Member Info for Exploration

Crude

Yes - how can one vote for Bouteflika who is almost dead.

His brother, Said and Army chief, Salah seem to have grabbed the steering wheel in Algiers.

In practical terms this means there is no-one in Sonatrach with authority to agree inter-government gas contracts. So a good opportunity for Sound to progress its GSA.

Politics, Crude

If Morocco's Energy Minister signals he'll take 'all the gas' from Te5 gas field, he's also indirectly telling Sonatrach he does not need 60 mmscfd of Algerian gas in 2021 when their contract expires.

KTF

Good question.

Creating a gas sales agreement involves several parties, each of which can upset the applecart if they 'leak' information which a competitor can benefit from.

Competitor? Sonatrach - who is also negotiating price/volumes at the same time to extend their supply contract to Morocco. Do we PI's know the terms/price - of course not and never will.

In my experience in these things it is better if all participants keep quiet even on trivial level and its up to PIs to fill in the blanks.

KTF

In simple terms your are right. But there is more to it because both buyer and seller have to carve up the value chain to enable everyone to earn a fair share the rent. To do this both sides must have all the costs available at least to Class 3 (+/- 30%) estimates from well head to burner tip. My guess is the 'delay' is due to delivery of the FEED project costs by Enagas.

For Sound, the main objective is to maximise the netback to the well-head. i.e. what ever value is left once the CPF and export pipeline have taken their share. ONEE will ave a pretty good idea of what they can afford to pay to make a return on power generation.

On this basis both sides can arrive at a sustainable contract durable over many years.

I doubt Sound has the experience/knowledge to develop a sales contract and will rely on a specialist consultancy to finalise the 'boiler plate' - of which there is a lot! See link below.

http://ashokkumarbansal.com/understanding-natural-gas-sales-purchase-contracts-principal-contractual-terms/

Sure, we'll see a 'headline' number on price, but it will be defined by a formula incorporating MAD/$ exchange rate, electricity price index and so on. Also, the challenge for Sound (or whoever develops the gas field) is to ensure the final Class 1 engineering costs (actual tender costs) are as low as possible and wells exceed expectations to increase the netback.

Meanwhile, the hydraulic stimulation of TE-10 should provide us with the true promise of Tendrara as a whole. There are several prospects closer to the TE-5 gas field which justify exploration wells as well as possible TE-10 appraisal. This phase of Sound's work should be the prelude to a company sale. Interesting few months ahead.

DM

TE-2 is located ~30km NE of TE-5, well outside the TE-5 Concession, and also outside the 3D seismic area..

It found 38m of Tagi net gas pay with average porosity of 9.5%. Fastnet reckoned it would have flowed if it had been tested, but the objective at the time was to find oil.

Also penetrated >130m of Carboniferous with no reported shows.

TE-2 was drilled by Agip in 1966.

Boderisimus

I agree completely.

It could imply sale volumes are a function of the production performance of the TE-5 field as a Depletion contract. The RNS suggests ONEE has accepted production build-up, a projected plateau and decline profile based on the Onhym-sponsored CPR and ongoing engineering design. Under this arrangement the production profile may be adjusted as the performance of the field is better understood as time goes by - either more or less gas.

The benefit for Sound is that buyer, ONEE, accepts a large part of the production risk/uncertainty. Just what is required in the unpredictable reservoir like the Tagi.

Not at all.

The 2252 farm out could lead to a firm well and Shell's broadband 3D might reveal all, especially since there are existing wells with gas to calibrate the new seismic. Broadband 3D is enabling technology which opened the Carboniferous play in Q43, but it has not been used yet in Q42.

The attraction of this area is based on geochemical evidence for new, deeper source rock identified by CNRL in wells in their area. This is broadly equivalent to the Dinantian Upper Oil Shale Cemenstones which are found in the Midland Valley of Scotland, which were retorted in 1851 in Bathgate and became the first petroleum 'refinery' in the UK. This explains the origin of condensate in the Breagh gas field, rather dry gas derived from Westphalian coal, commonly regarded as the main source rock for gas.

Also, let's remember the prospective resources in 43/11 were 75% replaced by those in the last round licence awards too.

