Potential not Promotion (read this again and again)An excerpt from Shaw's blog. If you own shares, read this blog.....then read it again. Then remind me why you are holding your shares. Nothing is 100% but this has potenital beyond belief.
https://hydracapital.ca/hydra-blog/valeura-energys-thrace-basin-discovery-putting-all-the-pieces-together https://hydracapital.ca/hydra-blog/valeura-energys-thrace-basin-discovery-putting-all-the-pieces-together
I said I would get around to valuation and I promise I’ll get there soon. First though, you have to realize that the well costs on Yamalik-1 well are like “prototype” costs on a new invention or vehicle. Time and time again, the energy industry has demonstrated what the drilling cost evolution curve looks like as a play develops. Initial wells are investments in learnings to be applied to future development… and economies of scale kick in once you get into operations like pad drilling. A lot of people might look at Valeura and wonder what all the excitement is about when a $25 million well produces a few/several mmcf/d of gas with 40-50 bbls/mmcf of condensate, but they would be missing the point. With pad drilling, Cormark analyst Garett Ursu has suggested that well costs could fall into the $6-8 million range and there’s very good precedent for that. At $7 gas, if you can drill wells for $8 million in naturally fractured areas that come onstream at 20 mmcf/d and have an ultimate recovery of say, 10 BCF, you could get payouts of under a year and F&D costs of something like $5/boe. I get those numbers based on looking at a number of U.S. tight gas plays. Netbacks will probably be something like $25/boe in Turkey. That’s completely ignoring condensate so as to leave lots of margin for error and I think I may actually be conservative on flow rates and EURs for wells with pervasive natural fracturing.
Now imagine a time, not that far from now, when Statoil decides they want to do a pilot pad development somewhere in the Banarli block. Let's further imagine that they choose the location of this pad to be over an area that they expect to be naturally fractured, based on their 3D seismic coverage. Not right down the throat of a fault or anything, but close enough such that they are in one of the fractured “corridors” that have formed over time as the Thrace Basin has been pushed and pulled by large-scale tectonic forces. Eight wells per pad might be a decent place to start based on other comparable developments. That would mean that one pad could conceivably represent 160 mmcf/d of initial production. If your pilot pad development goes well, it’s onto full development.
In development mode, tight gas does have steep decline rates, but once you have multiple pads going, your flush production just blends into your overall production profile. And what does it cost to build the pad and drill those wells? At $8 million a well in full development (remember that we’re not even talking about horizontal wells here in this example), that’s $64 million per pad. Now, what if you had 5 or even 10 pads going like that? Even with declines you’re talking about 0.5-1.0 BCF/d of production (100% basis) that’s throwing off at least$4/mcf in cash flow (again, never mind the condensate). That’s $2-4 million a day, or $700 million to $1.4 billion a year… and what’s the capex for that? $320 million for a 5-pad case and $640 million for a 10-pad case. Then you have to add in capex for pipeline tie-ins and some processing facilities… let’s just throw $300-500 million at that. Seem fair? All-in, in very, very rough numbers let’s just say that initial development costs a cool billion dollars and then you’re up and running for 20-30 years or so (365 BCF/year at 7-10 TCF recoverable).
Payback is maybe a year-and-a-half or two in the above example once you’re operationally and logistically prepared. Where else in the world could you spend a billion dollars and have it come back to you that quickly? And how about the next year when your facilities capex is out of the way and you’re just doing maintenance drilling? Two words. Gravy train. That’s how I think a supermajor (Statoil 100% or Statoil+1) could turn one billion dollars into billions here. It’s embarrassing to actually put numbers like this out there at this stage because it’s so early, but unless I run some kind of hypothetical economic case, how am I to know when I think Valeura is under- or overvalued based on the data that I have to work with?
Given that I’m comfortable that this is a BCGA, and that my thoughts and assumptions regarding initial development are reasonable to me, I can easily see a world where Valeura is valued at $1 billion for its 50% interest and would still look like an attractive buyout target. At a $1 billion valuation any buyer would need to also account for $500 million in net initial capex (drilling plus facilities) so they’d be in for $1.5 billion to have 0.5 BCF/d of production coming to them. That implies capital efficiencies of $18,000 per boe per day including the acquisition cost. In the following years, with capex and acquisition capital treated as sunk costs, the buyer would be looking at perhaps $250 million (max) in net drilling and maintenance capex versus net cash flow of $730 million per year using 0.5 BCF/d with $4/mcf netbacks. If you run an NPV10 on that 0.5 BCF/d for a 20-year development, you get around $3 billion (net to the 50% interest). So, just to reiterate, a buyer could pay $1 billion for Valeura and capture a $3 billion NPV10. This is not about picking up dimes and quarters folks, these are the large-scale numbers that major energy companies need to work with. Think a BCF per day (gross) out of a BCGA is too high? Consider that the Piceance Basin produces around 2 BCF per day and has been held up as one of the possible analogues for the Thrace, so I don’t think the numbers are totally ridiculous. If you wanted to step production up to say, 2 BCF/d in a future development phase, you could likely nearly double the NPV of the project, but the numbers seem good enough already.
BCGAs are really their own animals in a lot of ways, and once you understand them on a large scale, you know just how much gas they can deliver if you put enough technical work, money, and pipelines into them. I am fully aware of the number of assumptions within my back-of-the-envelope development scenario that’s outlined here, but I have to start from somewhere. It may take longer than I think, but if this BCGA is real, I think that my numbers are in the ballpark. First you have to understand the “micro” technical data (the rocks, the well results, the potential productivities, etc) and then you zoom out and start looking at the whole basin as “the thing”, not the wells within it. The basin is just the sum of the wells and if you’re confident in the capability of the wells, then you’re confident in the capability of the basin. Once you get to that point, you’re thinking in billions, not in millions of dollars.
That’s what I think the supermajors know and it’s what I think will bring them to the table sooner than most people would think. When you’re a big fish in an ever-shrinking pond, you have an insatiable appetite for big projects that can move the needle and deliver good returns for your shareholders. The problem is that assets like that are hard to find and a lot of them are in regions with limited or non-existent infrastructure, marketing challenges, and/or poor fiscal terms. The fact that Valeura’s Banarli project just happens to be surrounded by regional gas pipelines is like a gift from above. And how can it get better than finding a giant resource play in a country that imports 99% of its ever growing gas needs that also happens to be on the doorstep of Western Europe?
The bottom line is that once you wrap your head around the BCGA concept and are comfortable that this is truly a nascent resource play, you can start thinking of Valeura as a vessel that can take massive amounts of capital and return them to you with a nice profit. The well details at that point are just details, and Valeura and Statoil might only be one or two wells away from drilling a vertical well into one of these structural corridors where the Thrace will really show what it can do.
Does a supermajor step in before that well is drilled? Quite possibly. If I learned anything while doing my studies in geodynamics, it’s that there’s no doubt that the rocks in the central Thrace have been put through some pretty major tectonic forces over time and that there’s a very good chance that there are some very fractured rocks down there. If I know that, then there’s no doubt a guy smarter than me at any one of many supermajors that knows that, and he’s the guy who will be part of the team whose job it is to identify and capture assets like these before anyone knows how much they’re really worth.