A few things that may be of interest/beneficial to us and drive future acquisitions to us in terms of additional gas.
We know there is a huge pool of 40 TCF gas within tie-in distance of Savps Accugas network. That's some 6.5 billion boe of stranded gas - some of which they will pick up no doubt.
There are numerous oil fields and like all have licences that must be renewed at some point.
Everyone is probably aware of the gas flaring problems.
When Elands OML-40 licence came up for renewal last year - it was granted 11 months ago for a further 20 years but one of the conditions built into it was they had to have a gas sales agreement of 25 mmcf/d signed within 5 years (4 years left). This imo will be a feature of many licences/renewals where producers will require to have a market for produced gas or else they can't produce oil and breach their licence and gas flaring regs.
Seplat obviously a big gas distributor (just as Accugas) so ideal for Eland to sell up at this point perhaps . Imagine if Eland didn't recommend the offer - where would they possibly sell gas to in 4 years in that area - they'd have to build a pipeline and some sort of facility to somewhere so Seplat an obvious but limited choice. If they didn't accept now, then perhaps in 4 years maybe no route for them available to sell anyone their gas to if Seplat are already well supplied.
This is what i see as a big opportunity for Savp - there'll be many smaller Nigerian companies that will not have the financial capability to deal with their gas and the more of them looking for a sales market that is tight could in theory mean a reasonably cheap resource just to get a sales outlet or risk their oil business in terms of licence conditions and especially flaring restrictions.
Eland 12-11-2018 Confirmation of Licence Renewal
"The consent is conditional on payment of a Renewal bonus of US$6.3 million within 90 days and a commitment from the OML 40 JV to gas monetisation and additional sale 25MMSCF/Day with the gas sales agreement to be signed within 5 years."
Diversified, i've had a look at Eland from time to time and this is my take from their results and presentations.
Seplats takeover of Eland @ 166p = £382m/$475m.
45% of OML40 498km2. Gross 2P oil = 82.2m mmbo (net 37 mmbo).
40% of Ubima 65 km2. Gross 2P oil = 9.3 mmbo (net 3.7 mmbo).
Further gross 2C of 54.9 mmbo combined (net 24.4 mmbo).
Half year results to end of June
Gross production 22,106 bopd (9,948 bopd net).
Net revenues $106m.
Net debt stood at $30.9m.
So $475m for a growing 10,000 bopd Nigeria only focus producer (all oil) with 40 mmbo 2P + 24 mmbo 2C.
Roughly $7.50/b for 2P/2C combined or $12/b for 2P only.
Why would the holders of Marine III want Tilapia - it was already hived off out of Marine III as pretty insignificant (proven by its drilling/production to date).
"The licence is located on the coast, covering an area of 50 km2, mostly offshore, in water depths of less than 10 m. The licence is limited by the Tilapia field boundary, part of the Marine III exploration licence, Lower Congo Basin."
At the end of the day we as investors have no say and it's up to any contracts that Savp sign in nailing down any deal. We are not in India. OGNC have a number of subsiduaries including their buy out of Russian Imperial Energy for $2.5b 12 yrs ago. There are plenty of Asian Companies but don't get hung up on one name specifically mentioned. Delonex a private energy company bought in to the next door block barely 2 years ago - maybe they'll be interested in in seeking to gain a foothold. They are backed by huge financial conglomerate Warburg Pincus who invested $600m to find projects. Maybe with the Agadem pipeline it would be helpful to them with ther Block H discoveries looking for an exit route. Nigeria was one country of focus for Delonex in seeking new projects and late last year farmed (25%) into a $1.25b project in Nigeria along with Vitol (we all know the connections to us re Vitol). If anyone cares to look, Delonex has also showed Niger as an area of focus. Maybe that will come sharper in to focus given the pipeline and what it says this month about its discoveries in the adjacent block to Savp/CNPC. World Bank Arm also an investor in Delonex.