You'll have to learn to cope with the ambiguity of market valuation vs technical valuation. Rarely do the two coincide except for when the last drop of oil has been extracted from a field.

100% correct - in absolute terms, and same for small companies without reserves/production or cash to explore.

100% wrong - in how the market values small exploration companies.

a1m1

Without money to drill an exploration well Block 43/11 has no value. CNRL told the market weeks ago in some detail.

Since we all knew that, including the deadline of Feb 28th to commit to a well, the market has priced this in to CNRL's overall value. So no material loss and nothing to announce.

Sure - investors tend to compare/contrast oil & gas exploration companies valuations, but it's all a dream. Why? Because without drilling money they're worth zero in absolute terms.

Remember a1m1, finding oil and gas is quite easy, but finding the money to do it is much more difficult.

Move along please, nothing to see here.

Mongolia?

Can you find one for UKCS.

Dickupham

On average about 50 ukCS licences expire or are relinquished every year, and that's been going on for >50 years. That's ~ 2500 such events, and probably many more if part-block relinquishments are included.

If anyone can show an example of a specific RNS announcement by a licencee that one of their licences is expiring or is about to be relinquished I'd be very surprised.

In fact it is very clear CNRL has, if anything, has been far more transparent in reporting compared with many other listed oil & gas companies - especially on AIM.

Scoobydoo5

One form of ‘protest’ to ‘developments’ is direct action. So this is why protesters camp out on the runway at Heathrow to draw attention to their climate change agenda. Yes, it hits the headlines, but it doesn’t stop the project.

Over the past decade, various groups have realised projects they object to are vulnerable to lack of finance. This approach has been very successful for them. For example, the World Bank was compelled to launch The World Commission on Dams, rapidly followed by The Extractive Industries Review (which included oil and gas). It worked because the World Bank is governed by member countries (i.e. politicians) who can be influenced at home in each country.

These things didn’t stop World Bank financing, but rather imposed standards which were far superior to those before. It also ensured big projects were conducted by companies with established governance systems and procedures. In genral, a good result all round.

So what’s this got to do with a1m1? Well, it could be that bulletin boards are a good place to influence and provoke private investors. Rizolino was one of the first to pioneer this approach with CNRL, although he appears to enjoy direct action too, and enjoyed a spell enjoying the comfort and hospitality of one of Her Majesty's establishments. He was ‘outed’ on IGAS bulletin board – see link below.

http://www.lse.co.uk/ShareChat.asp?ShareTicker=IGAS&page=11

LtdAxis

I think we can be sure of dotted i's and crossed 't's'

I noticed Gneiss were involved in completing the Shell deal. They provide exactly the right commercial and legal horsepower needed to make these transactions bullet-proof. CNRL can ill-afford to pay an in-house team of this calibre on standby. Completing the JOA should be a piece of cake.

https://www.gneissenergy.com/gneiss-energy-acts-as-commercial-adviser-to-cluff-on-their-farm-out-to-shell/

For a well commitment to qualify CNRL must demonstrate the money is ‘in the bank’.

See OGA requirements below.

https://www.ogauthority.co.uk/media/5003/financial-guidance-august-2018.pdf

Applamma

A refreshing post - thank you for reminding us where this all started.

Don’t forget Rabbah Bouchta, former DG of ONAREP and then geologist for Lone Star, Maghreb Petroleum and OGIF. With Luca these two had developed encyclopaedic knowledge of the Tendrara area. Rabbah was a consultant to Sound at one point but is also part of the OGIF team. I expect he is still playing an important role in shepherding sound along and guiding them through the Moroccan labyrinth..

Without Rabbah and Luca's insight we have glimpsed the ‘arrogance of ignorance’ - scientifically known as the Dunning-Kruger Effect. It is essentially when you don't know what you don't know in petroleum exploration until it becomes clear a venture like Tendrara, which was portrayed as simple to start with, is much trickier than one first thought. Quite common when a bunch of foreigners show up with no ‘local’ experience or local technical office. I don’t mean this in a derogatory way – it’s just a fact of life and Sound has caught up fast.

Were the challenges of Tendrara’s tight reservoirs already known about before Sound arrived? Yes, of course they were thanks to four decades of drilling in Morocco since the 1960s. Were techniques available to stimulate the reservoir known about? Yes, similar age/lithology reservoirs were stimulated since the early 1980s in Europe in 100s of gas wells.

