Member Info for Exploration

Daveyboy71

Its all about numbers.

The recent 34 tcf Basin Model defines the total amount of gas generated in Tendrara area since beginning of time in all reservoirs. Note the “small print” suggests only between 1 and 5 percent of the maximum 34 tcf generated might remain trapped in the contract area. These percentages are global averages for typical petroleum basins.

That equates to prospective resources of between 0.34 tcf and 1.7 tcf using the 34 tcf high case and barely enough for a BBQ in the low case. Sounds full CPR will reveal all although I doubt we will see it.

As a sense check from the BP Statistical Review shows proven reserves for Norway are about 60 tcf and Canada is about 66 tcf. These numbers are for whole countries – not just a small area like Tendrara.

Basin models can be useful but can also be misleading. In the end you cannot beat good seismic and careful drilling which is where we are today.

Here is the recent June 29 RNS.

Following receipt of the Basin Model, the Company is pleased to update the Company's internally estimated volumes for the exploration potential** of the Eastern Morocco Portfolio acreage, expressed as unrisked gross gas originally in place, of a low case of 7 Tcf, a mid-case of 20 Tcf and a high case of 34 Tcf. This range represents further support of the previous estimates announced on 1 February 2017.

** The total potential ("Total Potential") of the acreage is an estimated range of unrisked gross GOIP derived from the Basin Model. The Total Potential represents the total amount of hydrocarbon (gas plus the gas equivalent volume of oil) that could be available for trapping, across the whole licence area of approximately 23,432 km2. The Total Potential is a stochastic range, based on estimates of the total generated and expelled hydrocarbon from three source rocks (Silurian, Devonian and Lower Carboniferous), since the Mid Permian (approximate age of the end of the Hercynian orogeny at 268 million years ago). The total expelled hydrocarbon estimates are converted into Total Potential estimates by assuming only 1%, 3% and 5% of the expelled hydrocarbon is available to be trapped. This assumption is consistent with the assumptions used for the preliminary basin model, announced on 1 February 2017.

Partridge

Below is link to a useful paper describing the outlook for Algerian gas.

In short, production has stagnated, mainly due to tough fiscal terms, domestic demand has exceeded forecasts and big fields are in decline. The Medgas pipeline to Spain is a better commercial export option rather than the Maghreb pipeline.

80 percent of Algerian gas has a wellhead cost of about 1 dollar per mcf which means a big netback for producers from exported gas. In contrast, domestic Algerian gas prices set by their regulator have been close to or even less than wellhead costs.

The is new pipeline has been planned for some time especially since Medgas has only been used at 30 percent capacity. So plenty of capacity in Maghreb for gas from Tendrara.

https://www.oxfordenergy.org/wpcms/wp-content/uploads/2016/05/Algerian-Gas-Troubling-Trends-Troubled-Policies-NG-108.pdf

The CEO of Predator is Paul Griffiths.

Paul ran Fastnet Oil and Gas when they held Tendrara.

So he was familiar with Morocco for almost a decade with various companies including Island Oil and Gas.

Billfish

I tend to agree with you. It is not just the Finance Ministry, but also Customs, Security, Police and Environment to name but a few.

It looks to me like OGIF continues to support Sound via Onhym with the recent 8-year brand new Exploration Agreement covering the “Greater Tendrara” contract area. Only when the Energy ministry published the approval in the official Gazette can things happen because Gazettal defines the effective date of the Agreement.

According to the Petroleum Code Sound was due to relinquish 25 percent of the original Tendrara area at the end of the initial period this year. But by issuing a new 8 year Petroleum Agreement Sound has three years to continue exploring the whole area with no relinquishments until 2021 and a 25 year Exploitation Concession.

So someone, somewhere is looking after Sound in Rabat because competitors would be very keen to pick up any relinquished areas. Otherwise, Onhym would have applied the Petroleum Code procedures.

partridge

yes- incorrect. Simple sense check is that 622 bcm per year would mean Morocco would be second biggest gas producer in the world after Russia which produces 640 bcm per year.

60 mmscfd = 1.7 million cu m per day. which is 0.625 bcm per year.

If it is easier, in oil equivalent terms, Sounds gross reserves are about 50 million boe with peak production of 10,000 boe per day. Hardly big enough for a major company to bother with. Thats why the current drilling campaign is so important to demonstrate it is a material opportunity.

GRH

Well said.

Multi-spectral scanning and combination of wavelength bands – especially with Landsat 8 – is bog standard, cheap and capable of screening huge areas. They key is to “ground truth” anomalies which is precisely what Sound is doing with soil surveys. Good for them.

As someone said, micro seepage is a valuable tool in the geologists armoury to decipher the underground “plumbing” when combined with seismic and other data. Gas and oil seeps have been part of religious and cultural practices for thousands of years so nothing really new.

There is really no “perfect” seal and gas and oil will find a route from trap to the surface over time. BM mentions that the basin model suggests a lot more gas has been generated in the Tendrara “kitchen” than has been trapped and the seepage is still going on today. We are just drilling to “what is left” – probably less than 5 percent generated.

