Member Info for ZENGAS

Nigeria Slams $10bn Fine On Binance, Blames FX Crisis On Crypto Trading

https://leadership.ng/nigeria-slams-10bn-fine-on-binance-blames-fx-crisis-on-crypto-trading/

Binance drops Nigerian naira from P2P platform, gov't demands $10B compensation

The removal of the naira by Binance from its P2P market comes amid claims by Nigerian authorities that the platform contributed to its devaluation.

Binance is under increased scrutiny in Nigeria as the Central Bank of Nigeria (CBN) expressed concerns about “suspicious flows” of funds through Binance Nigeria in 2023. CBN head Olayemi Cardoso highlighted that $26 billion had passed through Nigeria via Binance in 2023 from unidentified sources and users.

There are also reports that the National Security Adviser’s office has detained two senior Binance officials in Abuja

https://cointelegraph.com/news/binance-drops-naira-government-scrutiny

Our small initial Statfjord Ost and Sygna acquisition came from Inpex.

Approx 300 boepd and with the new wells all on streanm this quarter should be circa 600 boepd.

Cost $12.75m or $8.20 per boe giving 1.55 mmboe 2P.

Effective date was 1/1/23

------------------------

We have $100m JAPEX financing available and the board has said they could double this to $200m with RBL. Imo it's not impossible for the LBE JV to do a 30 - 40 mmboe P2 asset purchase with a starting base of 10-14,000 boepd initial production which could climb by 20-25% in the following year for $140-$220m effective date price and a significant income stream including a short payback time from the effective date and the ability to utilise a full 5 year term and go again for more assets possibly within 24 months again .

By comparrison for $220m and all this cash wasn't needed in view of the effective date also being 1/1/23.

Okea bought their 4 interests (not long after LBE )n Statford, Statford Ost, Statford Nord and Sygna for $220m giving 13-15,000 boepd, 41 mmboe 2P, 8mmboe 2C and upside of another 14 mmboe.

Production in 2024 this year estimated to be 16-20,000 boepd (though likely reduced by 10% this year.

This was transacted at an initial cost of $5.36 per boe 2P.

However this would expand to a profit share on bls sold between $75-$96 in 2023, $64 - $85 in 2024 and $53 - $72/b in 2025 where Equinor get 90% of the profit in those ranges after tax and effectively increasing the 2P per barrel cost.

==============================

From Okea - Reference

Acquisition of 28% WI in PL037 from Equinor, comprising 23.93123% WI in Statfjord Unit, 28% WI in Statfjord Nord, 14% WI in Statfjord Øst Unit and 15.4% WI in Sygna Unit.

Effective date 1 January 2023

Initial fixed consideration of USD 220 million including tax balances of approximately NOK 300 million

Net 2P reserves of 41 mmboe and net 2C resources of 8 mmboe. Additional upside volume potential estimated to net 14 mmboe,

Adds production in 2023 of 13,000 – 15,000 boepd and expected to grow to 16,000 – 20,000 boepd in 2024.

In addition to the fixed consideration, the agreement contains a contingent consideration structure based on profit sharing on crude oil volumes sold at a realised price of

75–96 USD/bbl in 2023,

64–85 USD/bbl in 2024, and

53–72 USD/bbl in 2025, as well as on dry gas volumes sold at a realised price of 170-341 p/th in 2023, 125–248 p/th in 2024, and 37–75 p/th in 2025.

The profit sharing within these limits is 90% after tax to Equinor and 10% to OKEA

RR

I posted the below post exactly 10 months ago when some were saying they should pull out of the deal then. That time period should have shaved a further $300m imo off the settlement figure not counting the original effective start date. What is any different now in the last 10 months that imo would not have been considered after all this time since.

Why would Save imo suddendly flip flop now so unprofessionally at any sudden blip especially when they've continued this far into an 11 month neighbouring war and pull out when repairs/maintenance could be resolved at any time as well as significant efforts being made to resolve the war. As i said in the below post, i'd be absolutely surprised if they had not factored in the potential for exports being offline for 3-6-12 months at any point in the risk mitigation.

ZENGAS - 01 May 2023 -

Re should or shouldn't SAVE walk away from the S.Sudan deal.

