Member Info for PageofCups

Aaron LeBlanc wasn't COO when NT2 was drilled. He was appointed after NT2.

The novice questions raised by the environmentalists are to be expected when they are drowning in there own shrill voices regarding oil drilling and the environment. As for PM Davis suggesting they can receive carbon credits by keeping oil in the ground. First you have to drill a number of wells to prove up any oil field and establish a reserve base. Then you have to demonstrate a production history that the oil field is capable of producing before you can work out the value of any carbon credits. Otherwise how do you know how much oil you are keeping in the ground. This means flow testing the wells. I doubt any scheme would provide carbon credits of any value without this evidence. CEG will not be funding the next well. This will be done by a major oil company like Shell or BP. So the question of CEG's ability to finance the next well is irrelevant. The licences will be extended on a drill or drop basis. As for the valuation of the licences and The Bahamas assets of $94m, This can be accounted for by the investment made in the survey data and seismics and well data. This is very valuable information and expensive to acquire. 3D data alone is circa $35m. Fortunately it is the intellectual property of CEG.

Thank God that drivel is over.

It's clear I'm upsetting ex-holders who have sold, or just hate the company and the BoD. Just in case the company gets the finances and balance sheet cleaned up, which results in a turnaround, then personally, I would like to see CEG realise it's potential and succeed so shareholders can regain their investment.

Keep going.

Keep it up, you're just proving my point.

LayLadyLay, Afraid you are inaccurate. If the oil doesn't belong to CEG then please explain the below taken from the Trinidad & Tobago Strategy Update RNS.

In August 2020, when BPC assumed control of this portfolio of assets through the merger with Columbus, the Company established a target of achieving net 2P reserves of at least 1 MMbbl by the end of 2020. The net 2P reserves of 1.29MMbbl as certified in the CPR exceeds this target by 30%.

2P reserves relate to known oil that is capable of being produced economically, and thus the 2P reserves as certified by ERCE relate solely to production capable of being generated from BPC's existing wells in existing fields. The 2P reserves do not assume any contribution from infield drilling and enhanced oil recovery projects. Moreover, apart from routine operating costs required to keep wells online, accessing this production potential does not require material amounts of incremental capital expenditure.

As such, at current oil prices of around US$40 per barrel, BPC estimate this level of 2P reserve represents in excess of US$50 million of gross cashflow potential to BPC, and a reserve base equivalent to a baseline production of 500 bopd for approximately 7 years.

Given these production and economic characteristics, 2P reserves are a readily monetizable asset, and BPC has been approached by various financing providers requesting the Company to consider the suitability of a Reserve Base Lending (RBL) facility against its 2P reserves.

Not if it's secured against an asset that has 5 X the value of say $20m

Davie46, On current production the company is cash break even and will be cash generative ie profit making in 2022. This is conditional on recapitalising financing and creditor restructure. If a company is profit making it can pay back any financing. Why would a bank not lend?

Total assets are $148.876m

The $110m has been reported as the Trinidad and Tobago Group's direct oil and gas producing and revenue generating operating segment. The Bahamas segment includes The Bahamian exploration licences on which drilling activities were conducted in 2020. The elements of the Bahamas Licences of $94m is mainly the value of the seismic data.

Bohemia, What you say is inaccurate. Exploration and evaluation or referred to as assets that have been explored for and found. The Bahamas licence fees in general are $250k per licence each year. Not $94m.

If oil was at $30-40, it would be difficult. But the fact is oil at $80 increases the value of the assets. Markets look forward as do banks and lenders. Oil is projected to keep rising in 2022 towards $100. So oil producers will be able to get finance.

It should already be at 0.5p, but if you read the interims, the restructure of the creditors and recapitalisation will be done by the end of the year.

The interims showed a $110m asset value, but this would be based on a bank deck of around $59 a barrel. So the asset value will have gone up. This discounts any reserves that may get reported at Saffron.

So exactly what I said is happening. Seismic being done this year at CH-1 which gives enough time to process it during the wet season ready to start CH-1 in 2022 Q2 or the stated Q3.

What's your problem?

You need to wait for the reserve report at Saffron and the implications of a shallow field development. The increase in oil price revalues the assets. Banks now use a price deck of $75 per barrel on valuations. You need to work out future net income (total proved) assuming $75 flat oil price. After this, a reserves report can be submitted to support a senior lending facility. This will establish a borrowing base, supported by increase reserve value, future net income, and net present value using the banks price deck.

Good luck with that.

Don't recall saying we will have seismic results by now. Show me where I've said that?

Aminex is free to have dialogue with farmout partners, which they have already reported. What has also been reported is that the payment of the outstanding gas sales opens the door for investment in the Nyuni licence. The hurdle, having been now been gotten over by TPDC by paying for the gas along with the Tanzanian government wanting investment in gas projects, means the door is open and puts Aminex assets in an excellent position.