Nice article from seeking Alpha:

 

It seems official when you turn on the television or pick up the paper, everyone is singing a chorus that natural gas is “set to explode”. Many look at gas purely as an asset that has underperformed in an environment where commodities have soared. The problem is this; the majority of those making these claims do not understand this commodity at all. There is a reason that natural gas has underperformed and continues to do so, contrary to what popular opinion you hear otherwise, the market is always right. In doing research on the internet, I find so many articles about how the current price environment is below breakeven costs for many of the new unconventional plays. The problem I find is the estimates are all old, and based on expectations that are far outdated as we have learned best practices on how to drill and produce these plays. So I am going to update these expected breakevens with what we know at this point. Much of what I will use for estimating comes directly from company statements over the past several months.

Reading analysts expectations from 2008 and largely in 2009, there were many big name outspoken gas experts, claiming that shale would be a commercial disaster. They were largely based on expectations of very low levels of EUR (Expected Ultimate Recovery). What is now taking shape with the passage of time and using the knowledge learned, is the EUR’s are increasing through restricted choke technique and how many stages of fracture stimulations per well, with an aggregate EUR of 6.5 to 7.5 BCFe.

 

The rest of the article is at the link below.

 

http://seekingalpha.com/article/239231-estimating-the-breakeven-cos...

Tags: Breakeven, Costs, Estimating, Gas, Shale, of, the

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Good find Alongview. If his numbers are anywhere near correct (which he seems to defend aggressively and with logic in the comments below the article) then that would certainly change some fo the rumors we've been hearing about some of the operators being "upside down" in acreage with gas being below $6/$7.00 per mcf. Let's hope so.

I think he did leave the "export" part of the equation out and the role it could play in using up supply when there's a domestic glut. It'll be an interesting next 10 years.
AL, thanks for posting. Here are a few comments/observations.

The break-even NYMEX value for a Haynesville Shale well is ~ $4.35 per MMBtu based on a 10% ROR and exluding lease bonus. Throwing $5k/acre bonus on the 1st well would increase the NYMEX break-even value to $5.81 per MMBtu but I consider the bonus irrelevant since it is a sunk cost.

The crude oil to natural gas price linkage was broken in the US around 2000 due to the replacement of most of the oil fired power generation. The linkage still exists internationally (~ 60-65% parity) due to the nature of long term gas sales contracts.

The movement to natural gas in the power generation market could occur rapidly if we just increased the run rate of the exisitng gas fired generation fleet. Some switching has already occured temporarily in 2010 due to the low natural gas price.

It is true some rig migration is occuring from the Haynesville Shale to the Eagle Ford Shale but is not likely to occur for the Marcellus Shale. The Marcellus can use smaller drilling rigs and other factors will limit the rate of build-up for rigs in that play.

Yes, the (Mid) Bossier Shale lies above the Haynesville Shale but not for the entire HS play area.

Some areas of the Haynesville Shale play were already held by operators (Petrohawk, Questar, Exco, Comstock, Goodrich, etc) due to older developments in shallower formations.
Les, What does the "gas factory" do to the break even price? What are the likely outcomes from E & P's effort to decrease costs? I know Encana talked about building/owning Haynesville specific rigs etc. Thanks.
AL, in the long term the "gas factory" could reduce capital costs. A $1.5MM drop in the capital cost would lower the break-even price by $0.60 to $3.75 per MMBtu.

Actually I believe EnCana is talking about building and owning pumping equipment used for fracture stimulation.
That is significant and is obviously the reason the big players are testing it. The real question then becomes what does the gas factory do to the already bloated inventories? Does it offset any reduction in capital costs with a depressed gas price? Six of one , half dozen of another!
Les,

The author of the article includes the variable rates for lease bonuses per acre. Are you doubling up on that? Or how are you coming up with the higher number ? CHK has a history of claiming 6.5 BCF per section. If that played out, and there average lease bonus per acre was $5000.00 it looks like on that guys chart it would put the breakeven price of NG at about $2.50 or so. I seem to recall an investor relations piece from CHK stating that their average cost per acre across the play was about $4500.00/acre when you factor in the deals they've made with other operators to do JV's on the acreage and pick up drilling costs while staying on for the ride. (PXP being one.)

So what am I missing between his numbers, yours and what CHK has told their investors? Just trying to put two and two together.
HMI, I believe the author has admitted his analysis is not sufficienly rigorous for a true break-even price since he did not include operating cost or the cost of capital - hence his low numbers.

Chesapeake generally shows F&D cost per Mcf rather than break-even price so a different parameter. As stated above I do not believe the bonus (ie Chesapeake's $4500/acre) is relevant since it is not part of decision case economics but I did show the break-even price both with and without bonus for comparison.
Thanks Les. So let me ask you, wouldn't the fastest way for an operator to get into the black on leaehold be to drill two wells per section to get their average cost per mcf down (at least on paper) assuming that there is infrastructure available to get the gas to market and a market for the gas?
HMI,
Yes, the operator will recoup costs on leasehold by drilling 2 wells per section. But many of the operators don't have that luxury. They leased up a gazillion acres, and are drilling as fast as they can, with one well per section, to HBP the leases before the primary term expires. A lot of leases will expire in 2011. CHK, ECA/SWEPI, and HK are all drilling to hold leases. With a few exceptions, most landowners who have these companies as their driller, won't see the second well for a while. Maybe a long while.
Yep, I understand that Henry. Some operators are behind the eight ball. While some others already have multiple stems in individual sections. I'm on the waiting list on mine and I doubt they get to us prior to our mid-May expiration in 2011. Which is fine, I like lease bonus money as much as the next guy. :-)
Henry, just so you know - a lot of leases have already expired in 2010 so I believe some companies such as EnCana are already transitioning to pad drilling mode.
Why will they not see the second for a long while?

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