That depends how you look at it.

First of all i believe any deal has to be non recourse to the parent group/other asset holdings just like Chad, Cameroon and Accugas Nigeria. Therefore i don't see it as putting the group at risk and no one would be that reckless least of all AK without ring-fenced financing.

If anyone is likely to pull the deal it could be the actual entity that is/was there to finance it and not so much Save.

It could be Petronas themselves who finance it - do or will they offer a financing agreement like Exxon and on what terms. They may be even keener to leave more than ever now especially as they also operate in Sudan where their complex/office in Sudan has been damaged in recent days with people unable to leave.

Any opportunist will see the potential in S.Sudan. Perenco themselves were reported as interested. Things continue as normal so far and the main worry is going to be relying on one export route - so yes i see now as the time for S.Sudan to address and develop an alternative route faster than ever. They have land bought at Djibouti for this purpose.

Can any deal be structured in a way that Save can continue say if oil exports were offline for 3-6-12 months at any point ? and it might not happen - totally unknown but i'm sure that risk has been considered.

AI reports Save will predominantly only be a partner in S.Sudan - they won't have too many to pay as they need little staff, it all comes down to the loan financing and perhaps length of it. Seplat managed to survive in a one country jurisdiction with its oil exports severely constrained for a number of times over many months while alternatives were found and the original export route re-instated.

What about the breaking story back on 18/1/22 when AI reported that it was a grand plan by the Vitol - Savannah duo for S.Sudan. Vitol is awash with serious cash and more so this past few years of high oil prices, and somebody like them could be more than willing to see this through with Save as they gain access to marketing the oil.

I may be wrong but to leave S.Sudan high and dry because of what's going on with it's neighbour would be a big blow for the South Sudanese (not their fault) and anyone thinking of investing in S.Sudan pre June if the Savannah Petronas deal collapsed - so again i'd be surprised if Save decided to pull the deal on neighbouring instability. Yes they could delay it or suspend it but i think that would open the deal to other potential buyers.

I do not want to see the deal collapse and i don't think Save will either but it will be more so in the hands of the right financing terms relative to the above.'

To follow on from the previous post -

Finally and a crucial point - is the very low CO2 potential at LBEs Kertang which they have highlighted for a reason (Take this in context of Kasawari costs and very high CO2 for getting shot of it (see above) which amounts to near 40% of the gas)

From the LBE presentation again -

* Kertang approx 8-10 TCF (CPR 2019), giant size prospect, updated CPR underway to reflect more technical work, over 200 sq km in areal extent at MMU closure

* Gas clouds very evident (& similar to Kasawari gas cloud), amplitude brights at multiple levels

* Geochemical analysis of sea floor sediments over prospect shows high Methane concentrations & very low CO2 (Fugro 2019)

-----------------------

So with Rystads Energy $3.50 - $5 mcf break-even for Kasawari - that's $21 - $30 per boe break-even (see article above).

My estimate is a $3 per boe valuation to LBE. With a potential 9 TCF recoverable that's 1.5 billion boe.

Retaining 15 - 20% on farm out is some 225 - 300 mmboe or $675m/£500m - $900m/£700m potential target value divided by the current 57m shares or expanded out to 100m re share price potential from Kertang alone - yet has potentially 50% more gas upside from at least 2 other prospects with further 'multiple large prospects' all compared to £14m m/cap now (24p).

This to me is imo more than underpinned by the Norwegian growing production, existing undeveloped discoveries and $100m available financing from Japex for further Norwegian production assets which should trigger further share price growth. Imo/dyor as ever.

If anyone hasn't studied the latest Block 2A presentation - the Kertang 9 tcf mid case recoverable prospect is described as an undrilled giant and on slide 5 it is compared as analogous to Lang Lebah 5 TCF and Kasawari 6TCF. LBE include the reference to Lang Lebah - "Unravelling an abandoned giant" by Aquilah (Amir Jamalullail and others- The leading edge 2020)

https://longboatenergy.com/wp-content/uploads/2024/01/Malaysia-license-SK2A-extract-from-EAGE-presentation-January-2024.pdf

Yet in that article, Lang Lebah lay dormant for 25 years after initial drilling and it was only in 2016 that new 3D seismic and reprocessing was carried out and a new well drilled that made Lang Lebah one of the largest gas discoveries of 2019

https://www.researchgate.net/publication/343411866_Unravelling_an_abandoned_giant_in_Central_Luconia_Province_offshore_Sarawak_Malaysia_-_Success_story_of_Lang_Lebah

"Lang Lebah, located in block SK410B in the South China Sea, is one of the biggest gas discoveries off the Malaysian coast.

