Member Info for Exploration

MK

But I thought the GSA was finalised end Q2 according to JP and Sound website?

Has JP entered your competition yet?

My interpretation of the FMA is that the NPI "equates" to a working interest, but isn't a real Working Interest. Either way how is this valued? That is a question Mr Big in Schlumbberger will be asking.

Schlumberger Net Profit Interest

Under the FMA the Company has granted Schlumberger a net profit interest of half of the Company's interest (which equates to 18.75% initially increasing to 27.5% after the first well).

n4aPound

Who else could hold up partner approval apart from Schlumberger?

This is a great project but Schlumberger is stuck with an old Saipem rig whereas they have modern state of art SCR rigs at Hassi Massoud in Algeria looking for work. The partners would have agreed the annual work programme and budget 9 months ago. Sitting in Schlumbergers seat I would want full access to the FMA with Sound and would not budge from that position. On other hand Sound must have an agreement with Saipem for their rig.

So as BM reported "some partners have a longer approval process".

Luckyman

There is a 36 month restriction on oGIF to keep their interest below 29.9 percent until 2020.

"The consideration for the acquisition of the OGIF Interests will be 272 million new ordinary shares in the Company (the "Consideration Shares").  The Consideration Shares will, on issue, represent 29.0% of the Company's enlarged issued share capital (24.5% of the Company's fully diluted share capital). As part of the transaction, OGIF will agree to a 12 month lock-in in relation to the Consideration Shares, a 36 month restriction on exceeding 29.9% ownership of the Company and will enter into a relationship agreement with the Company. OGIF will be granted the right to appoint one Non-Executive Director, expected to be a senior OGIF executive, to the Board of the Company for so long as OGIF continues to hold more than 10% of the Company's issued ordinary share capital."

On "partner approval" does anyone think Schlumberger is blocking TE9 TE10 and TE11 etc? They must have realised by now that their Net Profit Interest is a distant dream and stymied JPs best efforts to make progress? just a thought. Neither Onhym nor OGIF would prevent progress and I doubt Sound would go sole risk even with 30 percent CoS.

wh0sthedaddy et al

I have no doubt in Sounds capacity to deliver based on previous experience. I just referenced a few points from a typical drilling contract where the Operator needs to tread carefully without backing of the licence group paying the bills. Drilling is a notoriously tough area to contract and administer because the sums of money are so large.

I have seen numerous JVs where one or more partners have instructions from their HQ to delay spending. Often this has nothing to do with the project itself. Sometimes this is because they do not have the money and other times due to simple capital allocation priorities. BM and team are more than capable of choosing top quality locations, which suggests other reasons for delays in my opinion.

Time will tell.

Ok Daveyboy

This thread started on the issue of "Partner Approvals" which, on a geotechnical level, seems pretty straightforward.

So "why the delay" investors are rightly asking.

I can imagine a situation in the Management Committee where partners support the proposal for 3 wells, but perhaps one partner, mentioning no names, says, "OK, go ahead and make your plans but we are not approving release of any funds until the precise locations of all 3 have been agreed technically. Our logic is that a continuous operation is just more cost-effective."

This is consistent with JPs comments on site prep for 9 & 10.

At the bottom of the oil & gas food chain the operations and procurement teams then have to scramble to make it all happen.

Well all I can say is that I would not want you or Daveyboy running the drilling Procurement Department!

On the Sound side would you sign a contract for 3 wells without a signed AFE for the money?

On the Saipem side you would want to maximise your revenues by knowing the forward programme and recover some costs of that rig being idle since it first appeared in Morocco for Longreach seven years ago.

Yes good relationships are important but so are contracts. In the "East" relationships govern contracts, but in the "West" contracts govern relationships. It is a constant negotiation.

PNE

The Drilling Contract with Saipem will also be a challenge for 3 wells without knowing precise locations and timing. As I understand it Sound wisely needs flexibility depending on outcomes of each well. So before a start can be made, the locations and likely timing of all wells must be known and preferably approved by the Operator and Partners. Sure, an option agreement can be included in the Drilling Contract but any normal drilling contractor will want to be compensated if the options are not exercised. It just costs money.

Mobilization and Demobilization; Saipem and Sound need to be certain that there is a clear and definable point in time and space for both mobilization and demobilization. Depending on the terms of an agreement, day-rates may begin and end at mobilization and demobilization. They should consider how demobilization is affected, particularly if the end of demobilization triggers the cessation of payment of day-rates. How is demobilization determined? What are the criteria for establishing demobilization?

