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The predator prospectus in august reported a desk top study that confirmed that onshore gas in the rharb basin with poor log results and 35% gas saturation can flow gas.
This may could also apply to chariots onshore acreage.
Jimmy
Mou 3 encountered 50.5 meters of sand in the mou fan, yet only a 43 meter gross interval is being tested, is the 43 meters all sand or a gross interval.?
If a net sand interval then a flow rate of 47 mmcf per day could be expected based on average flow rates per meter in the similar rharb basin nearby.
The is almost enough to meet the high end volume cng market in morroco.
If the agreement to sell gas at the well head is reached there will be very little capex,just revenue with very little opex.
No sure the market has grasped this.
Jimmy
Never mind,
Good points, however with a relatively wide seismic line spacing, we cannot assume that the mou fan is laterally continuous at 43 meters. The last cpr is very much more cautious than the previous cpr, particularly regarding whether the turbidite sands are in fact channel sands instead of fan sands.
Jimmy
Hi wacky thanks for posting the analysis of the mou fan gas in place of 1.1 tcf.
I have two observations,
1. The gas in place is calculated based on 43 meters of reservoir encountered in the mou fan in mou 3, however, this is applied to a structural area of 30km2 which includes mou 1 where the mou fan reservoir is only 10 meters. So it’s unlikely 43 meters of reservoir is common through out the reservoir, particularly bearing in mind that this area includes a stratigraphic pinch out of the reservoir. If there was 3D seismic it could be calculated very precisely, otherwise I would reduce the 43 meters to an average of 26.5 meters based on known drilled reservoir intersections.
2. As you pointed out the calculation is for gas in place, whereas economic value is recoverable gas , usual to apply a 60% recovery factor at this early stage of appraisal.
This would adjust the calculation to a recoverable reserve of 400bcf, still very commercial for the mou fan reservoir.
In addition, we have the mou a sand reservoir , which appears to be prevalent at 11.5 meters in mou 3 and a similar 12 meters in mou 1, which predator report as being seismically correlated over an area of 58km. I have not done the calculation, but estimate it to be circa 350 bcf recoverable.
Then there are the other reservoirs, to be included, particularly the shallow gas reservoir in mou 3.
Still very valuable as soon as pg can flow test and confirm it’s gas and not possibly gas.
Jimmy
2.
Cattleman,
For many offshore wells, testing is not performed because the wells are extensively sampled and measured, gas and pressure readings taken from reservoirs along with side wall cores, provide information to calcualate a flow test that is usually acceptable for farm out and banking project finance, supported by an independent report.
There is no indication that I have seen that predator did any of this, so hence flow testing is nvery important.
Jimmy
Hi Brv,
Thanks for your analysis of the current prd situation.
I agree that Pg has a focus on drilling, I believe that the engineering and reservoir performance are not areas that Pg gets excited about, as I believe he is very much an explorationist.
The analysis you presented further confirms that to me ,as indeed the Jurassic target is indeed very exciting and a major breakthrough.
However, I believe that the pg analysis of the market is flawed. The market is looking for flow test data to confirm the three significant discoveries already made. Prd has raised funds three times to carry out flow testing and has yet to do so and a further delay will raise suspicion that something is not right . Based on the published data prd is likely to made substantial onshore discoveries, yet it has a market capitalisation of of £60 million instead of £180 million which is easily justified , because the market is fearing further dilution. The cng plan is an excellent way to address that, and then drill the hell out of the area from production cashflow, it’s a good plan and they should stick to it.
Pg should be aware that raising funds for one purpose and not using them for such purpose may have legal implications and it’s now time to flow test.
Jimmy
Hi fernan
The green hydrogen project is currently being funded by total, in due course as the project progress and assuming the economics stack up, then the European investment bank have signed an agreement with Mauritania to provide project finance , expected at 90% of capex , with the balance funded by chariot diluting down its current equity interest of 50%.
The green renewables are financed on a jv basis with Total at a minimum of 50% , with project debt also provided at estimated 70% , so the equity components are relatively small so far.
