After the comparisons that IVZ have presented regarding other...

After the comparisons that IVZ have presented regarding other companies and the Working Interest (%) that they sold assets for, I thought I would do a bit of digging to see how they compare - and see what events in the future might lead us to a more significant re-rate in share price. It's quite interesting that a lot of the assets in Africa are offshore - and there is some big money going into developing them.

• Mozambique Rovuma Offshore Area 1 (COVE sold to PTTEP in 2012 - sold about a 9% interest in the field)
• This was sold for about $200 million USD per WI %
• A number of discoveries were made prior to the 2012 sale. Starting in 2010 with Windjammer, Barquentine and Lagosta. Then Camarao field in October 2011 that had approx 116 metres of net pay. There was also the Tubaro discovery (also 2011) that had 33.5 metres of net pay. Then the Golfinho field in May 2012 - after which the takeover offers came in.
• In March 2012 they flow tested the Barquentine well, showing production of 90-100 million cubic feet per day (and estimated with an optimal setup this could be anywhere up to 200 million cubic feet per day).
• Estimated reserves were originally up to 50 TCF, but in more recent years they are talking up to 75 TCF.
• There were a number of bidders for this transaction, which likely drove the price up. And the flow rates are exceptional - hence requiring a minimal number of production wells.
• Translating the 9% interest to the 75 TCF in the field means that PTTEP effectively bought about 6.75 TCF worth.
• At Final Investment Decision (FID) in 2021, the estimated cost for development was approximately $20 billion USD.
• Rovuma Offshore Area 1 is also located right next to area 4, and together these areas are expected to hold up to 150 TCF.

• Mozambique Rovuma Offshore Area 1 (Anadarko sold to ONGC in 2013 - sold a 10% interest in the field)
• This was sold for about $260 million USD per WI %
• This was the same field as the above, and once again there seemed to be a lot of interest in this particular gas field by a lot of majors which likely helped drive the price up. And the exceptional flow rates as well.
• The 10% interest means they bought about 7.5 TCF - or paid about $260 million USD for each 0.75 TCF.
• Transactions related to the Mozambique Rovuma Offshore Area 1 seem to be massive outliers in terms of the prices paid per WI %, from all of the assets/sales that IVZ presented.

• Mozambique Rovuma Offshore Area 4 (ENI sold to Exxon in 2017 - Sold a 25% interest in the field)
• Sold for about $112 million USD per WI %.
• I couldn't find a lot of good information on this one, but they had drilled a number of discovery and appraisal wells prior to the sale.
• Estimates are that this area contains up to 85 TCF of gas.
• This area connects with Area 1 (described above), though it appears to be much deeper and hence would be harder to develop - which likely explains the differentiation in price.
• As of 2020/2021, they were looking to make a Final Investment Decision (FID) to spend about $30 billion USD to develop 21.7 TCF. It appears that this decision is still on-going (expected next year).

• Yakaar-Teranga Gas Field Offshore Senegal (Kosmos sold to BP in 2016 - Sold a 60% interest in the field)
• Deepwater offshore gas field.
• Sold for $20 million USD per WI %.
• They had three discovery wells from 2014 onwards (up until the sale).
• Estimated to contain 25 TCF of gas in place, with minimal CO2 and contaminants (i.e. makes it easier to process).
• I couldn't find any data on flow rates from the appraisal wells (either Yakaar-1 or Yakaar-2).
• Currently looking at Phase 1 development to target production of 150 million cubic feet per day of gas.

• Kenya Blocks 10BB, 10BA, 13T (Africa Oil sold to Maersk in 2016 - Sold a 25% interest in the field)
• Onshore.
• Sold for about $37 million USD per WI %.
• First discovery was Ngamia-1 in 2012, and a large number of other discoveries up to 2014.
• In 2016 they had 2C resources of 766 million barrels of oil.
• This project has run into all sorts of issues, and Africa Oil and Total have pulled out and Tullow now owns 100% of the project. Despite pulling out, Africal Oil and Total still appear to thing the project will be developed - it just doesn't fit their current business direction.
• There's a good interview with Africa Oil here that describes their shift in approach. It also sounds like the running of long pipelines through "environmentally sensitive" areas in a number of countries has caused them a lot of headaches. So if IVZ can connect into existing infrastructure wherever possible that would be a huge bonus. Also, the gas to power and generating revenue in the near-term could make IVZ more attractive as they could be "producing" quite quickly.

I was also doing a bit of reading on flow rates and there's some suggestions on the Oil and Gas flow rates page on what "good" numbers would be.

My takeaways from the above are as follows:

• Once you take into account the likely resource upgrade from the eastern leads, the Cabora Bassa Basin is well and truly up there with some of the biggest.
• Once IVZ can get proper supply bases set up, and reduce the costs of drilling wells, you would expect the onshore development to be much more cost effective than offshore development, making their asset potentially more attractive from a cost perspective. That being said, the flow rates in the first well test will be a big driving factor. Offshore Area 1 in Mozambique had a phenomenal flow rate from a single well, and hence likely drove the insane price being paid per WI %. So overall development costs are really going to hinge on good flow rates, reducing costs to drill the wells, and the 3D seismic better delineating any compartmentalisation to understand how many wells would be required to properly develop the field.
• The timeframes where a partner was brought on seem to vary quite a bit - all of the later acquisitions (i.e. 2016/2017) seem to have a number of years between initial discoveries and farm-outs.
• Reducing the amount of infrastructure required to monetise the asset will be key - and ensuring that wherever possible it is constrained to just being run within Zimbabwe. It sounds like in Kenya their planned pipelines run through multiple countries, complicating the entire development. For IVZ, being gas it will be much easier to deal with and monetise quickly, and with the ramp-up of other industries in Zimbabwe there's going to be plenty of demand within the country to start monetising - so I see IVZ as more attractive from that perspective.

What I would like to see this year - which could help us re-rate:

• Some solid data on poro and perm from the Mk-2 sidewall cores - including a net pay upgrade. Also, an updated prospective resource based on these updated values. I've read back through all the original resource estimates and they make no mention of the poro/perm values or the column heights and net to gross values used. Which I think is why it's so hard to understand at the moment whether Mk-2 met expectations or not. We just don't have the data on what net pay was expected.
• Excellent flow rates from MK-2.
• A solid commitment and timelines for setting up an initial 50 MW gas to power setup to start monetising Mukuyu. Ideally they can plan this while they're planning the flow test.
• 3D seismic - I'm not expecting this to be completed, but all shot and very far along the path of processing it.
• Another successful exploration well - I'm leaning towards this being in the eastern plays if they are more gas prone, as it sounds like gas will be much easier to monetise than oil or condensate.

I'm still not 100% convinced whether we will see a decent farm-in offer this year - but there's so many factors outside of just the exploration side that could change that. Were we to prove monetisation on a small scale, quickly, maybe IVZ becomes a more attractive option to companies that are looking for short-term production potential.