The Lang Lebah field is estimated to hold five trillion cubic feet (Tcf) of gas in place.

The field was discovered by the Lang Lebah-1RDR2 exploration well, drilled in March 2019 to a total depth of 3,810m. The discovery well encountered 252m of net gas pay in the Middle Miocene carbonate reservoir.

The Lang Lebah-2 appraisal well, drilled in January 2021, confirmed Lang Lebah as one of the biggest gas discoveries in the region. Drilled to a total depth of 4,320m, the appraisal well encountered more than 600m of proven net gas pay in the carbonate reservoir. The well test demonstrated a flow rate of 50 million cubic feet (Mcf) of non-associated gas a day. The Lang Lebah field is expected to come on stream in 2027 and will produce up to one billion cubic feet (Bcf) of gas per day." (165,000 boepd)

https://www.offshore-technology.com/projects/lang-lebah-field-development-sk410b-malaysia/?cf-view

Kasawari - "Discovered in 2011 offshore the Malaysian state of Sarawak, the Kasawari sour gas field is today a symbol of Southeast Asia’s energy challenge.

Petronas is eyeing next year for first gas. By 2025 it hopes to see 900 MMscf/D (150,000 boepd) flowing from the field to its sprawling Bintulu LNG export facility on the Sarawak coast.

The scale of Kasawari, found at a water depth of about 108 m (350 ft), is a result of its ranking as one of the most CO2-laden gas fields planned for development globally. When wells are flowing, it’s expected that up to 40% of what will come out will be CO2.

New research from Rystad Energy suggests that the capital inputs required to add CCS to Kasawari will hike the project’s breakeven gas prices from roughly $3.50/Mcf to more than $5.00/Mcf. "

https://jpt.spe.org/what-you-should-know-about-offshore-and-sour-gas-ccs-high-cost-leak-mitigation-and-transportation

Nothing to do with leaks imo but the fact of the assets it has added as well as the super deal with Japex in Norway and that investors are waking up to it. It is and was very oversold plus the the low available free float which i highlighted.

The M/cap at 25p is £14m m/cap and is a producer on it's existing assets which will soon have paid for itself as well as expecting to double production on those.

It has $100m of available Japex funding for acquisitions in Norway. Use some of that for Norwegian production acquisitions (expected) and will further transform the company.

It has also underestimated play opening discoveries in Norway with major partners.

It has a world class exploration block off Sarawak with multiple large prospects.

The block has 6,000 km2 3D seismic which would cost a fortune to replicate and at least $20m - or more than the current m/cap.

Kertang is a world class 1.5 billion boe recoverable estimate (9 TCF) drill ready prospect DHIs, gas cloud, significant methane measurements.

Two smaller adjacent prospects about half the size each may add 6 TCF to this so imo a target potential of 15 TCF.

Those 3 are covered by 2900 km2 3D.

Farming down from 52.5% to 15-20 % could yield $ 1billion of value.

57m now or expanded to 100m shares at £4 = £400m/$500m

With still further structures.

Also intending to pick up producing assets in that region seperate to Norway.

By comparrison - Upland (UPL) in the same Malaysian region, no production, financial backing, no 3D and unknown stake in a PSC block not even awarded yet, no recoverable estimates and nothing else of value on 1.2 billion shares and todays share price of 3.3p (recently 4 and 5p) = £40m m/cap and nothing else to underpin an entry price.

Fair starting value for LBE would and should be 40p which is only £22.5m and on the above looking for north of 100p from Norway in growth (ie barely £60m) and a potential future target as above of value on a success case on Kertang detailed above.