There are more extreme versions macro seepage which are generally associated with geologically young basins without good vertical seals.

Blown seals are a common cause of dry wells all over the world.

Here is an example of natural gas eruption.

https://www.youtube.com/watch?v=0xCPXg5lJeg

and a burning gas seep

https://www.youtube.com/watch?v=8TjQfBaZQAg

mymy

see page 8 for development diagram on link below.

multiple wells drilled from four or five pads connected to CPF via in-field flowlines.

https://www.soundenergyplc.com/media/1564/investorpresentation-q3-2018.pdf

Fellrunner

The “delays” may actually be part of the due process of getting things done in Morocco.
For a start, the new Petroleum Agreement only becomes “effective” when the details are published in the Official Gazette. That starts the clock running.

Strictly speaking any spending before Gazettal is not deductible from the partnership joint account. A responsible operator will usually define the start of mobilisation of a rig and associated “moving rate” payments when their Petroleum Agreement is effective. On other hand the operator may recommend relatively low cost work such as site preparation at their own risk.

The publication in the Official Gazette authorises various authorities such as customs, finance, tax, police, security, environment ministry to cooperate and do their work to enable the project to progress. Just raising and securing the Bank Guarantee in a Moroocan bank is a time consuming process.

Before gazettal the Petroleum Agreement is approved and signed by the Energy Minister in the presence of the licencees. Onhym simply orchestrates the process.

There is no need to query the timeline. Managing the process is part of the normal work conducted by oil companies throughout the world.

The RNS mentions the licence coming into force, but no date;

Further to the Company's announcement on 23 July 2018, the Company and its partners, including Schlumberger, have signed a petroleum agreement covering the Tendrara and Matarka areas (the "Greater Tendrara Petroleum Agreement"). The Greater Tendrara Petroleum Agreement, details of which are provided below, has been signed by L'Office National des Hydrocarbures et des Mines ("ONHYM"), the Moroccan State regulator for petroleum operations and it will come into force on approval of the Moroccan Energy and Finance Ministries.

JoeCreed

The new structure mapped by Sound is the same structure mapped by Fastnet, Maghreb and others before them. It is located south of the Mechkakour fault and north of the fault which defines to NW boundary of the A-Structure where TE9 is to be drilled. To the SW of the "new structure" Fastnet maps in their CPR show it is part of the SBK structural trend where the infamous Talsint scandal took place with Lone Star. Fastnets mapping supports Sounds recent RNS which says the new structure is connected to the source kitchen.

There is plenty of "old" seismic in this area - approximately 4000km in total. Mainly 48 fold vibroseis acquired in 1980s by Onarep, Agip and Pennzoil.

Thanks draft

Here is a link to CATS website

http://www.cats-ml.com

As I understand it, Cluff realised early on that mature infrastructure would need more gas. That is why the company concentrated in their core area. Looks like it might pay off.

Tolmont has been brewing for several years.

The catalyst which triggered the development, which is quite modest but very profitable, is the ETS pipeline system which is used to ship Cygnus Field gas to Easington. ETS is the old Esmond Transportation System. Esmond is a depleted gas field which produced from Bunter sandstone close to CNRL 43/11 area where there are several small prospects with classic "bright spots" on seismic.

ETS was acquired by CATS two years ago. CATS is the Central Area Transmission System which was built by Amoco in the 1980s to ship gas from fields in the 23/16 area to Teeside. More recently, I think CATS team up with the Breagh project to modify Teeside to accept and process gas, condensate and water in multiphase flow rather than separate the fluids offshore, which was more expensive.

In Tolmont it looks like the CATS owned ETS company has teamed up with Premier and Dana to keep its facilities full.

So same will happen if the CNRL prospects, Andromeda and Pegasus have enough gas.

The Tolmont Gas Field is actually a Leman Sandstone reservoir which is very productive compared to the Carboniferous fourth north. Only 4 wells will be needed with a small platform in 55m of water.

This ought to trigger interest in drilling in CNRL blocks.

Its the Takeover Code, which is designed to protect all shareholders and avoid things like false markets.

Thats why its important to use a reputable merchant bank to avoid a deal collapsing, transparency in process and so on.

On the buy side a serious prospective buyer will demand compliance with Takeover Code.

Neptunes

An excellent post.

Someone said earlier there are no delays but rather a project schedule which TBH have been very ambitious from the start. Add liberal use of oil and gas jargon such as “FID”, “FEED” and “GSA” it all sounded plausible in videos etc.

In my opinion perhaps we should reset our expectations to achieve a realistic, achievable schedule to reach the LE Goal. More rigour and discipline will likely be imposed with influence of David Clarkson to the BoD. I see at least 12 months until the LE is finalised.

But one thing which has not changed is the geology which is why I invested in Fastnet and now Sound. The outcome of the current drilling programme will probably find more gas and take until the start of the sales process.

