a. The site survey was completed a few months ago, including U4 samples for penetration tests.

42/15b-3 was drilled in 2015 by RWE Dea and reached a total depth of 8400ft. It encountered gas bearing sands in the Carboniferous Scremerston formation, although the main target was the deeper Fell Sandstone. Gas was also found in the overlying Zechstein.

Its close to Deltic’s P2567.

The main point is that this part of North Sea features numerous small prospects which can only be developed as a cluster and co-operation between operators.

FD

All the procedures for spending money in any JV are specified in infinite detail in the Joint Operating Agreement. It’s the bureaucracy which underpins the industry including huge projects costing $billions as you know.

In my experience it works.

In a well run company the COO and the CFO should be joined at the hip and use their judgement to assess what can go wrong.

The CFO cannot say Deltic is fully funded for 2024 without approval of the work Programme and Budget, which is still being developed.

But I’m afraid neither the CFO nor the COO at Deltic has the long-term experience to cope with Murphy’s Law in E&P operations;

1) If anything can go wrong, it will.

2) If there is a possibility of several things going wrong, the one that will cause the most damage will happen ?rst.

3) If anything just cannot go wrong, it will anyway.

4) If you perceive that there are four possible ways in which something can go wrong, and circumvent these, then another way, unprepared for, will promptly develop.

5) Left to themselves, things tend to go from bad to worse.

6) If everything seems to be going well, you have obviously overlooked something.

7) Nature always sides with the hidden ?aw.

Cost over-runs and schedule delays don’t exist - they’re just the result of human shortcomings.

In practice, when un-budgeted funds are needed, a supplemental AFE is conjured up for approval by JV representatives. If one party cannot pay, a 'fix' must be agreed or the party goes non-consent, with penalties.

FD

How much does it cost?

The way it works for Selene is as follows;

By September this year the Operator will submit a technical proposal for the 2024 Annual Work Programme on each licence. The techies will thrash out what needs to be done and agree on that. The work programme is then costed and presented to the Operating Committee for approval. Estimates are sometimes classified as ‘Class 3’ - which means plus or minus 30%

In the rare event the non-operating partner can’t afford it they can go ‘non-consent’, but the penalty is that they don’t receive any well data and may even forfeit their interest in the licence. But, in practice, it never reaches that point and mis-alignments on budgets are sorted out beforehand.

Once the Work Programme and Budget is approved it is still just an estimate. The Operator then tenders for drilling services and presents their recommendation to the Operating Committee.

In reality, that is the first time a firm cost figure in known, usually with a 10% contingency.

After that an Authorisation For Expenditure (‘AFE’) is circulated for approval to all parties and requires signature by the representative and the alternate of the Operating Committee for each partner.

The the Operators accountants spring into action and issue cash calls on a monthly basis.

When the rig is mobilised the operations team includes a cummulative daily cost with the Daily Drilling Report which includes everything from mobilisation cost, helicopters, sacks of mud - you name it etc.

So the answer to the ‘how much will it cost’ question is only known after the rig is demobilised and invoices paid, sometimes weeks later.

I meant share profits

check out ************* opinion

Dr P

You raise some good points. In terms of ‘$-in’ for ‘$-out’ Selene wins hands down.

Perhaps a better option is for Deltic to trade its 30% interest in Pensacola to Shell in return for a full carry by Shell on Selene. A simple equity exchange freeing Deltic of the need to raise more money.

Some would also argue that the current ‘under-valuation’ of Deltic’s share price is mainly self-inflicted by lack of communication by the company. For example, if Deltic had explained the first Pensacola well was designed to establish the presence of moveable petroleum and, if successful, to be followed by a second, horizontal well to establish commerciality, then investors would not have been left guessing.

Looking ahead to Selene, I’d expect Deltic to create a pre-drill narrative to explain the well’s technical objectives and address the critical issues of reservoir compartmentalisation, horizontal drilling and plans for fracking. Surely this new well will be designed as a horizontal potential producer due to its proximity to Shell’s Barque platform?