F/book 1 hour ago reporting on an interview with the minister of information saying the 23-24 budget will not be met as oil production reduced, gelling in 2 pipeline stations and difficulty getting oil out from port sudan due to the attacks on shipping in the red sea.

They intend to strengthten the non oil sector for the economy. Saying that we don't know what the actual oil production numbers are, they could be down as little as 10-20k but which still makes a huge difference to meeting their budget. One would think the government wouldn't be in the position for buying up oil assets.

Also this article on the challenges for S.Sudan via the red sea/houthi attcks on shipping.

https://bnnbreaking.com/world/yemen/south-sudan-oil-exports-hit-by-yemeni-houthi-attacks-amid-sudan-conflict

For 2022. The average gas price was $3.69 mcf spread across 8 contracts for 2022.

Revenue was $212.5m ($181.1m for gas, $29.8m for oil and condensate and another $1.6m for handling 3rd party oil).

If we were doing 200-220 mmcf/d consistently it would be $270m - $300m plus another $30m+ oil from S.Creek.

So to run consistently at 200 - 220 mmcf/d at present capacity or when the compression project completes it could generate an additional $90m - $110m revenue with most of the fixed costs already taken for. That size revenue would be a game changer as would the debottling of S.Creek oil that practically double capacity/sales.

Trust as i see it we're buying 3rd party gas so we should be doubling on the purchase price i would think given what Save sells the Uquo gas to Accugas for. I don't think there'll be any valueing 3rd party gas reserves as we don't own them but yep there should be a value given to the sales portion and certainly a good growth market for 3rd party suppliers such as Amocon.

We have 200 mmcf/d processing and rising to 220 mmcf/d with the compression project - maybe a bit more but surely the emphasis is on safety.

The pipeline capacity is up to 600 mmcf/d so around 400 mmcf/d spare depending where the gas goes in.

Noix, They do total that, but the ones over and above the 3 originals are for 'an up to amount' which i don't beleive is fullfilled consistently at that rate. They are also buying in up to 20 mmcf/d gas from Amocon.

"Gas supplied from Amocon does not require processing by Accugas and therefore does not utilise available capacity at the Uquo CPF" = 31/5/23 RNS

Trust sorry just seen your question

The 2 trains do 100 mmcf/d ie 200 mmcf/d total design capacity.

One was run at 110-120 on test from memory.

They are both being upgraded to 110 mmcf/d each according to the section in the annual report which gives more detail re pressure etc.

So they should be safely capable of doing 220 mmcf/d instead of the name plate 200 mmcf/d.

I'd need to understand or see the pressure rating explained to fully understand why the increased pressure is needed ?

They can add a modular bolt-on processing train when needed is my understanding so could lift production further when demand/contracts are there.

Dangote Refinery can meet 100% of Nigeria’s demand for refined petroleum products and has a surplus for exports.

The Refinery can also help the naira appreciate against the dollar in a number of ways.

Increased production and export of refined petroleum products can generate foreign exchange earnings for the country, thereby increasing the supply of dollars in the foreign exchange market.

Despite the risks involved in daily operations, the refinery could be a game changer for Nigeria’s economy and currency with proper management and support from the government and stakeholders.

The refinery, which has a capacity of 650,000 barrels per day, is expected to meet 100% of Nigeria’s demand for refined petroleum products and have a surplus for export.

The refinery is also expected to create thousands of jobs, boost fuel supplies across Africa, and generate foreign exchange earnings for Nigeria by exporting 40% of its products.

The refinery is seen as a game-changer for Nigeria’s economy and the downstream petroleum products market in the entire African region.

This is a huge achievement for Nigeria, as it will reduce its dependence on fuel imports and save foreign exchange.

Nigeria’s significant expenditure on fuel imports puts pressure on the demand for foreign currency, particularly the dollar.

By reducing or eliminating the need for fuel imports through the Dangote Refinery’s production, it would reduce the demand for dollars in the importation of fuel. This decreased demand for foreign currency can help strengthen the naira against the dollar.

By exporting excess refined products to other countries, especially in Africa, the refinery will earn foreign exchange for Nigeria and increase its reserves. Increased dollar supply can help stabilize or strengthen the naira, boost the confidence of investors, and strengthen the naira’s value.

