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Permalink Reply by CB on June 6, 2009 at 7:29

More like 90%.

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Permalink Reply by Grillin' - MmmMmm on June 8, 2009 at 1:58

I agree with Jay. I'm not sure there is sufficient data that hasn't been impacted by "non-reservoir" factors. We have some wells that come on at very high rates and then the operator chokes them back due to pipeline restrictions and/or the overall gas glut. For instance, CHK has said they will not produce HS wells at more than 10 MM per day (I think that's the number, but it could be a little different). So, the put a well on and it tests 25 MM per day on their state test. They then choke it back to 10 MM per day for the first 3 months. What's the decline rate? No one really knows as the well is not flowing in a reservoir steady state.

Give us a few more months and I think there will be more data coming out that will help shed some light on this. It took us 10 years in the Barnett and 3 - 5 years in the Fayetteville. We've only been at this for a little over 1 here in the HS.

As for Matt Simmons "false NG glut", I respect the guy a lot but I don't think he's got the picture straight here. Just look at a) prices, b) storage and c) rig utilization. I'd say we have a glut for now. Could go away quickly (hopefully!!!) but for now, I'd call it a glut!

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Permalink Reply by red rider on June 7, 2009 at 18:40

ouch! 90%? is that across the board? or unique per certain wells? i recently saw a video from matthew simmons on "http://www.financialsense.com/index.html" where he mentions in a slide presentation that shale gas has a very high depletion rate. which prompted my question above. which also makes me wonder about the length of production from a horizontal well. How long would a horizontal well be expected to produce gas?

he also mentions a false natural gas glut. which i thought was interesting. things that make you go hmmm.

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Permalink Reply by Bacon on June 8, 2009 at 7:48

A related article.
http://www.fool.com/investing/general/2009/06/05/the-well-test-wall...

The Well Test Wall of Shame
By Toby Shute
June 5, 2009 | Comments (0)

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Something's been bothering me about certain press releases from oil and gas companies lately. I'm not even talking about the sickening swell of follow-on share offerings by the likes of Anadarko Petroleum (NYSE: APC), Delta Petroleum, and Mariner Energy, either.

I'm talking about the preponderance of PR that proclaims eye-popping initial production rates. The more I scrutinize the language in these releases, the less informative I find them. Some are downright misleading.

Can I see some IP?
From a stakeholder's point of view, a well's initial production (IP) rate can be useful knowledge, insofar as it provides some indication of future productivity and expected ultimate recoveries (EURs). For example, a rule of thumb in the Barnett and the Cotton Valley is that for every million cubic feet of a well's initial gas production rate, EURs bump up by a billion cubic feet.

The problem is that there seems to be no reporting standard whatsoever when it comes to initial production rates. Some companies quantify this production period (24 hours, 30 days, and so on) while others don't bother. Some report the results of a production test, which implies the use of test equipment that may or may not match real-world production conditions, while others report the average volumes actually flowing through surface equipment to sales.

A few operators even have the audacity to present a well's absolute open flow rate (a theoretical figure that generally multiples higher than the rate sustained under actual production conditions) as a proxy for the well's expected performance. If you ever see this trick, run away. Fast.

Drilling deeper
Consider Goodrich Petroleum's (NYSE: GDP) announcement following its first horizontal well completion in the Haynesville/Bossier play of Louisiana, which "tested at a rate of approximately 14.5 MMcf per day on a 24/64 inch choke with 6,000 psi." This kind of reporting leaves many questions unanswered:

What kind of test was performed? What sort of equipment was used?
Was this only one of several tests conducted? If so, is this the result of a single test run, or is it a composite?
What was the duration of the test -- 72 hours … 30 minutes ... something else?
Was the rate sustained across the entire test period, or just a portion of it?
Without more context, this test rate doesn't really tell me a lot about the well's reserve or production profile.

Mind the decline
If a well continued to produce at or near its initial production rate over the ensuing weeks and months, I wouldn't make a stink about the shoddy state of IP reporting. But the fact is, we are seeing some stunning declines in today's horizontal gas plays, even within the first weeks of production.