As you say, the commercial attraction of Selene is that gas has been discovered already and it is ~10km from Shell’s Barque platform which, in turn, connects to the Clipper system whose ultimate destination is the Bacton Terminal. See the link below which shows ullage available in the Clipper system facilities.

https://www.shell.co.uk/promos/clipper/_jcr_content.stream/1675778334037/9eca456118ad315ed028c499c0334a1d3eaa595e/clipper-asset-fact-sheets-marketing-dec-2022.pdf

It’s not as though any of this is secret - no-one can ‘steal’ the licence and the approach is widely published. Shell has the gas export route needing more gas to ensure the BarqueClipper facilities operate at full capacity. Barque is already in decline..

Yes, it’s tough working alongside a major like Shell but they realise that minor partners have investors who need to be kept informed, especially as Deltic will need more money to participate once the £ cap is exceeded.

When you look at the evolution of the nearby, look-a-like Ensign gas field you can see how Selene is probably an excellent project. Ensign started out with non-commercial vertical wells delivering 15 mmscfd and, after fracking, horizontal wells producing 44 mmscfd - and all this nearly 20 years ago.

https://cupdf.com/document/ensign-unravelling-the-enigma-devex-ensign-unravelling-the-enigma-ensign.html?page=8

Dr P

I suspect we’re thinking along the same lines.

One way to assess the value of a resource is to take a ‘bottom-up’ view and imagine a case where there is no geological, appraisal, project execution, price or political risk. That’s where the $10/boe pops up and is remarkably similar in various jurisdictions.

The other way is to take a ‘top down’ view and look at what resources or reserves have actually sold for in UKCS. And un-appraised discoveries in relatively unknown reservoirs have traded at 10 cents to 50 cents per boe in last decade.

In other words, taking Deltic’s assessment of 45 mmboe as a starting point it has cost to Shell/Deltic more to make the discovery at Pensacola than its actually worth today. Hence static share price.

So I agree completely that to advance the discovery to Proven Un-developed Reserves Shell/Deltic have to decide how much they can afford to spend to see increased value exceed appraisal investment.

This happens with almost every discovery in a new play or even a supergiant discovery where nay-sayers initially outnumber the supporters. My guess is that Deltic's 30% is worth more to Shell than a newcomer, especially with Shell's tax break. But all that hinges on the next phase of technical work.

Robroom

You might expect $10/boe for proven, producing reserves in UKCS in terms of value calculated as shown by Deltic.

But there are no ‘reserves’ as yet at Pensacola and on a mark to market basis for recent UKCS transactions you can expect between 10 cents and 50 cents for an unappeased discovery.

Fairdealer

I wish it was nitrous oxide - but at this share price smells more like hydrogen sulphide!

sharegnomie

Shell don’t need to buy Deltic’s share of either Pensacola or Selene because they may even get it for nothing.

The typical UK Joint Operating Agreement contains forfeiture provisions for default in the event the defaulting party cannot pay cash calls or invoices. e.g. Deltic runs out of cash or cannot find a buyer for their share of a venture or raise more money.

The non-defaulting party e.g. Shell in this case, has the right - but not an obligation - to acquire the defaulting partner’s interest or part thereof for zero consideration.

The drawbacks of forfeiture are that enforcement can be difficult as the defaulting partner may not be willing to sign the required novation agreements. This is usually because directors may be personally accountable for breach of fiduciary duty.

To overcome this, there is usually an irrevocable power of attorney exercised by the Operator on behalf of the defaulting party which is prescribed under the Joint Operating Agreement.

Gasatapeep

Communication? - It’s apparent the root cause of the Pensacola debacle lies in lack of communication to investors about the well’s objectives.

But, in reality These were all achieved - i.e. 1) geological model proved, 2) gas present and 3) moveable hydrocarbons proved and 4) enough information gathered to justify appraisal/development planning using horizontal wells. 100% success.