It's said to be a healthy process, ONGC partner many oil companies and are involved in some substantial multi billion dollar projects. Pttep from Thailand bought out Cove Energys stake in Mozambique in 2012 for over £1.2b - pushed back now again to 2025 for development. They didn't run an offshore Australian oil field to the best it should have been. We don't know who we'll get if any or what any of their management style is. Can we also say we don't like this or that on any big firms previous black marks. In addition it has to be acceptable to the government.
Bottom line is GWD has rigs in country rigs and engineering is available from Chinas BGP.
As for Amer -no one with certainty can't honestly say what any wider issues are or not. Amer hasn't delivered its best imo. Some of Amers people are also at Ironveld which was meant to have been a substantial profit making mine a number of years ago and still haven't got it off the ground and gained zilch. After about 7 years they are basically throwng in the towel there too by hoping for an offer for the assets as they stand.
The oil finds continue and why i beleive we'll find multiple new discoveries. Also what price a farmin for Savp with 5 discoveries made, 140+ targets (significant number drill ready), substantial seismic conducted etc compared to what Delonex paid for a 3 well committement and seismic for $35m cash/$65m spend and substantial future payments given the high COS in the area.
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.
I posted 2 years ago re Delonex farming into United Hydrocarbons blocks in Chad by acquiring their subsiduary UHCL Chad Ltd for $35m cash, plus $65m minimum spend which included 2D and 3D sesmic and drill 3 wells (over a 2 year period).
Deal was closed in late September 2017.
$35m was paid on closing, plus $65m committed spend plus $50m additional to be paid if first oil achieved.
United Hydrocarbon (seller of subsiduary) to get 10% and 5% royalties from 2 of the blocks as long as oil is never below $45/b for more than one continuous quarter.
Given the go ahead to invest overseas - they've been overseas for along time. That wasn't the nature of the link but a unique quick call method of additional funding whenever required at 5-10 days notice so i wouldn't say that was beaurocratic.
What's Colombia got to do with it? Can you say what the actual reason is why they are slow ?
(One of 40+ overseas projects including Africa)
They aren't one of the worlds biggest oil companies for nothing. FWIW i thought they had 2 wells drilled there and were stopped to do seismic.
If a Niger farmout is conducted the Upstream article states a planned 10-15 well campaign is to kick off.
What would be the point of a doing a farmout if that was going to be the case and sit on your hands. There's a high number of actual drill ready prospects. Part of the farmout also was in the past to include provision for additional ongoing seismic.
'ONGC, India's top oil and gas producer, is implementing multi-billion dollar projects within the country to bring to production new discoveries or prolong output from existing fields. Its overseas arm is on the prowl for acquisitions besides having funding requirements for the 41 projects it has in 20 countries.
It's only one company mentioned by name. As reported in the past, Tullow execs went to seek licences there but were unsuccessful.
Subscripton based - Quotes a "A well placed industry source."
Partners sought are "large independents and national oil companies" with tech/finance clout.
"Asian Conglomerates" said to be interested, "May include Indias ONGC Videsh which was close to finalising a farm in deal a few years ago" (with Savp).
"You can assume that is a name Savannah will be revisiting this time around" a source.
Could farm out up to half its stake (a source).
Farm out process by consultancy Merlin Energy Resources likely to last between 3-6 months. (We do know it started a while back)
'Situation changed with the pipeline deal - now much much more attractive to potential faminees.'
"Interest has increased since the pipeline deal (said a source). It's looking like a very healthy process".
Article in AEI subscription today basically outlining
CNPCs first production via their new pipeline forecast Jan 2022.
Profitability projections are
First 2 years production from CNPC forecast at 90,000 bopd rising to a peak at 97,000 bopd bewteen 2026 and 2029. Output then decreases to circa 10,000 bopd by 2043.
Lions share to come from Agadem and a few k bl from the Bilma block.
Will take 8.4 years to absorb all expenditure.