Chariot have stated they are going to get equity funding at the subsidiary level, so hopefully no more equity dilution at top company.
Jimmy
Great article in upstream, some very important insights on the business.
Firstly with regard to the suggested target of 250 mmcf per day, this is very achievable from three production wells and the proven gas reservoirs in anchois 1 and 2.
So what does that mean in terms of production ebitda.
Using the $12 mcf guided price this is $3 million per day gross, less royalties is $1,056,675,000 per year. Assume opex at $60 million gives an ebitda of $996,675,000 gross. Per year. At a 37.5% interest to chariot its $373, 753, 125 per year, at a 25% interest its $249,268,750 per year.
If the plan is for higher capex, carried interest, but lower carried working interest, very attractive.
Chariot currently valued at less than 6 months future ebitda assuming a very low 25% working interest.
Strong buy
Jimmy
Hi surfit,
My comments on the cash sweep are based my negotiations for a project financing with a uk consortium of banks, perhaps a farmin partner may be accommodating, but there would be a price.
Jimmy
My view of the move onshore is for the following reasons.
1. By taking out the onshore licence it prevents potential farm in partners doing due diligence offshore and investing onshore . Narrows the farm in options.
2. Chariot have unlocked the geophysical signature of gas offshore and are now applying this onshore , I personally think they have identified areas of thick reservoir likely to be gas bearing and the potential reserves are bigger than previously announced.
3. A farm out deal for offshore may include a non recourse loan for the capex, this usually includes involves a “cash sweep” of the net production cashflow to repay the loan quickly, so that leaves chariot needing production cashflow from elswhere to cover basic ongoing corporate costs. With an 85% success rate, going onshore is the right solution to get into cashflow asap.
It’s a good move.
Jimmy
Fernan,
I would not compare barryroe to anchois as barryroe had very thin sand reservoirs below direct seismic identification. Anchois has thick sand reservoirs and a very modern 3D seismic with direct correlation to two drilled wells which validated the seismic interpretation and they are located in a basin with an 85% drilling success using modern seismic attributes.
I believe it’s highly unlikely they will drill anchois east without a farm out to finance it.
Jimmy
Gooner,
My reading of the chariot situation is they they have received farm in offers that did not adequately value the low risk additional gas potential of anchois east, and the O sands below anchois 1 and anchois west, which if successful would bring proven gas volumes to circa 2tcf.
The first step is to get anchois east drilled, and chariot announced the ordering of long lead items for a well and issued a rig request for tender for drilling. If successfull that low risk production well and exploration appraisal well will bring proven gas to 1020 bcf and unlock the field development farm in.
Huge progress has been made on environmental base line reports and gas pipeline surveys that are required to derisk the development to secure a development farmin the value of which will be determined by the anchois east well results.
That’s my reading of the Agm presentation.
Jimmy
I have been considering why a farm out has not been announced yet. We know we are starting with 637 bcf of proven gas, but as disclosed on page 11 of the latest presentation there is substantial very low risk upside . Chariot have disclosed that they have ordered long lead time drilling equipment and issued tenders for a drilling rig and services for early next year, to drill anchois east production development well and will include a slight deepening to the proven O sand , below anchois east and to drill the anchois north footwall. These additional targets have a reported chance of success of 49 to 64% . If successful such a development well would increase proven gas volumes to 1020 bcf.
So my guess is that farm in partners are not giving enough value to these low risk gas prospects, so one possible solution is a phased farm in deal. Initial farm in is for x % of the 637 bcf proven gas, which would reduce if the proven gas increases.
If the exploration potential of anchois east gets proven it increases proven gas to 1020 bcf, but it also de risks the O sand below anchois 1 and anchois west and plié, combined they increase gas volumes by a further 914 bcf.
So, I am expecting a phased farm out to include low risk exploration drilling and a capex carry depending on new proven gas , supported by project debt if required.
A lot of value here and very low risk.
Jimmy
Louis,
I find it extraordinary that you look at an evaluation of chariot without any reference to the proven gas volumes or indeed the low risk prospective resources which can drilled at very little incremental costs when developing the anchois field.
Jimmy