What did we get on Pensacola? Details of sub-commercial, rapidly declining flow rates leading to collapse of share price and widespread disappointment amongst shareholders.

Sure - Shell is operator, but they respect the right of partners to keep their investors informed.

For example, looking ahead to Selene, I’d expect Deltic to create a pre-drill narrative to explain the well’s technical objectives and address the critical issues of reservoir compartmentalisation, horizontal drilling and plans for fracking instead of leaving us guessing. Surely this well will be designed as a potential producer due to its proximity to Shell’s Barque platform.

It’s not as though any of this is secret - no-one can ‘steal’ the licence and the approach is widely published. Shell has the gas export route needing more gas to ensure the BarqueClipper facilities operate at full capacity. Barque is already in decline..

Yes, it’s tough working alongside a major like Shell but they realise that minor partners have investors who need to be kept informed, especially as Deltic will need more money to participate once the £ cap is exceeded.

Bubble

I’d be surprised if we hear any more about Pensacola before 4Q 2003.

In the normal course of business, before future plans can be made, Deltic/Shell have a lot of work to do. From a technical plan, an annual work programme and budget for 2024 must be agreed - probably in 3Q 2023, in line with the Joint Operating Agreement.

Assuming an economic case can be made to justify appraisal drilling, which will likely require one or more appraisal wells, Deltic/Shell get on with the work. Only then, will Deltic know how much money they need to participate.

But to justify appraisal drilling all sorts of studies must be completed, including;

1) PVT Analysis; In the Pressure-Volume-Temperature lab, reservoir engineers determine reservoir fluid behaviour and properties from oil and gas samples collected during the flow tests. The aim is to simulate what takes place in the reservoir and at the surface during production. With a mix of gas, oil, condensate and water tested at 41/5-2 this is really important.

2) SCAL; (Special Core Analysis). This extends the results of routine measurements to understand behaviour of fluids at reservoir conditions. SCAL data is used to support log and well test data to understand individual well and overall reservoir performance. However, SCAL measurements are more expensive, and are commonly only done on a small selected group of samples, or if a difficult strategic reservoir management decision has to be made.

3) Seismic reprocessing/interpretation; Now the acoustic properties of the gas-bearing reservoir have been measured from the well, the geological model can be refined from the 3D seismic to predict the probable extent of the gas accumulation, and hence reserves.

4) Conceptual development options; How many wells needed? Fixed platform? Export options? Cost? `Schedule? Oil and gas price forecasts? Etc etc.

5) Commercial analysis; Choice of best options to define objectives of Appraisal Programme. Assess risks and sensitivities.

FD

Deltic has far too many ‘confetti’ shares in issue making up ~ half of those issued.

Capital reduction is not widely understood, but why not start by cancelling worthless option shares held be certain board members. In current circumstances Deltic cannot raise more money by issuing more shares and they only have themselves to blame.

FD - capital reduction on the way?

FD

Cairn disclosed in a 2022 update. Here is is in quotes.

“In the second half of 2021, the Capricorn Group farmed into and became operator of five Southern North Sea licences: P2428 and P2567 (Capricorn 60 per cent. WI) and P2560, P2561 and P2562 (Capricorn 70 per cent. WI) with partner Deltic Energy.

The Capricorn Group also completed the acquisition of nearly 700 km2 of broadband 3D seismic data over the P2428 licence and surrounding area in November 2021, which fulfils its work programme commitments for the current and next licence phases and will inform a drilling decision in the future.