China Petroleum Planning and Engineering institute and China Petrlm Pipeline Engineering have drawn up the assessment. Total cost = $2.71b ($1.18b for Niger & $970m for Benin sections). Additional 62c/bl Benin transit fee. CNPC to pay the wages for 352 new employees (197 Niger/155 Benin).
CNPC funding 30% internally. 70% to come from China Petroleum Finance Co (headed by a CNPC board member who is also CNPCs CFO.
No mention of Savp as it's CNPCs own oil costing from it's own production ( likely rather than relying on any other operators input/capacity re finacial returns).
If correct - shows CNPC at no more than 97,000 bopd/peak but im sure they leave room to improve on this and are going on a base case re costings.
Also if as claimed the p/line cpacity is 200,000 bopd before compression expansion, this leaves significant room for other operators.
Above prod figures show about 245m bls exported to 2029 (7 years) from CNPC.
If Savp were added into the mix and pay a pipeline transit fee of say as an e.g of $10/b on 10-25k bopd would be 3.6 - 10m bls/yr giving $36m-$100m/yr in pipeline fees ?.
One thing that does stand out in terms of additional info is that from the earlier January 2019 presentation the number of drilling targets has increased by around 23% ie an increase of 27 targets from 119 to 146 now. Haven't seen any official RNS highlighting any change but it appeares to have crept in with the broker note (newly recently appointed broker - Numis) of 17th September 2019 and again in this weeks presentation.
Numis note of 17th Sept 2019 - "Savannah has no less than 146 prospects identified in Niger"
119 mapped potential drilling targets (Jan 2019 Presentation ).
146 mapped potential drilling targets (Oct 2019 Presentation).
The Mengo fallback poition may be fine re the production scenario that you outline but if the reserves are as low as the original CPR then that is never going to push the valuation up as far as some think. 400m shares over XYZ P2 will determine that.
Also if as they say they get 500 bopd that's not going to produce significant free cash to keep drilling wells in a timely fashion so i could see an ongoing future requirement to raise more funds through debt or equity. Again having sufficient reserves would say whether it's worth continuing down that road or not. The Company would survive but to me it could well turn out to be a stagnant situation and that's why i beleive there's been no rush for any directors to put their hands in their pockets.
The licence still needs to be agreed at what cost but hopefully soon?
Also the comments about why are SMPC paying up if Tilapia were no good ? Even if the well had found nothing of interest SMPC are still liable for their share no matter who they were partnered with and whether oil is/was found or not.
Bottom line imo if there is not sufficient production/oil reserves in the Djeno(and not predominantly gas) then the Mengo isn't going to be worth sticking around for as an investment.
Yes I was aware of it and I asked the company about it before the 1st period would expire. I posted on ADVFN in July and I posted here in August.
Agadem, I posted this on Ad v F n back in July -
' R1/R2 (8406 km2 permit) was issued in July 2014.
On the 3/5/18 (RNS) it was granted an extension.
The 1st phase period runs to 5/8/2019.
2nd phase runs to 5/8/2021.
3rd phase runs to 5/8/2023.
50% of the permit less any discoveries must be relinquished at the end of each phase. If they lost 50% at 5/8/2019 they would still have all their mapped prospects. I know they were planning on seeking a 2nd extension when I enquired about this.
R3/R4 (5260 km2 permit) has had the minimum work compliance exceeded in the 1st 4 year term and has exceeded this by 3 wells. It was granted in July 2015.
As far as I see it, they are comfortable on the Niger assets in terms of time/relinquishment requirements. It was late last year that AK said from memory that he wanted to see a number of rigs operating at once. More than 2 rigs operating, I would think you would want to bring in a partner. '
Todays interims mention the discussions on same - but use the word 'amalgamation'
R1/R2 had different terms to R3/R4 when originally granted. If they are stated today as being in "advanced discussions" on amalgamation they aren't going to have an RNS out saying they have been concluded.