As the Dangote Refinery produces more fuel domestically, it would reduce Nigeria’s dependence on imported fuel and conserve foreign exchange reserves.

Higher foreign exchange reserves provide stability and confidence in the currency, which can positively impact the exchange rate. Nigeria’s external reserves are around $35 billion, representing 6 months of imports only.

The opportunity cost of subsidizing petroleum products, which includes loss of export revenue, will be gained thus boosting external reserves.

This decreased dependence on imports can help mitigate the impact of imported inflation, as the prices of locally produced petroleum products would be less influenced by global market dynamics.

Additionally, by eliminating the costs associated with importation, such as shipping, customs duties, and other related expenses, the overall cost of fuel consumption for Nigerians could potentially decrease.

https://nairametrics.com/2023/05/23/how-dangote-refinery-can-strengthen-the-exchange-rate/

Huge news considering Nigeria spends $30b on fuel imports and should greatly improve the dollar liquidity.

Exclusive: Nigeria's new Dangote refinery to export first fuel cargoes

LONDON/BRUSSELS, Feb 15 (Reuters) - Nigeria's Dangote oil refinery has issued tenders to sell two fuel cargoes for export, the first from the newly commissioned refinery, a tender document showed and trading sources with knowledge of the matter told Reuters.

Nigeria has for years relied on expensive imports for nearly all the fuel it consumes but the $20 billion refinery is set to turn it into a net exporter of fuel to other West African countries, in a huge potential shift of power and profit dynamics in the industry.

Dangote declined a Reuters request for comment.

The first cargo is 65,000 metric tons of low-sulphur straight run fuel oil, which Dangote has awarded to Trafigura and is due to load at the end of February, three of the sources said. Trafigura declined to comment.

At least one refiner said they had been offered the cargo by Trafigura without elaborating further.

The second tender is for about 60,000 tons of naphtha loading on Feb. 23-29, a tender document seen by Reuters showed. The deadline for submissions of bids closed on Thursday afternoon, a trader who participated in the tender told Reuters.

Sources told Reuters last week that the refinery was preparing to deliver its first fuel cargoes to the domestic market within weeks.

https://www.reuters.com/business/energy/nigerias-dangote-refinery-export-first-fuel-cargoes-2024-02-14/

Okea AS went ahead and completed their acquisition from Equinor in the Statfjord Unit as well as Statfjord Ost, Nord and Sygna.

'The Statfjord Area comprises the Statfjord Unit, Statfjord Øst Unit, Statfjord Nord and Sygna Unit. The Statfjord Unit development covers the Statfjord A, B and C concrete gravity-based platforms. The other fields are subsea developments tied back to the main field platforms.

Statfjord Area is one of the largest fields on the NCS in terms of initial oil in place which was in excess of 6 billion barrels. Statfjord A was put on production in 1979, followed by Statfjord B in 1982 and Statfjord C in 1985. The field is operated by Equinor and the Field Life extension (FLX) unit was established in 2020 with an ambition to deliver 200% increase in remaining reserves, 25% cost reduction and 50% CO2 reduction in the Statfjord Area by 2030. The FLX unit focuses on safe operations, improving recovery from the field as well as reducing costs and CO2 emissions and has a strong track record of deliveries in recent years.'

As LBE partners Equinor, VAR, DNO etc most of the existing discoveries made are close to existing facilities and some of those at the lower end of the threshold may yet come on to the development stage or swap in the future, but that is where all these companies have a major focus similar to the details in the Equinor transcript.

Kjetil Hove Equinor ASA - EVP of Exploration & Production Norway

In addition to the large sanctioned project portfolio, we have an even larger number of non-sanctioned projects. We have more than 30 projects that we are maturing towards investment decisions in the coming years. The projects are in an early maturation phase, but we expect an average breakeven of the portfolio of around $35 per barrel and a payback time of around 1.5 years. For many of the new subsea tieback fields, we are looking into new ways of working to reduce the maturation and execution time with 50% and the cost level of at least 30%.

