Member Info for Exploration

Audible.

Facts and figures; daily production;

You can make a back of envelope estimate based on a few assumptions such as using TE6 and 7 as producers.

10 mmscfd produces 125,000 gallons of LNG per day via a cryogenic distillation plant which also knocks out the CO2 from the wellstream. That needs ~10 road tankers per day assuming 14,000 gallons/tanker as a continuous operation. The trucks would be fueled by LNG which is a fairly simple conversion to a regular diesel engine.

Assuming the LNG is used to generate power at the delivery point, the gross revenue would be ~$75 million/year for the power at 100% utilization at Morocco power prices. Assuming a 50/50 split between fuel/generator that’s $35 million per year to Sound/Schlumberger les royalty, operating costs etc.

Micro-LNG scale is limited by road transport capacity, so 10 to 20 mmscfd is an operational limit before a pipeline becomes a better commercial proposition.

Thanks Crude - if you mean I'm not gullible, examine evidence critically and avoid having the wool pulled over my eyes, then I take it as a compliment. The new management really has to demonstrate their commitment to good governance by providing an independent assessment of the prospective resources in Tendrara and Sidi Moktar.

FD - CLNR’s reason for the write-off is described in the notes on their accounting policies in the 2018 Annual Report. Looks like they’d capitalised investment in P2248 and when it ceased to exist they had no choice but to write it off.

Incidentally, here is a link to OGA’s marking system for new applications. Applicants complete a computerised spreadsheet which spits out the scores for each block applied for. Then there is some jiggery pokery resulting in offers to applicants. Sometimes OGA creates ‘forced marriages’ if there is a tie.

https://www.ogauthority.co.uk/media/3974/marks-scheme-reference-sheet.pdf

Hello ddboy, I do miss the comedy show acted out by Parsnips and his lads - but the geology has not changed and the gas is still there. On the other hand they did prove the Tagi reservoir in Tendrara is probably regionally unproductive apart from the TE-5 and SBK areas, although this had been recognized for years. So the new team is doing what should have been done early on by aiming for a revenue stream with early gas via micro-LNG followed by the full field development and pipeline.

But to have any credibility Sound really needs a CPR for its properties. Otherwise the new Board could fall into the trap of misrepresentation, either negligent or innocent. The new chairman has told us corporate governance is a high priority with adherence to the QCA Code. On the other hand he has told us there are 50 prospects, leads and ‘concepts’ with ‘exploration potential’ of 20 tcf. No doubt this would boil down to Prospective Resources of between 1 and 4 tcf in a CPR taking risk into account.

FD

There have been no changes to UKCS fiscal terms for some time apart from the industry ‘levy’ which pays for OGA so I think we can rule out BOGOF!

UKCS licenses are awarded by scoring applicant’s work programmes. The problem facing CLNR on the old P2248 is that they were actively promoting an exploration well on block 43/11 in the failed farm-out - which implies it is still ‘drill-ready’ and therefore they should include a firm well in an application which would score a knock-out 50 points. Such an application would only qualify at OGA if CLNR can demonstrate financial capability and capacity to pay for a well i.e. cash in the bank - which they can’t.

So what to do? Since any gas exports from a discovery would go via the Cygnus system it would make sense to apply jointly with the licencees of the adjacent, undeveloped Andromeda (43/12) and Pegasus (43/13) discoveries who do have financial capability/capacity.

Like other shareholders, I’d like to see some wells drilled on CLNR’s acreage after >5 years of waiting - and so would OGA.

http://pd.gov.sl/wp-content/uploads/2020/04/AWARD-OF-OFFSHORE-PETROLEUM-CONCESSIONS.pdf

Woodrow

I expect the new team will provide us with an integrated project plan for the micro-LNG scheme in due course. Let’s remember its an interim solution to generate early revenue while the full field development is being organized. It will enhance the overall commercial return and provide long-term well performance data from TE-6 and TE-7.