We'll get there eventually because the geology is favourable, and I agree we owe a lot to Luca and Rabbah for starting this journey.

dickupham

A few points;

First;

The licensing system has changed since 28th Round when CNRL applied under the 'Promote' scheme. Now there is an 'Innovate' scheme which encourages a creative approach which CNRL can develop for the old 2248. Spirit will have to do same on their adjacent expiring licences.

The Innovate Licence replaces several earlier types of Seaward Production Licence: the Traditional, Promote and Frontier types. The Innovate Licence offers greater flexibility in the durations of the Initial and Second Terms (which was the main difference between the older licence types). An applicant for an Innovate licence is able to propose the durations of the Initial and Second Terms, and among the permutations that may be proposed are those that represent those associated with each of the older licence types.

The Initial Term can now be subdivided into up to three phases, with the Work Programme being correspondingly divided:

Phase A is a period for carrying out geotechnical studies and geophysical data reprocessing;
Phase B is a period for undertaking seismic surveys and acquiring other geophysical data; and
Phase C is for drilling.
Phases A and B are optional and depend on the applicant’s plans. Every Work Programme must have at least a Phase C (just as a drilling commitment was the minimum Work Programme before the Innovate concept).

Second;

CNRL elected to allow another 5-block licence to expire a couple of years ago with no loss of value. The reason was that the Gov't 'top leased' the area to the Forewind group to build the Dogger Bank wind farm, but without consulting mineral rights holders. A straightforward energy ministry snafu which prevented petroleum operations and rendered the area worthless for exploration.

Third;

CNRL enjoyed support from Halliburton under an MOU. They conducted some of the work at their cost. Other than small G&A fixed costs + bought-in expertise and CPR work I imagine costs were very low.

Thanks Dickupham

In the normal course of events being operator provides cost/schedule control - you are right. It tends to create 'David and Goliath. operating committee meetings which are quite painful.

Looking at the ‘dynamic’ map of acreage near P2248 at first sight it might seem Spirit Energy is in a strong position to pick up CNRL’s area. But Spirit is unable to drill due to lack of discretionary funds for exploration, despite having some interesting prospects. Meanwhile, Centrica, which controls Spirit via its majority holding, is putting all its effort into servicing old boilers and selling gas via its low-risk subsidiary, British Gas.

Spirit’s partner in this area is Oranje-Nassau Energie, which bought 30% of Sterling Resources share of the Breagh gas field and all their exploration acreage a couple of years ago. Using the ‘Principle of Least Astonishment’ it could be that Shell may approach Spirit/ Oranje-Nassau to explore the Pensacola look-a-like Zechstein reef in Blocks 43/4 and 43/5.Overall, that might add 4 or 5 tcf of prospective resources in a new play fairway in which CNRL has a modest stake via P2252. Speculation on my part - time will tell.

250swb

Yes - you are correct.

Depending on the hydraulic stimulation design ~500 tons of proppant - or maybe more - has to be blended into a slurry with water and injected in about 15 minutes. That's why large, deep perforations are needed. Even 500 tons would be a small job - big jobs on shale-gas fracs use up to 25,000 tons per well!

Presumably, the natural completion flow test will provide the baseline figure from which to compare the effect of stimulation on tight Tagi formations. This operation is being closely watched by the industry because, if successful, it may trigger a rush to licence/drill the Tagi in Morocco - an area where Sound is perfectly positioned and will have all the data.

It's a massive logistical challenge requiring military-style preparation and execution. Expensive? Certainly. But a much better use of funds than an immediate TE-11.

Dickupham

Although it feels like a backward step for some PIs, the expiry of 2248 is not a set-back, but just a normal event in UKCS (and, for that matter, all over the world in petroleum business). Many ukCS licenses expire every year. 2248 didn't expire for lack of technical work, but rather due to timing of drilling in adjacent licences.

The UKCS licensing system is surprisingly dynamic over time. Many blocks have been licenced ten times or more since the 1st Round in the 1960s, even before the median lines were agreed with Norway etc. As private investors our strategic time span is measured in a couple of years or less, whereas the full cycle of application, analysis, exploration drilling, appraisal and development is measured in decades.

