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The ‘one man show’ and succession was my webinar question.
From memory AK said they don’t tend to employ for promotion rather best person for role. Which absolutely makes sense but imo at Bod level there should be others as able as AK or at least the potential.
Trek
Totally agree, Agadem. Keyman risk is one of SAVE's biggest risks: possibly *the* biggest risk. There may well be fantastic and inexpensive opportunities in region, but there is also the risk of overreach and loss of focus. For instance, I am a little nervous on the proposal of a renewables purchase.
Also, having a very hands-on CFO who can manage the banks, key counterparts and key strategic investors is essential. The appointment should really help take the weight off AK. It'll be interesting to see if Nick Beattie gets the role or not.
Steve Jenkins and the NEDs should be guiding on these issues.
It's easy for us all as PIs to sit at our desks and do excel models or talk about Price to FCF ratios or adding another big ticket, but the team are clearly working flat out on complex deals in difficult geographies. At some point, people need to come up for air, take a break and take stock - we're all human.
I know this post isn't analytical in the same way the great posts are from a number of you on here, but I think it is still extremely important.
Have a peaceful weekend, everyone.
On the current assets Save has 183 mmboe 2P
As posted earlier re FinnCap analysis and the bare base case, it could be possible that by end 2024 Save could be in a net cash position and thereafter generating a substantial cash build from then which is likely to buy/expand into further reserves/production assets that in turn throw off their own cash contribution.
Currently having 176 mmboe 2C makes it a distinct possibility that the company can sell on the business in a near debt free or net cash position with the original P2 valuation intact.
In fact on a 5 year basis without touching on 3C or exploration upside in Chad or Nigeria, the assets could produce 50,000 boepd and only consume 90mm bls reserves and imo should be more than replaced by the current 2C without eating into the original reserves.
I beleive we could add a further 250-300m P2 and 50 -75k of production and still be at a net debt position of only $1-$1.2b while being an 85 - 100k+ boepd producer with upside from their base case and having the benefit of significant midstream assets.
With Niger production still to come, where would that take their production profile ?
Overall, i see the possibility for 1b boe of P2 reserves being achieved.
'No new production wells have been drilled on the fields by the operator since 2015 and Savannah intends to make further investments in the fields, including drilling an average of 12 wells per year from 2023.'
Suspending the drilling of new oil wells for 7 years on these assets due to low oil prices has seen the average field production drop from 46,218 bopd in 2017 to circa 33,500 in 2021. Since 2015, only the two hundred high performing wells responsible for 75% of total production were prioritised for work-over. The top 200 wells averaged 173 bopd each in 2015 while the other 400 wells averaged 29 bopd. Comparative figures for 2021 are 124 bopd and 21 bopd respectively.
New production wells in the Doba and Doseo basins typically test at rates up to 2,200 bopd and 2,368 bopd in the lower and upper cretaceous reservoirs respectively. Consequently, recommencing drilling in 2023 with a 12 well a year programme, should have a highly material impact on production.
According to BP’s January 2018 statistical review "over 40% of Chad’s reported proved reserves of 1.5 Bn Bbls, that is 635 MM Bbls, have been produced from four production licenses in the Doba Basin fields operated by ExxonMobil. This implies that as of the end of 2017 around 900 MM Bbls remains to be produced from the fields and areas that contributed to the original estimate."
From Exxon:
Successful restructuring of Chad oil field operations
The restructuring program began in early 2015 following EEPCI’s decision to reduce both capital and operational expenses by suspending the drilling of new wells. The company’s focus shifted to maximizing oil recovery from the project’s producing wells.
By the start of 2016, the project had transitioned from operating multiple drilling and completion rigs to one well work rig. The demobilization of equipment was accompanied by a reduction in contractor and employee staffing. These actions resulted in a 95 percent decrease in EEPCI’s 2016 capital expenses compared to 2014, the last year of substantial drilling.
Described below are the operational changes that led to a 20 percent reduction in operational expenses from 2015 and an all-time best safety record.
Top 200: Recognizing that 30 percent, or 200, of its 600+ wells produce 75 precent of its oil output, EEPCI opted to give maintenance and well enhancement procedures priority to this “Top 200.” To the extent time and resources permit, crews also repair and restore lower performing wells outside the Top 200.