No GSA is needed for the micro-LNG project and besides, they can’t sign the GSA until finance for the full field development is in place and the pipeline goes ahead

Ps200306

The Oxford report applies to large scale LNG with exports from an ocean terminal.

In contrast, Sound will use a small plant which arrives ready to use by road. There is negligible Capex - suppliers provide the equipment on a lease paid for from the revenue stream. It’s scalable and simple.

http://www.rekasinergi.com/global/en/markets/oil-gas/midstream/lngo-micro-scale-lng-production-system.html

God himself

BP’s shale disaster.

https://www.bp.com/en/global/corporate/investors/investor-presentations/bp-acquisition-of-bhp-us-onshore-assets.html

Some science -

https://www.imperial.ac.uk/media/imperial-college/medicine/sph/ide/gida-fellowships/Imperial-College-COVID19-NPI-modelling-16-03-2020.pdf

xxViperxx

Viper - so how do you explain maintenance of dividend when low oil prices mean BP can only generate break even returns?

You’ll be lucky to get anything at all when 1Q and 2Q results appear. Please refer to the famous quote by Sir Richard Mottram to describe the state we’re in.

The majors, independents and small companies have relied on the OPEC cartel for 40 years to prop up prices generate super-normal profits. But the demise of the petro-states means it’s all over and the autocratic regimes which control them will no longer be able to pay off their citizenry.

Well done Mr Putin.

Gunner101

With greatly reduced revenue due to low price there will be insufficient cash just to complete existing projects, let alone pay shareholders a dividend.

Worse still is the huge exposure to shale in Lower 48, fancy new office in Denver and over-investment in onshore USA which wipes out decades of value created in conventional projects. Looks to me like BP’s strategists were hoodwinked by their own hype and should abandon the shale projects which are clearly ‘disadvantaged’. At the time of the BHP deal they said.

“We will add more than 4 billion barrels of high quality resources. Resources that can be developed with an IRR of greater than 20% at prices of $55 per barrel WTI and $2.75 Henry Hub”

Perhaps a good opportunity to accelerate the carbon neutral strategy and dump L48 onshore?

FD

No real knowledge is needed, just curiosity about how it all works.

National Grid runs the ‘NTS’ or National Transmission System right up to the high pressure gas main in your area, where British Gas takes over low-pressure distribution to your house.

Every day, month and year National Grid assesses the ‘Prevailing ?View’ - how much gas the country needs - and producers or pipeline suppliers from Norway, Russia, Europe sell their gas in specific trades via the ‘National Balancing Point’ or NBP. The buying gas traders in UK then buy their gas at Day-Ahead, Month-Ahead or even Year Ahead prices. They all sign up to what is known as the ‘Network Code’ - which defines the rules for buyers and sellers.

If a buyer cannot fulfill their side of a trade or a seller cannot deliver, the NBP ‘balances’ the trade and the end of each ‘gas day’ with a cash adjustment one way or the other. Same happens at other gas hubs throughout Europe and also USA, where prices refer to the ‘Henry Hub’ which is actually in Louisiana and a reference point for US natural gas prices recorded by tracking gas trades on NYMEX - same principle as NBP.

You can see how US gas producers flooded their market and the gas prices tumbled from ~ $8/mcf to less than $2/mcf today.

https://www.macrotrends.net/2478/natural-gas-prices-historical-chart

So for Shell/Cluff the name of the game is to discover, develop and ship gas via existing facilities to a shore terminal when it is needed by NTS, according to the Prevailing View created by National Grid - in other words, keep the whole system in balance.

The NBP concept spawned the proliferation of private gas-trading domestic suppliers who constantly buy and sell at wafer-thin margins depending on their own forecast of weather etc. Some go bust because they can’t balance their trades or, more likely, because their billing systems/meter readings fail to bring in enough revenue.

Patrm

No profit due to low oil price means reduced dividend - unless big projects are delayed or abandoned.

A classic lobster share.

Here’s the NBP gas price from National Grid. It correlates more with weather than oil price.

