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Oil still possible and some back of the envelope valuation for InterOil

February 4th, 2010 · 6 Comments

Turns out they couldn’t isolate the oilzone…
In a message board post (we can’t guarantee its authenticity, but we have to say the IV board is usually a paragon of civility compared to Yahoo) containing an update from Stansberry, one quote really peaked our interest:

They didn’t find the oil they wanted, because they couldn’t isolate the section of the well that holds the oil. The rocks in the well are so holey that the fluids flow around the “packers” (inflatable tubes that should prevent fluids up the well from flowing down and contaminating a well test).

This is actually something we ourselves speculated on three days ago because:

  1. According to Morgan Stanley, 7% porosity (in the post we wrongly assumed 6%) is enough for oil to flow from the vertical well
  2. DST#3 didn’t produce any oil flows.

So either Morgan Stanley was wrong, or there must have been some mechanical problem. This is now confirmed by Stansberry at least. Wayne Andrews earlier described the same problem at Antelope1 (in a famous undercover interview by a hired detective by the shorts, thanks to ‘Palmducks’ for pointing that out):

“A drill stem test is they have open rock sides on the walls of the wall bore and you try to set a packer so you can isolate what’s below. You test just a certain section of the wall bore. That really hasn’t worked well for us because the rock is very porous and as soon as you set a packer, the pressure goes around the packer through the pore space and eventually eats away a channel so that you really can’t isolate the zone that you’re testing, but they do a set casing and we’ve just done that and we should have more drilling results here probably next week. I think it’s the best way to test a wall bore. It’s the only way, in fact, to test the wall bore.” [p.2]

“But it is a big field. Several, 15 miles long and like 6 miles wide. So it’s still a big field, but what’s of particular interest to us is what is the composition of the hydrocarbons lower in the reservoir. When we flow the well, all the flow comes from up here because it’s so porous. We’ve been trying to isolate zones in the well bore down here with packers that I told you about, right? Then we just have not been able to get a good test although we’ve seen encouraging increases in condensate. Condensate is essentially a light sweet crude oil. It’s very hot. It’s almost like a natural gasoline. Where we are today is we sampled in the first side track that we did, we did a test down in this zone right in through here, that black area, we tested oil there. We tested oil. We were seven feet from the old wall bore that we have cemented in, cemented it, drilled the side track. We’re seven feet away. We’ve pumped a huge amount of water into the well while we’re drilling it. So if it was contaminated right near the wall bore. We just drilled another side track. Now we’ve over, I think we’re 100 over 100 feet away from the old wall bore and it should be uncontaminated rock. We tested this zone right here with drill stem tests. We saw surges of condensate as high as 25 and as high as 100 barrels per million cubic feet in our last test. They didn’t last very long because, like I said, the channel behind the packer and all that gas from up here came around. So we’ve cemented a liner, a casing, right down to this point right here and we can perforate this zone and retest it, but what we’re doing today and maybe even tomorrow is drilling from outside that liner into this zone where we tested oil a couple weeks ago in the first side track.” [p.10]

We’ll wait until they’ve figured out where the oil water contact is, and then the results from horizontal drilling. But all is not lost yet.

Now, here is a little valuation exercise to entertain you:

Consider the following quote from a Bloomberg interview with Aldorf, the new LNG guy at InterOil:

[“The Liquid Niugini project has a free-on-board breakeven price of about $2.25 per million British thermal units, by far one of the lowest for a proposed venture, Aldorf said. That compares with $7.49 per million Btu for a rival Papua New Guinea LNG project by Exxon Mobil, including upstream, pipelines and the plant, according to Wood Mackenzie.”]

(Note: One million BTU is roughly 1Mcf)

What does it tell?

  1. The Exxon/OilSearch LNG project just took the final investment decision and is considered highly profitable even with a break-even price three times that of InterOil. No wonder, as it receives in the order of $12 per Mcf for it’s LNG, which still gives it over $4 per Mcf in profit, a 50% margin
  2. So InterOil’s LNG project, which is at least as big but budgeted at half the cost has a large cost advantage. This means that per Mcf of LNG sold, the pure profit of such project could be $12-$2.25 is almost $10 per Mcf…

So InterOil has stuff that cost just over $2 per Mcf and which it can sell for $10-$12 per Mcf (To give you an idea, the Australian Gorgon project sells it’s gas for $16 per Mcf but has much higher cost).