Term; The term of a drilling contract may be defined by time or by the drilling of a specified number of wells. Either approach is common in long term drilling contracts. When the term of a drilling contract is based on the number of wells drilled, a clear definition of "well" should be included. For example is a sidetrack a well? The drilling company has an expectation that at least a certain number of days will be used drilling the firm wells in the contract giving a minimum revenue stream, whereas the operator needs the flexibility to vary the drilling plan as geology dictates, the right to abandon drilling if the target is technically, or from a budget perspective, not obtainable (including after fishing and sidetracks), and desires to complete the drilling plan as quickly as feasible in an effort to reduce well costs.

Same goes for contracts for drilling fluids, logging, logistics, work camps, transport. It is a huge legal and logistical challenge and i am sure Sounds team in Rabat can handle it, although it takes time. It is easy to make a powerpoint graphic shown order of drilling, but turning it into a bulletproof contractual operation requires outstanding capabilities in the field. Get it wrong and post project squabbles over money go on for years and become a burden. The last thing we need for a clean LE is a court case cropping up in due diligence.

McRonin

Your appeal to Angela is not needed.

The days of long-term supply supply contracts, oil-indexation and take or pay are history in Europe. When Tendrara is connected to the Maghreb Pipeline the new Moroccan Gas Law is designed to connect to the PVB virtual trading hub. This does not currently link to Europe because there are a few missing pipeline links in France but this will be fixed soon.

With trading hubs, if Russian supply declines Norway, UK, Netherlands and LNG increase their market share. But Russia also needs the money too because their fields are in decline as well. If Russian gas fields were discovered today they would be marginally economic because they are so far away; they were developed in "another world" at "another time" when economics didn't matter. In other words forget "physical gas" - with trading hubs producers just need to insert one methane molecule at a given location and a buyer can buy a different methane molecule somewhere else even the delivery point is 1000s of km away.

See link below.

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2017/05/European-traded-gas-hubs-an-updated-analysis-on-liquidity-maturity-and-barriers-to-market-integration-OIES-Energy-Insight.pdf

https://www.bp.com/en/global/corporate/bp-magazine/locations/shah-deniz-2-building-gas-project-azerbaijan-georgia-turkey.html

ktf

Sound Energy's Madeddu sets up Enexon Technology
Italian national Luca Madeddu, chairman of the Moroccan subsidiary of Britain's Sound Energy group since 2015, has taken over as head of new company Enexon Technology. The new company is owned by Enexon Sviluppo, an Italian company headed by a relation, Stefano Madeddu, which is investing in solar energy. Enexon Technology plans, however, to restart operations on depleted hydrocarbons fields thanks to new technologies. Luca Madeddu has inside knowledge of Morocco's key gas projects. Sound Energy, which is developing the Tendrara, Meridja and Sidi Moktar fields, went into partnership in 2017 with Oil & Gas Investment Fund, an entity which took over Prince Moulay Abdellah Alaoui's interests in the Tendrara field. Following this link-up which was organized by merchant bank AFG (owned by Mohamed Benslimane, husband of Lalla Zineb, a cousin of Mohammed VI), Sound Energy made former AFG partner and OGIF director Mohammed Seghiri managing director of its Moroccan subsidiary.

Ok - it’s 2.29 million dollars per bcf on the Fastnet model - same volume and 9 dollars per mcf

Doohhh

I’ll get this right third time lucky;

2.29 dollars per bcf

Sorry MikeGP - I made error - the value quoted is 2.29 dollars per mcf.

When Fastnet were working on Tendrara they realized drilling and completions were very important. That is why they hired Dennis Krahn to design the wells. Krahn is something of a drilling legend. But they ran out of money and left. But Sound/Schlumberger carried on regardless and turned TE8 into a “partial success”. I really do hope they have learned a lesson and TE9 has been designed accordingly to make the most of our money.

Fastnet quote from 2013;

“A new well design study by Dennis Krahn, Chartered Petroleum Engineer, Summit Upstream, supports the enhanced well potential by designing and drilling a conventional appraisal well using modern technologies to minimize and, preferably, eliminate the formation damage seen in previous drilling operations which impacted previous gas flow rate potential. Scoping well costs have been determined based on the design and equipment criteria necessary for optimizing drilling operations to ensure good deliverability from the TAGI reservoirs.”