Cabot Oil & Gas (NYSE: COG) has drilled 50 wells in its County Line play in East Texas, with an average IP rate of 10 million cubic feet per day. The average 30-day rate is just half of that, at 5 million per day.

Haynesville shale wells, the hottest horizontal play around, tend to come online so strong, and decline so rapidly, that old rules of thumb for calculating per-well reserves are getting thrown out the window. That 1:1 IP-to-EUR ratio I mentioned earlier? According to top-tier reserve evaluators Netherland, Sewell, the ratio's tracking closer to 1:0.37.

In other words, these Haynesville well tests make for big headlines, but the EURs aren't tracking the IP number nearly as closely as many investors are used to seeing. Haynesville players such as Goodrich and Petrohawk Energy (NYSE: HK) tend to shout their often vague initial production rates from the rooftops, but I worry that these announcements don't serve investors particularly well, especially at this very early stage of development. It's far from clear today what the "average" Haynesville well will look like over the course of its productive life. Variability is actually running quite high.

I should note that the state of Louisiana invites ambiguity with its requirement that deliverability tests merely "be of such length as to determine an accurate gauge." Texas' guidelines are clearer, requiring that "all deliverability tests shall be performed by producing the subject well at stabilized rates for a minimum time period of 72 hours." The biggest, baddest Haynesville wells appear to lie mostly on the Louisiana side of the border, however.

The prudent way to play
Considering the combination of non-standardized initial production figures and dramatic early declines in many of today's hottest drilling targets, I am much more partial to the practice of reporting 30-day IP rates. That is, the average daily rate of actual production over the first month of a well's life. EQT (NYSE: EQT) stands out for its steadfast commitment to this format, and I doff my jester's cap to this company. Penn Virginia (NYSE: PVA) is good about highlighting its 30-day IP results, as is EnCana (NYSE: ECA).

As for those E&Ps that are sparing with their details, while the SEC may never force a higher reporting standard upon them, I'm going to hold them to one anyway. They're going on my Well Test Wall of Shame until they put down the pom poms and get with the 30-day program.

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Permalink Reply by Roy on June 10, 2009 at 7:14

Is it possible to model the income a landowner may expect for the life of a Haynsville well? Say an average well, one acer, normalized gas price, etc.? I don't know all the factors involved.

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Permalink Reply by The_Baron on June 10, 2009 at 8:05

Sure, but you will need a crystal ball to predict gas prices, and at this poit who know what the "average" well will be. We could talk all day about IPs and decline rates and never get to what an Average well is.

My advice....Take your royalties as mailbox money, don't bank on any supposed estimates.

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Permalink Reply by CB on June 10, 2009 at 8:09

No! Not at this time. Too many variables, especially production rate.

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Permalink Reply by Mac Davis on June 10, 2009 at 8:25

Gas prices have varied from roughly $13.69 to $3.25 over roughly the past year, so that's a 4 to 1 variation.

If you forget dollars, and try to calculate the amount of gas a well will produce, that's complicated, too.

Wells vary widely in gas production. (10:1 variation)
Wells vary widely in how quickly the output declines. (Guess at 2:1 variation)
There's not a lot of history on how long the wells will produce.
There's talk of drilling up to 8 wells per section. (8:1 variation)
etc.

You can't just add up the factors above, you'd need probability distributions and models to really add them up, but take a SWAG as it being only 10:1 variation on the gas, or 20:1 on the dollars you'll get.

One friend is getting around $200 per month per acre. Take a wild guess at the lifetime production being equivalent to 5 years of the first year's rate. That's $12000 per acre. However, it could easily be 10 times more or less. You could even end up with no production and get $0.

Another way of looking at it is that people were offering leases at $30,000 per acre. They wouldn't have been offering that kind of lease bonus unless they were planning on making a lot more than that per acre. This was when natgas prices were much higher.

The answer is, "Yes, you can model, but the uncertainty in all the factors is so high it's almost meaningless."

It would be interesting to see some more real numbers in terms of how many dollars per month per acre people are getting on actual producing, paying wells.

You can look up existing well production on sonris. Check production rates. Don't get too excited about initial production rates. Production declines rapidly the first year. There are numerous royalty calculators you can Google.

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