This will reduce the breakeven from these fields with 30% compared to a more standard subsea development. And this will be done through new technologies such as the Cap-X subsea wells and by taking out portfolio synergies. These projects will give us around 350,000 barrels in production after 2030

In addition to the large sanctioned and non-sanctioned project portfolio, we are working hard to increase the recovery factor from our fields. Historically, we have been, since sanctioning, been able to increase the average recovery factor from around 30% to around 50% from our oil fields. And there is still a large remaining potential in our fields, and we plan to deliver 50 to 70 increased recovery wells annually in this decade.

Many of these wells are using new technologies such as retrofit multilateral wells, multi-stage fracking and advanced completion solutions, reducing the cost and increasing the production. And these are highly profitable barrels with a breakeven of around $20 per barrel and a payback time less than a year.

We're also planning for around 300 interventions annually to increase production from our existing wells. And in addition, for many of our late life assets, we are planning to sanction low-pressure projects to reduce the reservoir pressure and thereby increasing the recovery from our fields. This increased recovery effort will give us an annual production of around 150,000 towards 2035

Our exploration strategy is that around 80% of the exploration wells will be drilled close to the infrastructure in known exploration plays. This is normally low-risk exploration with high probability of success. And new discoveries can be put on stream quickly since they will require limited new infrastructure.

The remaining 20% of the exploration wells will be drilled in new plays, still quite close to our infrastructure. These are higher potential wells but with somewhat higher risk than the pure infrastructure-led exploration targets. These wells can open new plays also in known areas such as the Kveikje, Heisenberg and Norma discoveries during the last years. Discoveries that you may not have heard about, but you should not underestimate them because there are many of them, and these could open new plays with large potential on the NCS.

RR once the R3 project was sanctioned for development and close proximity especially to the pipeline just 30 km away, those 2C should be reclassified as 2P and be worth at least $120-$140m ($4/barrel) imo as they are new long life production compared to mid-life/mature assets.

Phase 1 initial production to 1.5k bopd then phase 2 with inter field flowlines and moving to 5k bopd. Personally hoping that with the upside potential in deeper levels and pressure communication on one of the bigger fields (Amdigh) it may double those reserves at little cost (but wait and see approach).

146 prospects/targets identified so yes i believe 2.8 billion bl recoverable estimate. I think they'll only every drill a fraction but if they can get to 3-400 mmbls reserves with production/pipeline access then they should be worth $1b+ particularly when we're paying $1250m for some 300 mmbls supposed reserves in S.Sudan thats mid-late life. Niger pipeline is to expand to 300k bopd with pumping stations. No reason why we can't get to 300 mbls reserves alone from the low hanging fruit at 75% COS on the Sokor alternances.

Trust - the compression project was to increase the gas export pressure to a maximum 81 bar and deliver 110 mmcf/d per train (x 2) if i've read it right. A $45m capex project with completion later this year.

Updated 3:50 PM GMT, February 24, 2024

ABUJA, Nigeria (AP) — West Africa’s regional bloc known as ECOWAS has lifted travel, commercial and economic sanctions imposed on Niger that were aimed at reversing the coup staged in the country last year, a senior official announced Saturday.

https://apnews.com/article/west-africa-ecowas-niger-mali-burkina-faso-abuja-ae53abf8464dce5487cd7a3d73e0a9c0

Mommur

"perhaps after 5 years the major shareholdrers here feel the same"

To be factual -

LBE listed in November 2019 with only 10m shares just slightly over 4 years ago. (4 yrs/3 mnths).

58.% (5.8m) was held by instituitions and mangement had 8.3% (830k) leaving 33% or 3.3m free float shares.

The main fundraising of 45m shares at 75p came just 2.5 years ago in June 2021 which would be 4 in 5 of the current shareholders so i don't think you could describe them as - "perhaps after 5 years the major shareholdrers here feel the same" - any more than the share price swings as in Serica.

This is supported by 46% held by institutions with 26.3m, Directors & related parties on 3.22m at 5.7% with a free float of 27m of the total 57m shares in issue.