MikeGP

Here is a link to Fastnet evaluation of TE5 area. This was done by a UK engineer called John Tingas based on 310 bcf recoverable. Value is 3.29 dollars per bcf based on numbers at the time.

His development plan was same as current Onhym plan with exception of horizontal wells with multi-stage frac jobs. The results of TE6 and TE7 have reduced the risk on productivity recognized by Tingas.

http://www.ise.ie/app/announcementDetails.aspx?ID=11770722

Ozzie43

When a new area is brought into production the GSA usually takes the form of a Depletion Contract.

This means there is a dedicated source of supply from a specific field which is dedicated exclusively to the buyer under the contract.

Gas quantities available for delivery each day are generally fixed for the initial build up period and for the Plateau Period. The Plateau Period can be either for a fixed period of time or until a pre-determined percentage of the gas in the reservoir has been produced. Thereafter during Decline Period, the quantities available are re-set each year as the production capacity of the reservoir declines.

This was the accepted approach in the UKCS in the 1960s and 1970s. As more gas fields were found Depletion Contracts were replaced by Supply Contracts which simply required a certain amount of gas delivered irrespective of the field it had come from. So, if for example Shell/Repsol found gas in their contract areas they might start with depletion contracts which, over time, might morph into a supply contract.

Moroccos new gas law seems to be designed to smooth the path to a completely liquid market for gas similar to UKs NBP approach which enables trading between the various European hubs. The new gas law also anticipates the arrival of the LNG terminal in years to come. If this is enforced gas suppliers in Morocco must offer their gas to ONEE first. Fortunately Moroccan authorities are very pragmatic and perhaps will avoid the complications of Depletion or Supply Contracts and go straight to a Moroccan ‘hub’ price in the same way Spain is heading. In that case spot and future prices would be specified on a daily basis by ICE of a similar price monitoring system.

SO

You are right. A subsidiary has been set up in Morocco to be run by Luca. The depleted field story is rather puzzling because apart from Sidi Fili Oilfield and perhaps Sidi Rhamen there few examples in Morocco except perhaps Meskala.

Luckyman2

Here is link to Enexon

http://www.enexon.eu/

Sound Energy's Madeddu sets up Enexon Technology
Italian national Luca Madeddu, chairman of the Moroccan subsidiary of Britain's Sound Energy group since 2015, has taken over as head of new company Enexon Technology. The new company is owned by Enexon Sviluppo, an Italian company headed by a relation, Stefano Madeddu, which is investing in solar energy. Enexon Technology plans, however, to restart operations on depleted hydrocarbons fields thanks to new technologies. Luca Madeddu has inside knowledge of Morocco's key gas projects. Sound Energy, which is developing the Tendrara, Meridja and Sidi Moktar fields, went into partnership in 2017 with Oil & Gas Investment Fund, an entity which took over Prince Moulay Abdellah Alaoui's interests in the Tendrara field. Following this link-up which was organized by merchant bank AFG (owned by Mohamed Benslimane, husband of Lalla Zineb, a cousin of Mohammed VI), Sound Energy made former AFG partner and OGIF director Mohammed Seghiri managing director of its Moroccan subsidiary.

Petroleumeng

Welcome back. I sense the team at Sound may have a theory about how to predict porous and permeable TAGI from their new seismic. I do hope so because this reservoir is well known to be unpredictable over kilometres or even 10s of metres. The prevailing wisdom in Morocco is that faulting in the Tendrara basin occurred at the same time the TAGI reservoirs were deposited.

I expect the new basin model has revealed just how complicated the generation of oil and gas has been in the area. With three rich source systems in Silurian, Devonian and Carboniferous oil and gas would have been generated and accumulated fairly early according to the burial history. Later more burial cracked oil into gas and even later gas turned into carbon dioxide as we see in the TE5 area. Later, the whole basin is “inverted” and fluids re-arrange themselves. Gas migrates into any oil accumulations and equilibriates with lighter liquids. Eventually, as the basin rises, some of the gas condenses in reservoirs and become “retrograde condensate” or “oil”. The type of oil used to be used to run cars in the early days until refineries were developed to make gasoline.

Anyway, condensate yield in Tendrara well tests by ONAREP was reported at 4 bbl/mmscf. So pretty “dry” gas. At Meskala the ratio is 40 bbl/mmscf. Bottom line is that there will be plenty of surprises in the TE9, TE10, TE11 drilling results.