Member Info for ZENGAS

That's the meeting over. Thought it was good a good listen and for me most issues tackled/explained and discussed with further update with the results next month.

The Numis update yesterday was a buy target of 28p again.
Debt at $520m and net debt being $494m described as being better than their own forecast of $554m and mention net debt falling faster than expected. Slight lag on Numis own production estimate but expect it to ramp up in H2 .

and another
"Nigeria’s Telecommunications Industry Bleeds from Inadequate Power Supply"
An on-grid site consumes an average of +1,500 litres per month in Nigeria and 450 litres per month in Ghana. The higher diesel consumption of on-grid sites in Nigeria is due to the lack of grid power supply, making the diesel generator run longer every day”. In Nigerian telecoms, we consume almost 40 million litres per month to power telecom towers which are both financially consuming and pollute the environment further.”
Nigeria’s telecommunications industry must look towards new cleaner and eco-friendlier sources. Research has proven that the use of diesel generators as the default power source for off-grid and grid connected telecom tower sites comes with implicit disadvantages; namely, the high cost of power, diesel logistics and theft, as well as a negative environmental impact due to the high CO2 emission per kWh consumed.
http://venturesafrica.com/qnb-group-mastercard-undertake-first-successful-international-transaction-in-sudan/

There is always a risk from any unexpected future rises in diesel beyond business's control - then what ?
"While many Nigerian household and small business generators are powered by price-capped gasoline, the big generators for larger firms, apartment complexes and more substantial homes can only run on diesel. The oil industry, the Nigerian economy’s biggest driver, would not take a big hit as it does not rely on Nigerian consumers being willing to absorb extra costs it has to pass on. As fuel producers in their own right, its firms can also recoup costs more easily.
“Businesses may struggle to survive, or in the best case scenario, would at least downsize,” said Tunde Leye, a Lagos-based analyst with SBM Intelligence. Diesel is the second or third biggest cost for many Nigerian firms, he said.
Telecoms giant MTN (MTNJ.J) told local media in 2015 that it spends 8 billion naira ($26 million) annually on diesel.
Even bakeries need diesel. At Rehoboth Chops & Confectioneries Ltd, a bakery in the Ogba district of Lagos, giant diesel-powered ovens bake hundreds of loaves of bread. The factory runs 24 hours a day, six-and-a-half days a week.The lights, mixers and fans that clear the heat are powered by two large diesel generators outside. The ovens run directly on diesel, so they never cut out.Chief operating officer Abayomi Awe said they use cheaper grid power when they can but rely on generators for around 20 hours per day. Grid power can be down for days.“It becomes difficult for us to expand if the price of diesel goes up,” he said as bakers scrambled to pull finished loaves from steaming ovens. “It might result in some companies, some bakeries like ours, shutting down.” https://www.reuters.com/article/us-nigeria-power-diesel/nigerias-diesel-dependent-economy-braces-for-clean-fuel-rules-idUSKBN1W323K

Surely cost refective tarrifs would ultimately reduce business costs eleswhere as well as make goods/services more competitive (which they are crying out for and result in savings being passed on into other parts of daily life. (Telecoms/Food/Clothing/etc).
W/Bank survey, 27% of Nigerian firms identified electricity as the main obstacle to doing business.
International Monetary Fund said in its latest economic report on the country. It estimated the annual economic loss at about $29 billion. Businesses and individuals spend about $12 billion a year, twice the country’s annual infrastructure budget, fueling these generators. Tariffs should go up by a minimum of 50%, according to the IMF, but maintaining prices at current levels has become a fiscal burden.
To run and operate a generator for just '9 hours' a day in Nigeria is 3.8 times the cost of getting electricity from the grid. You've got to budget for replacement/useful life (6/yrs), maintenance/breakdown inconvenience too as well as fuel, constant noise etc. Between generator spend and fuel $28b+/yr.
Country swamped in pollution/toxins from CO2/NOX levels from 30-100m estimated generators spewing that out even in cities like Lagos that also have intermittment power supply.
Private members bill was being touted to gradually ban generators but too severe too soon - but imo will only be a matter of time when stricter controls come in and likely only for back up use in critical circumstances ie hospitals etc.
Doing business for just 9 hours - so what's the cost for plants etc that run 16-24 hour shifts - imagine the massive savings for cheaper reliable electric on tap and no big budgetting for multiple big ticket gensets where money can go directly into business growth.
https://kpakpakpa.com/spotlight/diesel-generator-cost-business-nigeria/#
Bottom line it's always been compelling for grid electric though that has to be become reliable what many other countries take for granted. Who wants to run their freezer or fridge for 9 hours if food/produce is spoiled through lack of 24/7 grid electric and that's the only issue from poorer class - they will pay but it's got to be reliable. For business - business is at a competive disadvantage. The amount of agriculture waste through lack of refrigeration or high cost generation for processing is brutal in a country of over 200m people growing at 2-3m/yr
If you also move people away from using diesel/petrol and develop a massive gas industry which has it's own resource on tap, it's brings a wealth of jobs to the gas industry and revenue/taxes directly from an under used resource and allows the country to be far more competitive in just about every respect.
https://www.reuters.com/article/us-nigeria-power-diesel/nigerias-diesel-dependent-economy-braces-for-clean-fuel-rules-idUSKBN1W323K