Based on facts supplied to us the forward timeline goes something like this

Late Q4 2018 - Gas Sales Agreement

It is important to remember it is not “our gas” but rather the property of the Moroccan state. Sound is simply a contractor with rights to explore for a produce petroleum according to the Exploration Agreement and the forthcoming Exploitation Agreement for TE5 area. The gas price will have to compensate several players

the Operator – Sound or new owner, who drill the production wells
the Pipeline Company – OGIF, who finance the pipeline
the Engineering Company – Enagas, who will finance/build the processing plant
the State Oil Company – Onhym, who may participate at 25 percent
the Gas Buyer – ONEE, who need to generate commercial power

We know the Front End Engineering started in June and will take six months which means completion November 2018 . FEED defines cost streams to Class 3 Level which is plus or minus 30%. These costs are needed to calculate the value of the TE5 Project and any subsequent discoveries. Final costs are only known at Project Execution when tenders for the work are submitted and contracts awarded.

Early Q1 2019 - Start Sale process

This is not a matter of a potential buyer calling JP with an offer. Buyers and sellers are brought together by M and A specialists or investment bankers. They are the “estate agents” of the market.

Rothschilds will write a Confidential Information Memorandum (CIM) which is a document used in a sell-side engagement to market Sound to prospective buyers. Rothschilds screen prospective buyers and set up a process to arrive at a buyer and sale price.

The buyer’s technical, legal and commercial experts embark on a detailed due diligence exercise, including physical assets in the Tendrara contract area. Central to sale of upstream gas producers is the GSA and understanding of the market.

Sale is agreed but only becomes effective when assignments and change of control conditions are approved by Ministerial decree after recommendation from Onhym.

Early Q3 2019 Sale Completed

Mid Q3 2019 - Final Investment Decision and Project Execution

Project executed just in time to substitute Moroccan gas for Algerian

LimitedAccess

"Word on the Street" & press reports indicate discoveries at Pegasus and Andromeda to be tied back to the Cygnus field and then to a shore terminal. Decision to go ahead likely 2019.

It follows that Andromeda might be drilled in coming months in time to integrate results into a development plan for approval by OGA. If this happens CNRL properties become next priority for drilling to maximise benefits outlined in the OGA paper.

Investment strategy is pretty simple. Buy low and now. Wait for others drilling.

So time will tell. Cluff's approach is to under-promise and over-deliver to investors. In contrast to some AIM companies who do exactly opposite with predictable outcomes!

Maybach

It looks like the event is fully subscribed anyway.

I would hope CNRL will outline their geological thinking in the 43/11 area, although they have pretty good spread of other acreage. The Pegasus West discovery at 43/13-7 was tested at a combined rate of 90 mmscfd from Carboniferous reservoirs which astonished the industry. In “oil” terms 90 mmscfd is same as 15,000 boe per day. This result caused CNRL to re-rate the potential of its adjacent acreage. See link below,

https://www.cluffnaturalresources.com/wp-content/uploads/2016/01/Cluff-Natural-Resources-Block-P2248-Fact-Sheet.pdf

In terms of near term production OGA has encouraged operators to think of innovative methods to develop small discoveries as a group. If you look at page 15 of the attachment below you can see how Centrica – now Spirit Energy – see the plan to develop Pegasus and then Andromeda if it is a discovery. Added to CNRL’s adjacent prospects there is enough gas to support a development “hub”. Clearly, the positive impact on CNRL’s 43/11 and 4315 blocks is large.

http://oilandgasuksharefair.co.uk/wp-content/uploads/2016/11/Share-Fair-2016-Innovation-Hub-Sessions-02.11.16.pdf

Potentially a very attractive situation, but who will drill first?

CLNR is giving a talk on Southern North Sea in Aberdeen on September 6th mentioning their new play concept

https://www.pesgb.org.uk/events/oil-finders-lunch-2/

See map - they have share in Pegasus and Andromeda, operated by Spirit, next to Cluff 43/11 and 42/15

https://www.third-energy.com/offshore#Pegasus

I certainly hope so LimitedAccess

The solution is for the participants in this prospective trend to sit down and "cross assign" their licence interests where they share percentages in the whole area in proportion to some logical calculations.

TBH I would rather have, say, a 25 percent slice of a much larger pie rather than 100 percent of something unlikely to happen.

Of course, potential farmin partners into the CLNR licences see the Mexican Standoff as a barrier to be overcome so it is really up to CLNR to fix it first.

What I meant by “log jam” is that Cluff, Spirit Energy and Third Energy in 43/12 find themselves in a situation in which no-one can win or gain an advantage by drilling first and and therefore nothing happens.

Maybe it is better expressed as a “Mexican Standoff” where there is business tension between two or three companies in which no strategy exists that allows any party to achieve a “win” unless they cooperate. Once again, nothing happens until an exogenous event occurs to resolve the problem. For example, Spirit blinks first and drills Andromeda.

Ultimately perhaps the operators will team up to share drilling cost of a single well to test a multi-block trend. This is type of arrangement OGA is keen on.

Partridge

The TE5 area development plan is based on 12 wells to recover about 300bcf. So about 25 bcf per well.

Of course, productivity could turn out better and the development plan is quite conservative.