Regardless of the share price in that time, i think they've done fairly well with the opening discoveries to date. Followed all in the last 9 months by attracting a JV venture partner in Japex (with $100m of funding available that can attract a doubling to $200m in RBL for assets), adding the initial production assets and opening up with a significant asset with over $20m spend on it in Malaysia that on it's own could offer $1b of value on a success case given the multiple prospects, DHIs and methane measurements and gas cloud similar and described as analogous to 2 other milti tcf discoveries. But i expect it to deliver a decent valuation on lesser assets such as production and the existing discoveries.

Just because their ex Faroe holds no bearing. I don't see HH as the CEO in it anywhere (apologies if mistaken). As COO he follows the CEOs decision. There's may an ex director of Tullow who have gone and set up companies (AET from SEY for eg1).

Likewise for many shareholsders there's been a number of times to exit with substantial multi baggers at various times.

GKP listed at 48p and after it's operations in Algeria under performed and hamered down in 2008 to 3-7p was a buy for me on the very promising Shaikan block in Kurdistan and finally got out at 320p 3.5 years later before it ran on to 420p and over the following few years completely crashed to 1p and a restructuring. To me it's all about an optimum time for entry/exit and not trying to extract the last penny of profit but certianly looking for a multi bagger from here on the current strategy.

I remember it being a painfully slow burn so to speak at Sterling waiting for the asset injection which happened with the new strategy in May 21 and a rename. Could have been picked up at 8.5p Dec 19 and 14.5p in late 21 - now 41p and only the start for more acquisitions.

Likewise look at Serica 43p in March 2012 and could have been picked up in the 3p range Jan -April 2015 and at 5p to Sept that year.

90p Jan 2018. 57p 6 months later end of June.

140p range Feb 2019 - Jan 2020.

150p+ mid 2021

420p early 2022 retreating to 245p May 2022..

Averaged 240p for 2023.

Jan 2024 220p to it's current 178p.

12/6/22 - Britain's savviest investment couple are sitting on shares worth more than £80million after good news last week from Serica Energy. David and Debbie Hardy, who run a Midlands building firm, are the largest shareholders in the North Sea energy producer. Serica's shares to £2.90, sending the value of the Hardys' 10.4 per cent soaring to £82million. David, 63, and Debbie, 58, bought into the business for as little as 3p a share.

https://www.thisismoney.co.uk/money/investing/article-10907389/STOCKS-WATCH-Canny-couples-80m-oil-gusher-Serica.html

I see someone perhaps equally canny has bought and increased to 4m here or 7% up from 6% back in October.

OMV seem to have gotten what they paid for the Sapura interest when the JV was formed in 2019 (9/11/18) on top of 5 years production income.

At the time Sapura had 260 mmboe 2P reserves and 2C resources. This went into the newly formed 50-50 Sapura/OMV JV ie 130 mmboe (or in gas around 0.8 TCF).

As OMVs Chairman (J Pleininger) said at the time - production trebled from 10,000 boepd at the time to around 36,000 boepd for the JV at the time of the present sale (Jan 2024) to Total Energies for $903m.

There has been significant production over the last 5 years. The large Jerun Gas field to start production later this year.

This from November 2018 -

'Sapura and OMV inked a joint venture (JV) agreement for the strategic partnership today, as a follow-up to a Heads of Agreement (HoA) signed between the two parties on Sept 12.

The deal entails OMV subscribing to 50% of the enlarged issued share capital of Sapura Upstream for US$540 million, and to repay US$350 million worth of shareholders’ loan owed by Sapura Upstream to Sapura Energy.

This marks a cash consideration of US$890 million to Sapura Energy.

OMV also agreed for an additional consideration worth US$55 million plus up to another US$30 million in contingency funds mainly linked to the resource volume in Block 30, Mexico at the time of taking the final investment decision.

Under the agreement, OMV will fully consolidate the JV company’s assets in its financial statements, which comprises 260 million barrels of oil equivalent (boe) in proven and probable (2P) and contingent (2C) reserves,

“Already right now, [the JV] has a great portfolio that is fit for growth. So what we are aiming for is to triple the production in the next two years from close to 10,000 boe/d currently to 30,000 boe/d in 2020,” said Pleininger.

https://theedgemalaysia.com/article/sapura-seals-deal-divest-50-upstream-unit-omv-ag-us975m