(Disclosure: The following represents my opinions only. I am not receiving any compensation for writing this article, nor does Hydra Capital have any business relationship with companies mentioned in this post. I am long VLE.TO)
As Valeura Energy (VLE.TO, last at $3.05) continues to trade near multi-year highs on record volume, a lot of market participants and observers are scratching their heads wondering just what all the excitement is about. That’s understandable. It’s a big market out there and no one can follow everything, especially at a time when the words “small cap energy” have been synonymous with “bubonic plague” for a few years now. There are a few specialists that have kept candles burning for domestic energy juniors, but there are even fewer that even remember the concept of what being an international energy junior is all about. Having been an international energy equity analyst in a former life, I happen to be one of the few people that remembers why you follow these obscure international junior energy companies. It’s because once in a blue moon, and I really mean once in a blue moon, one of them finds something mythical. It might be a giant offshore oilfield, an untapped oil structure in Utah, an oil strike in the jungles or deserts of Africa, or, in Valeura’s case a giant tight gas play on the doorstep of Western Europe.
Many companies try to make world-class discoveries and most fail miserably, but that’s just the nature of the exploration game. It’s knowing who these companies are and what they are up to that makes all the difference to a good speculator. Risk, as is usually the case, is commensurate with reward and I’ve said before that if you truly understand what you own, you are far more likely to be a successful speculator. It’s of little use if you spend years stalking a story (I’ve followed Valeura since 2010) to make a quick 30-50% gain and be gone. In Valeura’s case, I highlighted earlier this year that things had become quite skewed in the long’s favour and boy have things ever come together. Valeura is up over 500% since its October lows and is certainly one of the best performers on the TSX this quarter. The crazy part is that, if you’ll forgive the pun, there’s probably more gas in the tank… while more people have clearly discovered the story, it’s still far from mainstream given its low market cap and relative obscurity.
Valuation on international energy discoveries is always a challenge. Fiscal regimes, capital costs, infrastructure access, operating conditions, and pricing are all highly variable, and that can make it hard to make apples to apples comparisons with similar assets in other jurisdictions. There’s also the fact that international energy stories often require a fair degree of technical knowledge to evaluate or even understand, meaning that the line between “value” and “potential value” becomes blurry since it is interpretation dependent (and there’s almost always far less data than a domestic play). Of course, when it comes to exploration discoveries, more data is always better, but the market makes you pay for that data in the form of a higher, or lower, share price. So if you can come to the same conclusion of value with less data than “the market” needs to come to its own conclusion, you’re probably going to make money. That means you will need to be able to do more with less, which takes hard work… but the rewards can make it worthwhile.
International energy stories live in a world where probability, geology, economics, geography, and finance meet. Once you’re comfortable enough with the geology that you feel you’re in the ballpark in terms of scale, you can crunch some high level numbers to get a sense of the quality of the commercial opportunity to see if it even makes sense. It’s back-of-the-envelope math/art at the beginning, but the numbers are usually big enough that even being generally right is a good place to start. Ultimately, an industry player will tell you if you’re right in the form of a buyout by a major – the dream of most junior international energy explorers.
When it comes to the Thrace BCGA that Valeura and Statoil have discovered, the first key is in understanding what a BCGA is… it is a Basin Centred Gas Accumulation. Google will tell you anything you want to know about a BCGA, but the most important part is that they are just what they sound like they are, basin centres that are full of gas. If you think of a basin as a giant bowl that is filled by many, many layers of sand and shale over time, you’ll have a reasonable visualization in your head. In that basin, below a certain level all of that sand and shale is full of gas that can’t escape and leak out into the layers above. Every pore space available down there is full of gas. It takes the usual exploration risk (i.e., Will I hit gas?) right off the table. Think about that for a minute. Wherever you drill within the BCGA cell, the rocks will be gas bearing… the only thing you might look for is a place to drill where you think you can get more gas than elsewhere… or maybe a better liquids yield. The gas is deep in the basin and typically in tighter (i.e., less porous and permeable) reservoirs than one might expect in a conventional field, but the pressures are high because the gas can’t escape through the overlying regional pressure seal. When you drill into these reservoirs you can either fracture stimulate them to unlock the gas, find naturally fractured reservoirs, or do both. It’s just about productivity and maximizing return. BCGAs are commonly exploited in North America, but abroad they have been elusive, at least partially because they are difficult to identify/recognize with limited drill data. The excitement about the Thrace BCGA is being driven by the understanding of just how large these BCGAs can be and how profitable they can be to develop.
Once you convince yourself that the Thrace BCGA is for real, you can start to think about how it might be initially developed. The BCGA cell covers some 1,600 square kilometres, maybe less if you pare it down to the thicker parts of the basin, but in any case it’s a huge area. So where do you start? Well, obviously you want the best rock you can find with the best flow potential, but where the heck is that? In terms of the best rock, you probably want to balance proximity to the sediment source in the interval(s) of interest (i.e., sand content) with distance from the centre of the basin where the overall sedimentary package is its thickest. But that still leaves a huge area – how do you place an “X” on the map for your first development pad?
This is where things get a little more technical. The geodynamic/tectonic history of the Thrace comes into play here. I won’t go into the gory details, but importantly, there are multiple NW-SE trending fault zones crossing the Banarli licenses. Valeura has these large faults indicated as thick grey lines on some of its presentation materials (see below). Those fault zones have accommodated the tectonic stresses that have acted on the Thrace basin over time and are likely to have created a network of natural fractures and micro fractures throughout much of the basin’s BCGA cell. Logically, one would expect fracture density to increase adjacent to these fault (or flexure) zones… and fortunately logic works here, because that exact strategy has led to the drilling and completion of a number of very prolific wells in a number of North American resource plays. So if early development might target natural fractures… how will they target those? Answer: With 3D seismic.
How many times have you heard about wells with high flow rates being spoken in the same sentence as the presence of natural fractures? Wells drilled into highly fractured areas in comparable plays can produce at rates in the range of several tens of millions of cubic feet per day. If I were Statoil, I would already be thinking about an initial pilot development in an area like that, or a test well at the very least. Being somewhat close to a fault, Yamalik-1 shows some limited evidence of natural fracturing, but even closer to the fault you would expect the fracturing to be even more pervasive, which is what could lead to productivities that are many multiples of what Valeura and Statoil are already seeing at Yamalik-1… and that’s really something to think about, because the early results continue to exceed all pre-drill expectations where extrapolated fully completed well rates could already be in the 10+ mmcf/day range.
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.
I’ll likely be accused of being a dreamer for putting something out there like this that requires as many leaps of faith as I have taken here, but a friend of mine likes to say that he doesn’t know any billionaires who are pessimists, so maybe I’m on the right track after all… time will prove me right or wrong, but at least I'll have a record of what I was thinking in the early days.