Naturally, the Plymouth prospect was the initial focus, given the potential read-across from the Pensacola well to be drilled later this year. However, the new 3D data does not support the earlier interpretation made on the legacy 2D seismic and the prospect has been downgraded in relation to the other prospects and leads which exist on the licence. Interpretation of the new data is ongoing, with Capricorn now directing its attention towards maturing the other prospects and leads in the Carboniferous, Leman Sandstone, and the Triassic Bunter Sandstone, including the Cupertino and Richmond prospects which were the original focus of the licence application”

Plymouth is a large Z2 Hauptdolomit carbonate build up which is highly analogous to the Pensacola prospect on Deltic Licence P2252 and to the 2019 discovery at Darach. The structure is a four way dip closure with the best reservoir expected on the reef edges.

It is expected that Shell will drill a well on Pensacola in Q2 2022 which will further de-risk the play and have significant read across to the Plymouth prospect.

Plymouth was estimated P50 Prospective Resources of 282 BCF with a Geological CoS of 20%.

P2428 covers Block 43/7 and 43/8. Below is a presentation from late 2020. In fact, it has probably worked out well because the Carboniferous tilted fault blocks forming the early Carboniferous source system are similar to the Cygnus gas field.

https://www.delticenergy.com/wp-content/uploads/2020/12/Deltic-Presentation-PROSPEX-2020.pdf

It’s about time Deltic tells investors more about the Selene project which is ideally placed for early production. And early production means higher value than pure exploration such as the Pensacola project.

To quote Deltic;

“Deltic Energy underlined that the Selene prospect is one of the largest unappraised structures in the Leman Sandstone fairway of the Southern Gas Basin, estimated to contain gross P50 Prospective Resources of 318 BCF of gas – with a P90 to P10 range of 132 to 581 BCF – with a geological chance of success of 70 per cent.

The company stated that it is looking forward to progressing this next phase with technical and commercial evaluation complete. The joint venture is now moving on to detailed well design, planning, rig procurement, and other “key preparations” to support drilling operations”.

The commercial attraction of Selene is that gas has been discovered already and it is ~10km from Shell’s Barque platform which, in turn, connects to the Clipper system whose ultimate destination is the Bacton Terminal. See the link below which shows ullage available in the Clipper system facilities.

https://www.shell.co.uk/promos/clipper/_jcr_content.stream/1675778334037/9eca456118ad315ed028c499c0334a1d3eaa595e/clipper-asset-fact-sheets-marketing-dec-2022.pdf

But the catch at Selene is reservoir performance. The Barque Field is associated with some of the earliest gas discoveries in the southern North Sea. In the Sole Pit area the reservoir, the Lower Leman Sandstone, occurs between Carboniferous Coal Measures, which source the gas, and Zechstein evaporites which form the seal. The sandstone has generally very low permeability resulting from deep burial of the Sole Pit Trough.

The deepest burial and hence the maximum diagenetic damage to the reservoir was achieved in the early Late Cretaceous prior to two phases of inversion in Late Cretaceous and Mid-Tertiary. Compaction and diagenesis reduced reservoir permeability to such an extent that parts of the field would be non-productive were it not for the presence of effective natural fracture zones and well stimulation by hydraulic fracturing techniques.

A selected initial area at Barque was developed for first gas in October 1990 and good reservoir performance from horizontal wells led to later development of the whole field. Over the last 20 years industry has developed horizontal drilling and ball-drop, multi-staged fracking to transform productivity of vertical wells at ~10 mmscfd into horizontal wells delivering >50 mmscfd.

Selene is covered by several 3D surveys calibrated by several wells which found gas which enable definition of reservoir compartments created by pervasive faulting.

So it really should by like ‘shooting fish in a barrel’ - geologically and commercially.

Snoop

Once again I agree with you.

If the Deltic Board was a football team, faced with taking a match-winning penalty, with no goalkeeper in the opposition’s net, they put the CEO on take a long run at the ball only for him to trip over and kick himself in the goolies! And the fans have all suffered too.

The main point is that this is the only exploration well both CEO and COO have ever been involved with and they’ve completely fumbled announcement of of a result which should have doubled the share price or more.

The market knows this and the best way to boost the share price to what its worth is for the big shareholders to replace the executive board. But pigs might fly.