Additional contracts have to happen as that was also the whole point of this transaction.

Not going to repeat the impact of higher electricity prices from next month or full reflective tarrifs next year reducing payment lag - but add in that Save have significant spare processing capacity (not to mention even greater pipeline capacity) so some of the 3 things i hope will materialise soon - Alaoji to come through or another p/station, the 20 mmcf/d at Ifam (from the 35 mmcf/d contract) and some private customers at a much greater price.

I'm looking for a significant jump in revenues and hoping for $100m/yr to kick in by this year end going into 2021 from new contracts.

50 mmcf/d to p/stations @ $3-$3.50/mcf inc pipeline tariff is worth $55m - $64m additional revenue.
25 mmcf/d @ $5-$7.50/mcf (replacing more expensive and polluting diesel) is worth $45m - $68m.

There's potential to add $100m+ revenue from just an additional supply of 75 mmcf/d. Opex costs are already significantly built in so the margins should be even higher and this would greatly alter the debt repayment or timescale or could even lead to a successful debt rescheduling at better rates.

$25.7m cash at the 31st of May.

One thing for sure is it's very unlikely payment was received 2 days after the letter dated 29th May seen by 'The Cable' for $17.98m of which $2.141m was paid leaving a January 2020 outstanding payment of $15.8m which was due by 8th February 2020.
Reference https://www.thecable.ng/exclusive-accugas-moves-against-nigeria-over-calabar-gencos-debt

That implies another 3-4 or 5 months of similar payments still to be made which would change the cash position significantlty imo.

2 weeks after that cash position date - In a report of 17th June which i posted, the government did say it had authorised payments of $700m to gas and gencos directly.

"The Federal Government is to pay electricity generation companies and gas firms about N272.59 billion for 2020 and part of 2019, document sighted by Daily Sun from the Ministry of Finance has revealed.
The figures, according to the Federal Ministry of Finance, Budget and National Planning with the title ‘Power Sector Recovery Plan and Impact of COVID-19 Pandemic, indicated that Gencos and gas firms are expected to be paid 100 per cent of their invoices.
PAF is a facility line at the CBN, guaranteed by the Federal Ministry of Finance. In settling Gencos and gas suppliers invoices, CBN does not credit NBETs’ TSA account; instead, following NBETs settlement process, it sends all documentation to the CBN, for the bank to ratify and credit the generation and gas companies."
https://www.sunnewsonline.com/debt-gencos-gas-firms-to-get-n272-6bn-from-fg/
I think AK has been diligent enough in securing a $15m facility at 30th April and can't be drawn down unless he is in place which i expect him to be.
Tight, but the company is steadily increasing it's gas ouput and a number of contracts in the wings which should significantly change the landscape as well in due course.
Remember also electricity charges reportedly rise substantially from 1st July in line with the government directives and IMF conditions and full move to cost reflective tarriffs for 2021. Both of these materially help in speeding up payment and lag.
Not a lot, but added 100k and 60k at under 7p this am. As ever DYOR. (PS unfair criticism of Agadem. That's why i tend to keep any communications i have with IR or PR company off the boards as there's always that one or 2 who aren't man enough to think for themselves but too readily to blame others when any info is shared and it doesn't come along to some others likeing).

