Art Berman is a geological consultant whose specialties are subsurface petroleum geology, seismic interpretation, and database design and management. He is currently consulting with a wide range of industry clients such as PetroChina, Total, and Schlumberger. Mr. Berman has an MS in geology from the Colorado School of Mines and is active with the American Assoc. of Petroleum Geologists. Art spoke with us last Thursday after a presentation in Canada at the CIBC Technical Conference.

POR: Can you give us your latest updated perspective on the shale gas story?

Art Berman: You have to acknowledge that shale gas is a relatively new and significant contribution to North American supply. But I don’t believe it’s anywhere near the magnitude that is commonly discussed and cited in the press. There are a couple of key points here. First the reserves have been substantially overstated. In fact I think the resource number has been overstated.

If you investigate the origin of this supposed 100-year supply of natural gas…where does this come from? If you go back to the Potential Gas Committee’s [PGC] report, which is where I believe it comes from, and if you look at the magnitude of the technically recoverable resource they describe and you divide it by annual US consumption, you come up with 90 years, not 100. Some would say that’s splitting hairs, yet 10% is 10%. But if you go on and you actually read the report, they say that the probable number-I think they call it the P-2 number-is closer to 450 Tcf as opposed to roughly 1800 Tcf. What they’re saying is that if you pin this thing down where there have actually been some wells drilled that have actually produced some gas, the technically recoverable resource is closer to 450. And if you divide that by three, which is the component that is shale gas, you get about 150 Tcf and that’s about 7 year’s worth of US supply from shale. I happen to think that that’s a pretty darn realistic estimate. And remember that that’s a resource number, not a reserve number; it has nothing to do with commercial extractability. So the gross resource from shale is probably about 7 years worth of supply.

For a project that a colleague and I did for a client, I actually went in and looked at all the shale plays and assigned some kind of a resource number to them. I also used some work that was done by Wendell Medlock at Rice University’s Baker Institute. He did an absolutely brilliant job of independently determining what the size of the resource plays in Canada and the US might be.

The resource hasn’t been misrepresented but the probable component has not been properly explained as a much smaller component of the total resource; I guess they just didn’t read the PGC’s report carefully enough. If you take the proved reserves plus the report’s probable technically recoverable number, we have something like 25 years of natural gas supply in North America, which is quite a bit. It’s a lot. I don’t say any of this to give shale gas a bad name.

The other interesting thing about the PGC’s report that nobody seems to pay attention is this: they said there is something like 650 Tcf of potential shale gas. Well, there’s 1000 Tcf of something else. What’s the something else? It’s conventional reservoirs plus non-shale/non-coalbed-methane unconventional reservoirs. So there’s 70 percent more resource in better quality rocks than shale. It just astonishes me that nobody has paid any attention to that.

So that’s the simple view. And then the other thing that we see empirically is that if you look at any of these individual shale-gas plays-whether it’s the Haynesville or the Barnett or the Fayetteville-they all contract to a core area that has the potential to be commercial that is on the order of 10 to 20 percent of the geographic area that was originally represented as all being the same. So if you take the resource size that’s advertized-say for the Haynesville shale, something like 250 Tcf-and you look at the area that’s emerging as the core area, it’s less than 10 percent of the total. So is 25 Tcf a reasonable number for the Haynesville shale? Yeah, it probably is. And it’s a huge number. But the number sure is not 250 Tcf, and that’s the way all of these plays seem to be going. They remain significant. It hasn’t been proved to me yet that any of it is commercial, but they’re drilling it like mad, there’s no doubt about it.

Those are sort of the basic conclusions. And when you look at it probabilistically, which I think is the only intelligent way to look at anything which you have any uncertainty about, what you realize is that the numbers that are being represented by all of these companies as “truth” are probably like the P-5 case, having a 5 percent probability of being true. So they say, “well, our average well in the Haynesville is going to be 7 Bcf,” and I say there will certainly will be wells that make 7 Bcf but there’s no way that the average is that high. My take is that there will probably be 5 percent of wells that will make 7 Bcf.

I just think everybody is caught up in this. I have a slide where I say, you guys need to get over the love affair and get on with the relationship. You keep talking about how big it is and how great it is, but at some point you have to live together and that’s hard work. You have to be honest with yourself and with each other and you have to do some work. I just don’t think we’ve moved past the love affair.

One other important thing is the Barnett shale. We keep coming back to it because it’s the only play that has much more than 24 months worth of history. I recently grouped all the Barnett wells by their year of first production. Then I asked, of all the wells that were drilled in each one of those years, how many of them are already at or below their economic limit? It was a stunning exercise because what it showed is that 25-35% of wells drilled during 2004-2006-wells drilled during the early rush and that are on average 5 years old-are already sub-commercial. So if you take the position that we’re going to get all these great reserves because these wells are going to last 40-plus years, then you need to explain why one-third of wells drilled 4 and 5 and 6 years ago are already dead.

POR: When you say one-third of the wells are already sub-commercial, do you mean they have been shut in, or that they are part of a large pool where no one has sharpened the pencil?