COSTS (3 things) - "We also incurred costs during the period relating to the preparation for our negotiations for the new licence, the legal dispute with SMP and the aborted reverse take-over involving assets in Tunisia. "
LICENCE - " A final round of negotiations is scheduled for October to ensure that the optimal position for both parties can be finalised."
SIDETRACK - " These funds, ***alongside continued anticipated receipts*** from our partner Société Nationale des Pétroles du Congo ('SNPC'), the Congolese national oil company, are expected to enable the Company to re-enter the TLP-103C well at Tilapia with a view to producing oil from the Djeno horizon. "
For anyone to say it was wiser for the company to produce from the Djeno rather than the Mengo on account of greater revenues - that did not work and proved vastly coststly as they gave away an enormous chunk of the company via dilution in fundraisings.
No mention of the legal dispute - has it been quietly put to bed ? They do say the legal dispute incurred costs = more unnesscary burn.
Also the aborted reverse takeover to AAOGs detriment - yet still this can still enrich the same directors/ATOG no matter how you look at it.
The sidetrack depends on both funding to come in as well as future Government payments for past drilling so imo the wishy washiness about 2 rigs and now looking at scouting other options re minimal mobilisation costs.
If the 2 rigs are already in Congo what mobiliastion costs will be significantly different to scouting a 3rd option in the country This all points to delaying tactics and at worst not having enough capital to carry out the drilling - Get on with it ! The oil they produce does not cover their cash burn and the longer they take to get that rig the more cash is burned in costs and admin in the meantime - which if you look at for the last 3 years are brutal and the reporting period showed another £2m+ burned for 6 months. Imo it's delayed because they do not have sufficient capital room.
Still no director buys at this level to show any confidence.
Cash at end June £739k. Miton fundraise £2.5m, Sept SMPC payment £500k = £3.73m.
If they are burning £330k/month Jul/Aug/Sep = £1m - so may have around £2.7m but reducing by £300k each month this goes on but might be helped/offset by the disastourous funding arrangement.
They may have a licence renewal fee coming up/offset maybe by some of outstanding debt ?
Is the legal case dropped quietly to preserve cash?
£2.9m provision to rehabiltate mining and drilling sites - doesn't say when some of this has to be covered but there have been variables in this, the past 3 years so must be some ongoing spend.
"AAOG own 56%of this project but that could well increase to circa 80% in a deal with SNPC"
Have you or anyone considered the licence renewal cost and how much that might be ?
These are a source of government income and usually are not given away for free.
Could it be $1-$2m-$3m + ?
There's been talk about AAOG forgiving SNPCs debt to get a bigger stake in exchange for past drilling costs owed, but that imo won't take into account what the government may charge in terms of a renewal fee for a completely new licence term.
Last year or earlier this year was there not talk of potentially there being another oil company being introduced as a partner ie taking some of the government/SNPC stake ? Does anyone know/recall who that company was or if it still is something in the background ?
Some facts from the CPR and thoughts on broker note.
Accugas distribution capacity = 600 mmcf/day ie 100,000 boepd (page 109).
Gas processing 200 mmcf/d (one train tested at greater capacity) expected to do 240 mmcf/d (40,000 boepd). Capable of modular bolt on expansion.
Exploration upside at Uquo = Net attributable risked recoverable mid case 507.6 BCF gas =84.6 mmboe already risked on factors from 25-75%. (Page 225).
Niger recoverable oil potential unrisked and risked(Page 323)
Unrisked recoverable potential = 6.927 mid to 10.332 billion bls High case.
Risked recoverable 2.821 mid to 4.203 billion bls high case.
Many of the prospects are very low risk and like the 5 made so far are in close proximity and derisked to existing discoveries.
The core VALUATION given by Mirabaud for the Accugas transaction, 2P reserves, Uquo and Stubb Creek 2C + the R3 discoveries = 75p risked (83p unrisked).
They have a total risked valuation target of 92p based on some additional finds.
1) No allowance for any upside from new gas deals (switch from diesel to gas).
2) No allowance for the risked additional Uquo exploration upside (80 mmboe+).