Since the European Gas Hubs were built, gas prices have de-linked contractually from oil prices.

So if anyone has a 30 year forward weather forecast for UK, please let us know. But seriously the trend is clearly warmer and most UKCS gas producer/explorers tune their commercial analyses to cope with ‘cold’ or ‘warm’ forecasts over duration of projects.

http://mip-prod-web.azurewebsites.net/PrevailingViewGraph/ViewReport?prevailingViewGraph=ActualPriceGraph&gasDate=2020-03-09

FD - more relevant is the weather.

NBP spot gas price is 20p/therm today. Compare this with 80p/therm at same time 2 years ago. But nothing to do with oil price, but rather the ‘Beast from the East’ cold snap.

Skier - this is global politics at its best, all driven by Mr Putin because Moscow can drive a hard bargain if it wants.

Its diverse economy and flexible currency can now better absorb the blow of a tepid oil market and can handle prices as low as $25/bbl if required, even if OPEC members and Russian citizens suffer.

A bigger concern for Moscow, and its major producer Rosneft, is the potential loss of market share to the USA. Why? With the world’s largest economy, the USA has now leapfrogged Russia to become the biggest producer of crude when prices are > $50/bbl. And the lower the price, the more oil is consumed - despite Greta & co.

Maldini

See pages 17 and 18 for logs and core photo published by Petromaroc - link below.

Petromaroc suspended the well without testing and got into an almighty row with Onhym and Maghreb (aka Ogif) which resulted in Onhym terminating their involvement and substituting Sound. The post-salt Argovian strata is a muddy sandstone and an ****e reservoir. I’m afraid it was all Parsnip’s hype again - with our money.

In the RNS you mention they said they flared some gas, but there was no rate. Sound also claimed they were going to conduct a long-term test - but they never did, and probably knew it would barely flow anyway.

Of course Koba-1 had already been discovered years before by Onarep and failed to flow, although it was known as the Kerchoula ‘discovery’.

https://www.scribd.com/document/230244087/Unlocking-the-hydrocarbon-promise-of-Morocco

Thanks Maldini

There has been 50 years of ‘faffing around’ by Onhym and their predecessors in the Meskala area. Numerous wells were drilled based on surface geology but it wasn’t until 1980 that MKL-101 found gas in the Tagi. A World Bank sponsored effort was undertaken by ONAREP to commercialise the field including 3D seismic, a processing plant and a (now corroded) pipeline to a phosphate mine to dry the phosphate ore using gas heaters.

Meskala recoverable reserves are between 14 and 42 bcf.

Then ONAREP started a disasterous campaign of development drilling only to find 4 out of 10 wells were productive because the Tagi reservoir is plugged by halite - similar to Tendrara.

ONHYM’s ITT requires abandonment of existing wells. Some of these are leaking to the surface behind casing due to poor cement jobs. The ITT states Onhym will provide a rig and consumables. They have two rigs: an Ideco H525 and H1700 - neither of which has been operational for more than a decade. The H1700 is stacked at Meskala.

Here’s the history;

In 1975: TKM-201 well reached the Devonian and has show the presence of Devonian shales for which thermal maturity indicates potential hydrocarbon preservation and therefore this open up a new zone for subsalt petroleum exploration.

In 1977, Meskala (MKL-1) exploration well of Jurassic anticline structure reach the Devonian and has shown gas in Triassic and Paleozoic.

In 1980, MKL-101 well : first gas condensate (GOR=3000) in Triassic sandstone.

Regarding Sound’s Sidi Moktar area, I’m afraid its pretty unprosprective in the Tagi and unless Sound can complete their new seismic by August (impossible) then they’ll lose the licence, at least in theory - but no doubt Onhym will extend it.

Here’s the old Longreach presentation including Sidi Moktar

https://no0ilcanarias.files.wordpress.com/2013/01/longreach_investor_presentation_10-01-2013.pdf

Thanks Pontcanna. I’d missed that earlier post.