Berman: Some of them never produced to begin with. No one talks about dry holes in shale plays, but there are bona fide dry holes-maybe 5 or 6 or 7 percent that are operational failures for some reason. So that’s included. There are wells that, let’s just call them inactive; they produced, and now they’re inactive, which means they are no longer producing to sales. They are effectively either shut-in or plugged. Combined, that’s probably less than 10 percent of the total wells. But then there are all the wells that are producing a preposterously low amount of gas; my cut-off is 1 million cubic feet a month, which is only 30,000 cubic feet per day. Yet those volumes, at today’s gas prices, don’t even cover your lease/operating expenses. I say that from personal experience. I work in a little tiny company that has nowhere near the overhead of Chesapeake Energy or a Devon Energy. I do all the geology and all the geophysics and there’s four or five other people, and if we’ve got a well that’s making a million a month, we’re going to plug it because we’re losing money; it’s costing us more to run it than we’re getting in revenue.

So why do they keep producing these things? Well, that’s part of the whole syndrome. It’s all about production numbers. They call these things asset plays or resource plays; that reflects where many are coming from, because they’re not profit plays. The interest is more in how big are the reserves, how much are we growing production, and that’s what the market rewards. If you’re growing production, that’s good-the market likes that. The fact that you’re growing production and creating a monstrous surplus that’s causing the price of gas to go through the floor, which makes everybody effectively lose money….apparently the market doesn’t care about that. So that’s the goal: to show that they have this huge level of production, and that production is growing.

But are you making any money? The answer to that is…no. Most of these companies are operating at 200 to 300 to 400 percent of cash flow; capital expenditures are significantly higher than their cash flows. So they’re not making money. Why the market supports those kinds of activities…we can have all sorts of philosophical discussions about it but we know that’s the way it works sometimes. And if you look at the shareholder value in some of these companies, there is either very little, none, or negative. If you take the companies’ asset values and you subtract their huge debts, many companies have negative shareholder value. So that’s the bottom line on my story. I’m not wishing that shale plays go away, I’m not against them, I’m not disputing their importance. I’m just saying that they haven’t demonstrated any sustainable value yet.

(Note: Commentaries do not necessarily represent the ASPO-USA position.)

12 thoughts on “Interview with Art Berman – Part 1”

  1. There’s so many aspects to this — I hope Mr. Berman will again be at the conference in October. Some things off the top of my head ..

    1) I watch the NYMEX natural gas prices and keep seeing the same thing … dirt cheap natural gas under $5/million BTU, and wonder if it isn’t the energy play of the century being missed by so many, especially the big-money investors. We also appear to already have large quantities of gas in storage, and how long would that gas last in a deeply cold winter.

    2) The videos are now coming out about the nasty chemical combinations you need to do inject with this hydralic fracturing, how some of those chemicals are ending up in the water aquifers, and how long it will be before the government starts restricting all this frac-ing.

    3) Both gas and oil demand are down due to lack of industrial output. Is there any economic reason our industrial demand would rise because of a bettering economy, or has the horse left that barn and we will continue to use less and less natgas in industry because so much business has already left North America.

  2. Arthur, In the entire history of the O&G business, it’s the good 10-20% of the wells that compensate for ‘the dogs’. However, I respect your questioning nature and willingness to think independently. Because industry has to show that they are paying both the drilling AND the leasing costs there could easily be a bias leading to overstated results. You did a nice job of making that case.

    And as I search for O&G companies that are being run conservatively with debt/equity ratios less than 50%, the list is short. Because the leverage mimics our overall economy, risk is increased and I thank you for mentioning that in your analysis too.

    Looking forward to Part II.

  3. Art is very analytical and knows what he talks about. I agree. The shale plays are not totally evaluated and it is questionable that the ultimate recoverable reserves are as high as projects say.

  4. Huge debts can really bite unsuspecting share owners of any mostly shale gas companies, should interest rates rise due to some unexpected crisis. I’m no expert, but investing in them sounds a lot riskier than a lot of people think. The perfect storm of events, and you might find your stock value at $0. Remember the flash crash? Those computers can sell your stock down instantly.
    When I first read about shale gas, I found it hard to believe that a rock as dense as shale could produce any gas at all, much less produce gas for years. It seems my initial hunch was nearly right. Now I suspect it will be like oil shale, uneconomic until the cheap stuff can no longer supply the demand, and the price explodes. With gas, that could take a good while, with LNG having already been perfected.

  5. With the example of the BP disaster before us all, anyone with any sense should be concerned about worst-case scenarios occurring in shale gas areas, particularly heavily populated shale gas areas like the Marcellus. We have already had cases in which people have lost their water supplies, effectively rendering their homes worthless. In PA, water wells have exploded. A blowout occurred recently in Clearfield, PA; a similar blowout in a heavily populated area would be catastrophic.

    I live above the Marcellus Shale in upstate NY, and I assure you there are plenty of people here who will sue if their property and/or health are damaged. In PA, huge horizontal well pads are being constructed right next to homes and schools and busy roads: common sense seems to be in very short supply in the shale gas industry. If they keep on operating like this, a disaster is almost inevitable.

  6. Art is hammered by many within the e&p industry but I think he is sincere. There is no doubt that there are wells in the core areas of some of these shale plays which are going to be good money-makers and Art has recognized that. He is looking at the overall big picture and has come up with a different opinion versus the e&p companies. Who will be right, long-term is hard to predict but I definitely consider his position. Art seems to be a very nice guy in a world that can be quite ugly. As one who owns mineral rights in shale plays, I hope he’s wrong, haha.

  7. I think this rush to unconventional sources of energy shows our desperate situation. We drill miles deep under water, we dig up sand in ALberta, and squeze petroleum out of it. And now the shale gas plays, where companies received a blank check from the EPA to do whatever it takes. To drill those expensive holes, we have to lie about the potential payload, to atract investment, therefore we say that there is enough there for 100 years.

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