Sure, P2248 expires soon and, as we say in the trade, “no lease, no grease”. But there is more to it because of the churn of acreage.

When acreage becomes ‘open’ it may be available in the next licencing round. But, it’s not just CNRL caught in the churn of licences. For example, P1724, which includes Pegasus West in 43/13 reaches the end of its Second Term end-October 2019. Our immediate neighbour in 43/12 with the Andromeda prospect in P2128 expires soon too. One reason the 2248 farm-out failed to attract an investor was ‘cycle time’ – in other words a drill or drop commitment might have extended the 2248 licence, but rapid monetization of a success depends on Pegasus and Andromeda as export routes over which CNRL has no control. Money spent on even a successful well could be stuck in the ground for years with no prospect/control of a return.

Competitors’ strategies change too. For example, Centrica’s grip on Q43 was weakened when it hived off its E&P activities as Spirit Energy, but retained a 69% stake + instruction to concentrate on production and forget exploration. Spirit's only option to retain its exploration acreage is to find a partner.

To put it another way, CNRL can afford to let 2248 expire, go back to the drawing board and develop a powerful case to apply for the ‘old’ 2248 incorporating, say, a much larger area as a single unit. Impossible to accomplish alone, but could be done under a joint bidding agreement with a bigger company with, say, CNRL having a 25% (carried) interest.

Competitors are all in same position, with maps on the office wall showing expiring licences and constantly assessing the next options.

Roybar

Well, it is a discussion board so everyone is entitled to a point of view.

I never doubted the potential of Tendrara since the early days of ONAREP, Agip, Maghreb Petroleum. Lone Star, Fastnet and now Sound. But the tendency has been to drill wells with no convincing predictive model/technique about how to produce the gas from the Tagi.

But now Sound is addressing the fundamental challenge of well completion, rather than continuing to drill non-productive exploration wells. if the test of TE10 works as expected it de-risks numerous other prospects in Tendrara, some of which have already been shown to contain gas by previous exploration wells. Instant contingent resources (and value) beyond TE-10.

Agenda? To see the share price increase based on facts, figures and solid petroleum geology.

Wanger18

i rather liked you first post.

Maybe I was wrong to include the article about ‘shale gas fracking’ yesterday - it has caused some confusion. Let’s just stick to 'hydraulic stimulation' in future. Sorry about that.

On the ‘big guns’ discussion the objective is to make ‘big holes’ in the formation, but as a prelude to hydraulic stimulation. This is because huge amounts of proppant and water must quickly enter the gas-bearing reservoir the instant the fracture pressure – known in the trade as the ‘break pressure’ - is exceeded down-hole. After the ‘break’ the fractures propagate over a period of minutes the pumps work at full power to move the proppant into place to keep the fractures open. The holes made in the formation by the ‘big guns’ are actually ‘tuned’ in size to let this happen. In the European Rotliegendes Sandstone a higher injection rate generally leads to higher gas production.

All I was trying to say yesterday is that the phrase 'hydraulic stimulation' has released 10's of TCF of gas from the Permo-Triassic, Tagi equivalent play of the Rotliegendes Sandstone all the way from the Southern North Sea to Germany and Poland. There are literally 100s of gas wells in this basin which are commercial based on hydraulic stimulation and years of experience in a reservoir which is similar in many respects to the Tagi in Tendrara. The approach to testing TE-10 is tried and tested in analogue pre-salt gas fields elsewhere. And it's a 'first' in a vertical Tagi well in Morocco.

Why is this so important for Sound? Well, it several of the pre-Sound, pre-TE-5 Tagi wells in Tendrara found gas, but failed to flow when tested or were just P&A with gas shows. Fastnet almost got to the same point as Sound before they left. But if the current test scheme does work it justifies follow-up wells to appraise the TE-10 discovery with two or three more wells quickly as part of the LE process. By extension, if successful, it also supports the case for BM's big tcfs under his belt.

The result of the forthcoming testing programme of TE-10 is therefore transformational for all involved because it could be the key to releasing the gas which is obviously there. Sound may wish to keep this to themselves for now because the Tagi completion technology may transform the value of Tendrara (- and share price!) in one simple move.