The 2019 results to end Dec will be largely immaterial given we only took over in mid November.
Gas sales 93.9 mmcf/d + 2519 bopd gross. Cash collected $168.8m with EBITDAX of $89.5m.
Mirabaud estimate of minus ($15m) for EBITDA for 2019.

The Listing document beginning of May forecast free cash flow for this year 2020 of $104.2m rising to $128.1m for next year and $141.3m each for 2022 & 23.

Mirabaud estimated gross 25,100 boepd with revenue of $234.7m to achieve EBITDA of $173.5m for 2020.
For 2021 gross production of 30,600 boepd, $311.5m revenue and EBITDA of $244.5m.

Given the delay in the transaction being completed in November, delay to EPS in Niger, Covid and oil price, I think we'll be at least 6 months behind Mirabauds estimate for 2020 but this doesn't allow for much in the way of new gas contracts. Ifam would generate another $20m/yr in revenue at $2.50/mcf + pipeline tariff at 20 mmcf/d of the 35 mmcf/d contract when enacted.

Not so much where we've been, but how this first year will deliver - so looking for increased sales/new higher paying customers, EPS in Niger and move to debottlenecking Stubb Creek oil and of course exploration moves in Niger.

Given the likes of Tullow execs were after our blocks for themselves in the past as well as DIG Oil in late 2019 - they didn't get them, but i wonder would they be prepared to farm in ?

Also what about the huge company that we have done business with in Nigeria on the Afam power plant - ie Sahara Group a leading international energy and infrastructure conglomerate with operations in 42 countries. They were looking for oil and gas assets to grow their production business.

R3 is now smaller in size and has the first 5 discoveries with 33 mmbo 2C for 4 of them and upside on those to 109 mmbo.
Additionally under 3 existing discoveries ie Bushiya deep, Amdigh deep & Eridal deep there's a further 24 mmbo mid case - 71 mmbo high case unrisked. 2 other nearby prospects - Adal & Efital have 61 mmbo mid case - 192 mmbo high case.

That's about 200 - 372 mmbo target mainly from our existing discovery wells plus 2 further prospects on R3 so maybe Save don't wish to farm R3 out given it's $6.8m approx to 1st oil through a leased EPS and could pursue R3 exploration and development on their own. Now if someone was to come along with a farm in offer for R1/2/4 and some cash upfront ....??

Surely if others were keen on the blocks for themselves, you would think they would be interested to get in the door for 30-50% of that potential if the farmin terms were decent ??

6 Prospects on R1/2/4 have a net unrisked 342 mmbo mid to 1044 mmbo high case.
There was originally 14 drill ready prospects on R1/R2 and covered by 3D seismic.

Tullow tried to secure the same Agadem blocks that Save now have by their Africa head, Tim O'Hanlon. He's the brother in law of Aidan Heavey ex CEO of Tullow. Heaveys now heading up Boru Energy financed by Carlyle Group looking for Assets in Africa that will target acquisitions up to $1b.
http://www.boruenergy.com/2019/10/01/the-carlyle-group-launches-boru-energy/

The new CEO at Tullow came from Delonex which is funded by $600m+ from Warburg Pincus.
Delonex drilled block H on the Chad side which adjoins R4 on the Niger side. They made 4 new discoveries from 6 wells by October last year and were scheduled for appraisal drilling this year. I always thought it definitely bodes extremely well given the play types for our R4 block (given geology knows no man made country borders).

3-10-2019
"Privately-owned explorer Delonex Energy has made four oil discoveries in Chad’s frontier Termit basin and will begin drilling appraisal wells next year to also target a deeper, higher potential play.
“In the last year, we have drilled six exploration wells and have made four discoveries — these are exciting times,” said Lorna Blaisse, senior exploration geologist at Delonex, at the Africa E&P conference in London this week.
A possible export route could open in 2021 when a pipeline due to take oil from Niger’s Agadem basin to Benin’s coast is set for completion. Block H abuts the Chad-Niger border and is immediately adjacent to the oil-rich blocks controlled by China National Petroleum Corporation and Savannah Petroleum in the Agadem basin.
Delonex gained control of Block H in late 2017 by acquiring Bermuda-registered United Hydrocarbon.
Delonex has identified three oil plays in the block — two Cretaceous and one Tertiary.
The Tertiary reservoirs are fluvial, deltaic and lacustrine in nature, said Blaisse, with porosities over 25% and permeabilities up to six Darcies permeabilities “in very quartz-rich sands with minimal clays”.
Delonex — headed by chief executive Rahul Dhir — has found mature Cretaceous source rocks right across the block and at many levels and with a total oil content of up to 20%.
The real intrigue for us,” said Blaisse, “is porosity preservation in over-pressured Cretaceous shales, a play which has the potential to open up huge new reserves in the basin and a broader variety of deeper traps. "
https://www.upstreamonline.com/weekly/delonex-makes-four-oil-hits-in-chads-termit-basin/2-1-682041
Another one that was after our blocks late last year was DIG Oil which said some of our blocks were relinquished but by early 2020 it was reported the blocks were off the market. DIG Oil had apparently $600m coming to them. Last month SAVE saying they will have 100% for a further 4 (+4) years. It says something about the potential in the blocks given Saves resolve to keep control of them.