If you break down the valuation (page 2) they use $4.50/barrel for 72 mmbls at R3 East & central plus $4.30/barrel for 48 mmbls at R1 South = a combined $530m for 120 mmbls ie an overall average of $4.41/barrel.
They use an exchange rate of £1=$1.21. If we use £1=$1.40 longer term (brexit outcome etc) ie a barrel valued at $4.41 = £3.15 per barrel.
The risked recoverable = 2.8 - 4.2 billion bls range mid-high case so the valuation potential of the risked recoverable oil is somewhere between £8.8 - £13.2 billion using Mirabaud metrics as a base but with a poorer exchange rate.
With circa 1 billion shares in issue and the above valuation of 75p -83p (risked/unrisked), every 100 mmbls found net to Savp would add 31.5p.
400 mmbls would give 126p to add to the 75p-83p risked/unrisked targets = 201-209p reasonable target expectation.
(Note if Savp has farmed out 50% then above assumes 800 mmbls additional found in Niger or just 30% overall of the 2.8 billions risked recoverable figure).
A further interpretation with the Accugas debt reducing,values the company much higher in share price. Also potential to add some Uqou exploration upside. Some cash being used to buy further gas assets/marginal oil fields ? Also if there is a Niger farmout then the impact of that would also improve the share price somewhat as does the addition of cash from operations.
With so much low risk exploration potential in Niger, 200p is my realistic target. (Mirabaud have a combined unrisked 128p at the moment and that's just for a further 120 mmbls of oil ).
Savp hoped to be able to sign up additional gas customers in place of diesel at much higher gas prices but still at a big discount to diesel which would make the switch compelling.
"there is an estimated 20GW of off-grid power generation capacity in Nigeria that is currently burning oil products), which in a $60/bbl Brent oil price environment, corresponds to ~$8.0-12.5/mscf gas price in energy equivalent terms."
Savannah is actively looking for new industrial customers to take additional gas volumes, at potentially much higher prices than the current $3.6/mscf average sales price because these incremental volumes would be substituting for oil-price-linked products, such as diesel or fuel oil. We do not include any such upside in our base case Discovered Resource NAV but to the extent that Savannah can indeed achieve such sales then there is material potential value upside – we show the impact of additional Accugas volumes at various prices on 2021e net EBITDA in figure 36, where our base case 2021e net EBITDA rises from ~$231m to as high as ~$346m in a scenario where an additional 45mmscf/d is sold at
$10.0/mscf. That is a blue-sky scenario, but even an additional $20mmsf/d at $8.0/mscf, which does not seem like an unreasonable expectation over the next few years to us, would add $35m, or 15% to our base case group 2021e EBITDA forecast.
From Reuters 2 hours ago -
Nigeria's diesel-dependent economy braces for clean-fuel rules
Diesel prices are expected to surge as United Nations rules aimed at cleaning up international shipping come into effect on Jan. 1, with many ships expected to burn distillates instead of dirtier fuel oil.
Estimates vary widely, but observers warn that prices could surge by nearly 20%
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.
“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.
Other heavyweight industries would feel pain. Bank branches rely on generators, with diesel often accounting for 20-30% of banks’ operating expenses, according to Popoola.
Telecommunications companies need them to run their mobile phone towers across the country. Telecoms giant MTN (MTNJ.J) told local media in 2015 that it spends 8 billion naira ($26 million annualy 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 ovens run directly on diesel, so they never cut out.
A study back in 2016 envisaged Savp getting into the Chad-Cameroon pipeline with CNPC.
Savps share was a conceptualised 18,000 bopd but Exxon, Petronas, Chevron (who later sold out to the government) and others had a share of throughput in the 225,000 bopd pipeline.
Given that CNPCs pipeline will have no other major producers to share with yet and has a 200,000 bopd capacity before it can be increased with compression - surely could be an ample outlet for Savp and some others who might later join and much greater than the originally envisaged 18k bopd into the Chad-Cameroon pipeline.