Now, since there is likely to be around 10Tcf of the stuff of which some 5Tcf net to IOC, that’s a cool $40-$50B of lifetime profits for IOC. Of course this has to be heavily discounted as it is a future income stream (it also has to be multiplied by a sensible p/e ratio as we’re talking about profits here!), but it gives you a sense of the value that is there.

Even assuming just a $5 margin per Mcf (hardly better than OilSearch!) and on the 1Bcf of gas or so that would go into the LNG plant daily, that’s $5M a day, or more than  $1.8B a year or almost $1B a year as the ownership stakes stands now. And this is assuming the IOC plant is hardly more profitable than the much more expensive OilSearch one, so really very conservative.

But it could get quite a bit better still:

  1. Liquids stripping, once in full flow with a number of wells producing, could very well significantly lower the cost price. You have to remember that liquids have to be stripped anyway before the gas is send to the LNG plant and that once that plant operates, the gas doesn’t need to be reinjected anymore (which is by far the most expensive part of the initial liquids stripping project). Once the LNG plant operates and they do not need to reinject the gas, liquids could probably be stripped for way under $10 per barrel and sold at roughly equal to the oilprice. In Qatar, liquids stripping makes the gas essentially a free good.
  2. There are other fuels, like propane and butane to be won from the gas.
  3. IOC could very well discover additional gas over this lifetime of the project (or way before that, as early as the end of this year when they plan to start drilling other structures). They have over 40+ promising drilling sites and those who’ve seen the seismics argue that these are the real crown jewels of InterOil.

Tags: IOC

6 responses so far ↓

  • 1 Harold Chamberlin // Feb 5, 2010 at 1:18 am

    STP-Is it possible they still haven’t reached the Hydrocarbon water contact? The water they encountered is being sent to the lab for analysis. I assume they want to see if it’s their own water they pumped in, or water from the anticipated aquafur (SP). If the lab indicates it’d their own water, doesn’t that change the whole game again? Thanks Harry

  • 2 admin // Feb 5, 2010 at 2:44 am

    Yes, that’s possible Harold, although we have no clue as to the chances of that scenario..

  • 3 Tahir Rizvi // Feb 5, 2010 at 4:35 am

    IOC management has been honest and fair to the stock holders and I stand by IOC and its management. There are always those who will “short” the stock and bad mouth the Company management but we the investors should always rely on the honest data furnished by the Coompany.

    Let those who are shorting the stock loose and let good work of the hardworking IOC workers be rewarded.

  • 4 palmducks // Feb 5, 2010 at 5:50 am

    Great info! Have a question. I’ve been playing with some of the info that Petengr1 has posted in trying to estimate where the true formation water contact might be. I am not yet convinced that 7760 ft (2365 m) in Ant 2 is that point, and obviously neither are they. Unless:
    Diagrams such as on slide 17 of the 2010-10-20 show the Antelope platform pitched up from the Elk end and speculation and proof so far shows this causes the Reef Porosity (dolomite/limestone) to be pitched downward causing the dolomite to be closer to the potential heavy liquids/oil zone. Does the old theory that water seeks its own level apply in these fault systems where the formation water would be level across the formation and end up being closer to the dipping dolomite? If so this might explain the higher than expected formation water contact if that is what we have. Same question would apply to the heavy liquids/oil zone. Would that be tilted at the same angle as the Antelope platform, or run level? In slide 17 there is a tilt to what they show as the “oil leg” but not as much as the platform itself. Would this zone be trapped and tilted with the formation, thus making it run into the level (assumed) formation water by the time you get somewhere near Ant 2? Obviously I am not knowledgeable in formations (like pet, you or others might be), but any answers would at least satify my curiosity (or shut me up).

    Really enjoy this whole exercise in learning.

  • 5 kencooksam // Feb 6, 2010 at 12:03 pm

    As far as more NG I think the IOC slides tell the tale. Four of the surrounding structures connect to Elk/Antelope..This info from the news seismics.and posted on newer IOC slides.We already have enough NG for a multi train LNG plant..Makes ya wonder where all this ends up..

  • 6 palmducks // Feb 6, 2010 at 4:53 pm

    On my post above; petengr1 gave me some links to earlier discussions on the other Board that were very helpful. He feels that Gas/Heavy liquid contact and heavy liquid/water contacts are level across the formation as evidently 99.9% of the time that is the case.

    Mid-March cannot come soon enough. The updated estimates (and hopefully booked reserves) will blow the top off of this stock.