21/4/20
"As announced on March 10, 2020, the Company expected to achieve operational netbacks of $11 per barrel with its benchmark Brent priced at $30 per barrel. To date, the Company has achieved netbacks of $12 per barrel and continues to engage with all its contractors to further optimize its cost structure. PetroTal will now look to achieve netbacks of $13 per barrel, equivalent to 43% at $30 Brent."
==========================================

Net backs after transport, opex, brent discount and royalties have improved.
They expect to do 11,190 bopd for the rest of the year.
Brent reference price currently circa $40/b.
Capex deferred.

Current cash of $28m. They say they are "well funded to continue development".
10,000 bopd at $12/b net back on a $30/b Brent reference is $44m. Add current cash of $28m - is $72m .

Flat $12m/yr if unchanged/static liability.
47% of $33.7m due by Q2 2021 (12 months) = $15.84m.
Accrual for various projects underway due through Q3/20 - Q2/21 = $10.8m.
G&A trimmed, but say $11m for a year.
To open the oilfield via suppliers end of this month = $6.6m.

Above accounts for $56m against current cash of $28m and assumed net backs of $44m at a Brent ref price of $30/b and flat 10,000 bopd = surplus cash of $16m and ongoing cashflow.

Headroom is an additional 11.9% production and a higher reference Brent oil price in a $35-$40/b range.

17th June 2020

" The Federal Government is to pay electricity generation companies and gas firms about N272.59 billion for 2020 and part of 2019, document sighted by Daily Sun from the Ministry of Finance has revealed.

The figures, according to the Federal Ministry of Finance, Budget and National Planning with the title ‘Power Sector Recovery Plan and Impact of COVID-19 Pandemic, indicated that Gencos and gas firms are expected to be paid 100 per cent of their invoices.

PAF is a facility line at the CBN, guaranteed by the Federal Ministry of Finance. In settling Gencos and gas suppliers invoices, CBN does not credit NBETs’ TSA account; instead, following NBETs settlement process, it sends all documentation to the CBN, for the bank to ratify and credit the generation and gas companies.

Recall that the Nigerian Gas Association (NGA) had last week during a webinar seminar raised the alarm over the mounting debt of the power sector and its attendant effects on its members. "

https://www.sunnewsonline.com/debt-gencos-gas-firms-to-get-n272-6bn-from-fg/

The new electricity tariffs that were due to come in on April 1st but delayed for 3 months on account of Covid-19 now appear to be being implemented from 1st July.

Port Harcourt was to go up by 76%, Benin 82.8%, Abuja 73.1%. 11 Distributions companies - 8 of whom have increases in excess of 50%.
" The implementation of these reviewed tariffs is the first since 2015. The tariff review is designed to curtail revenue shortfalls for electricity distribution companies (“DisCos”) due to the disparity in generation costs, distribution costs and end-user costs. This means that electricity companies have in general, been remitting less than 40% of their contractually obligated payments to the Nigerian Bulk Electricity Trader (NBET), which in turn means the Transmission Company and Generation Companies have not been having their invoices settled in full, or have had to be subsidised by government interventions.
From a fiscal standpoint, this tariff adjustment frees up the increasingly challenged resources of the Federal Government (FG) as the Central Bank of Nigeria (CBN) has been supporting Genco’s in recent years through a N701 billion naira Power Sector Intervention Fund to cover the shortfalls of these DisCos. With the implementation of these new tariffs, DisCos revenues should increase materially, therefore, reducing the financial burden on an already strained FG and allowing it to invest in other sectors of the economy. As a cushion, the FG has approved a new phase of the Power Sector Recovery Programme (“PSRP”) which should compensate for any tariff shortfalls the DisCos may experience going forward which can be seen as further incentive for investors.
There will be relatively significant price increases on April 1 and an indication of further increases in 2021 to make the tariff fully cost-reflective."

https://africapractice.com/nigerian-electricity-regulator-announces-tariff-review/

16th June 2020 - New Electricity Tariff Regime Begins in July - Minister
https://allafrica.com/stories/202006170128.html

"Non-recourse debt is a type of loan secured by collateral, which is usually property. If the borrower defaults, the issuer can seize the collateral but cannot seek out the borrower for any further compensation, even if the collateral does not cover the full value of the defaulted amount."

Nigeria assets are secured against that debt but not Niger or the parent Co.

Re the $5m loan If not paid or it is extended - it depends on the reason. There's actually $10m available. We need about $6.8m for to get the EPS up and running in Niger for the first 1,000 bopd with lease costs of around $8m for the first 24 months. Getting that up and running moves that 2C to 2P reserves in Niger.

"Subject to mutual agreement between Savannah and the Facility provider, an additional tranche of up to US$5m is available to be drawn within a 2 year period, such further tranche expected to be made available on similar terms as the initial Principal Amount."

I will be voting in favour though i doubt my vote would make a difference given the larger holders/institutions.
I beleive the best option is retaining AK (but that doesn't mean not contacting the company over the course of the past year re pay/bonus concerns versus delivery) because at this time as we are in a period of transition and of what's in the potential pipeline with all the spare Accugas capacity. It's not the right time to eek any change in mangement and if there are payment delays a new CEO is hardly going to change that imo in the short term. 2021 is the time to see the introduction of cost reflective tarriffs and further change in infrastructure roll out which ultimately should be to our benefit.

To suggest pulling out of Nigeria does not make sense especially just after 6 months of ownership. The opportunity is too big given our 80% interest in Accugas versus just being an oil or gas producer there. On top of this, Niger and Nigeria are two seperate business units and the debt on our Accugas/Uquo/Stubb Creek is ring fenced from the licences in Nigers Agadem basin.

$49m supplier obligation.
$11m cash plus an $18m raise = circa $29m.

Deficit $20m.
About $15m per year for 3 years re oil contract payment unless a greater parity acheived which might reduce that significantly.
Net backs of $11/b, $14/b and $18/b were given for Brent reference at $30/$35/$40/b price. This was set against 15k bopd so would give a yearly net back of $60m, $76m or $98m.

Ther goal was to achieve 20,000 bopd which they said would improve net backs by an extra $1/b which if achieved and on the same price per bl range give $87m, $110m or $138m.

At minimum production of 9,000 bopd and the tarriff reduction should see in excess of $40m at a $30/b oil price.

I don't see an urgency to go back to the original capex to get to 20k bopd by this year end. They were already at 15k region and the disposal well ($7m?) i think was the next most important item.

Oversubscribed placing and Meridian in for just over half of that.
With the full placing about 815m shares in issue
Another 70.5m warrants at 16p if exercised would bring in an additional £11.25m.
About 885m shares potential.

Last broker target 40p at 674m shares. (My stab 815m shares now 33p? with warrants 885m = 30.5p but with additional cash of £11.25m if exercised).

Further to the Company's announcement on 18 October 2019 (the "RNS"), the Company announces that

* the Maturity Date of the Facility (which is no longer considered material to the Company) was amended to be 6 June 2020 *

The Facility is expected to be repaid in full from the Company's cash resources prior to expiry.

The compnay via it's tweets seems happy to pump more gas and seek to supply other gencos in the last few weeks re their tweets.

I posted this on the other board just over 2 weeks ago re delayed payments -

" On some delayed payments - can we live/cope with that until cost reflective tarriffs cover everything and all bills, past and present can be paid on time without the need for government subsidy and ultimately our World Bank and Standard Charter guarantee ?

It doesn't cost much more to produce additional gas over current fixed costs against it staying in the ground anyway rather than put it to a delayed payment market ??? Yes it depletes reserves - an extra 50 mmcf/d eats up 3mmboe yr but with the Uqo 2C and some of the lower risk exploration upside, i see Uquo being able to replace its P2 reserves by 100% not to mention all of the 2C gas in Stubb Creek which incidentally has no $ value attributed to it other than the oil there.
If we can grow the business sufficiently through additional higher end customers away from the gencos for now, then we might over compensate for that percentage which falls into delayed payment and this is something i'm watching for. "
-------------------------------------------------
Again today my focus is that we need to watch for the introduction of full cost reflective tarrfffs as the problems are fixed/Siemens work etc. The IMF have apparently this in it's loan criteria and these were to come in next year. So yes i see the Nigeria Finance dept of the Govt through its own payment support continuing to sustain this until there is equilibrium created in cost/pricing and return.
Bottom line Nigeria desperately needs to move away from some $30b+ on diesel use wastage that in itself does not supply a full consistent electricity supply, heavily polluting and stifling economic growth and reliance on an oil dominated economy.
Worth remembering also that a portion of our revenue comes from Stubb Creek and with the recovery in the oil price this can only be a positive (and also for the Niger EPS).

Stubb Creek, New private gas customers - it's the Gencos that have the issues for now so worth considering that in the current and future cash flow mix and studying how these develop. For that and the above reasons i'm confident Save will be ok.

$15.8m.

The previous one they reported on was in November 2019 and for around $65m.

"But The Cable understands that the ministry of finance is making efforts to settle the invoices and avoid the scenario."

If it was due 8th Feb, it gives an idea of around 4 months lag.

There wouldn't be the need for many questions if they give a detailed update - not so much on where we've been but where we are now and where we are going to be in 3-6-12 months.

Appears limited to one investor question - so i won't submit anything until i see what they say first.
Accepting the accounts brings another meeting (so might be an opportunity to ask further) and i'm sure there'll be new coverage by analysts, Vox and Malcy and this time around if there's anything felt left unanswered those guys should be pressured into asking the right questions or else they give these interviews a miss as whats the point. Most know what the company is about and who needs new investors if he can't retain the present ones by being light on info.

For me, it's not so much the accounts to Dec 2019. By the time of the agm, we will be 6 months on now with the first real period of Save ownership of the Nigerian assets which the previous 2 years delay was all about. This is the important bit.
We've seen an increase in production Q1 so what i want to learn about is
Cash flow - how's it going or have they reduced any gas payment backlog or are they at a stage where any backlogs after 6 months of trading are manageable ??.
What about new contracts/customers - timelines ?- The free cash flow projections were based on existing contracts.
$100m of additional new revenue/yr is sales of 80 mmcf/d @ $3.50 mcf.
Alaoji at full dispatch was estimated similar to Calabar so 110- 135 mmcf/d upside from that one ? Afam up to 35 mmcf/d ? Higher private contracts to displace diesel from $15 down to $8/mcf (20 mmcf/d @ $8/mcf or $58m/yr of additional revenue was estimated to be worth 10p+ on the share price by Numis). When can we see a sizeable revenue jump that wasn't in the baseline projections as these could be material game changers ?
Any of these contracts has the ability to change the debt/cashflow potential at little change to the opex as does - what progress on the debt tenure/improved rates. From memory it was stated that for every cut of 1 basis point would yield about an extra $4m to Save - so what chance 2-3 point saving and when as this is another game changer in waiting ?

Niger EPS when ? Niger exploration when ? Farmout expectation ? What happened to the 2018 $50m facility- still in place ??

The dividend is at least a year off minimum imo so even if they diverted the this to a buy back it wouldn't happen any time soon.
Brent is now just shy of $40/b with a $42/b price projection in the CPR for the next 24 months.
They have committments -
Get Niger phase 1 ($14.8m of which around $8m is leased) and phase 2 of about another $40m to production and self financing. If the oil price keeps improving i'm sure they'll want to start to deliver on phase 1 at least this year.
Company is looking to sign up further gas customers and that includes securing other gas fields in Nigeria - so i see cash preservation especially with the expansion in the electricity market - to spend there.
Also they are looking to secure better financing terms and until that would be concluded as well, i can't see them having cash so soon for a share buy back.
Also $5m to settle (if not done so already or extend again) by this friday for the short term loan.
Imo the seller(s) will dry up at some point.