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Estimating the Breakeven Costs of Shale Gas

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 The problem I find is the estimates are all old, and based on expectations that are far outdated as we have learned best practices on how to drill and produce these plays.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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Oil & Gas ProPermalink Reply by Les Bamburg on December 1, 2010 at 15:50
SS, it depends completely on your location. Some lease holders will see their 8th well this year while others will wait a long time for their 2nd. The operator will establish his priority for drilling.

Oil & Gas ProPermalink Reply by Les Bamburg on December 1, 2010 at 4:14
HMI, each operator's situation and philosophy is different so there is no one answer. Remember that there is a cash flow profile and an earnings profile for a company. For earnings, being able to book reserves is a big factor in reducing their overall F&D unit cost.

I think for cash flow purposes most operators would like to get into the pad drilling mode as soon as possible which generates the highest efficiency and lowest cost. For each operator their pad mode may be different regarding number of wells per unit/section. Some may delay moving into that mode due to the current oversupply and pricing environment.
Permalink Reply by HMI on December 1, 2010 at 4:23
Thanks Les. Have you seen this article? http://www.gurufocus.com/news.php?id=114506

It discusses whether or not Shale Gas companies who drill uneconomic wells make good investments. It actually addresses the idea that for some, this is largely an "asset play" as you noted regarding their ability to "book reserves".

When we look at the recent aquisitions of both XTO and ATLAS they were paid a pretty good premium for their assets in a low price environment. I believe XOM paid XTO an average price of $7/mcf for their assets if I remember right.

Oil & Gas ProPermalink Reply by Les Bamburg on December 1, 2010 at 11:18
HMI, I find that a little knowledge can be dangerous. The author of that blog knows just enough to seem credible but then makes statements and quotes from others that are total trash.

True some drilling $$$ are moving to other plays - most is not oil but rather just liquids rich natural gas plays that enhance the economics.

There is not of lot of shale gas acreage moving from the "control" of the independents to majors and the independents have adequate capital to continue their development activity.

The break-even costs are not at $8.00 per Mcf for shale plays. In fact conventional gas is generally on the margin and setting the market price.

Companies are not drilling "uneconomic" wells and the explanations in the story sound totally bogus.

By the way, ExxonMobil paid ~ $2.96 per Mcf for proved reserves but the cost drops to < $1.00 per Mcf when including all reserves.
Permalink Reply by HMI on December 1, 2010 at 11:48
Thanks Les. Always appreciate your input.
Permalink Reply by HMI on December 1, 2010 at 13:03
You're spot on Les. I looked it up on Morningstar here: http://quicktake.morningstar.com/StockNet/san.aspx?id=319483
Permalink Reply by Oklahomachic on December 1, 2010 at 3:00
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

Can you go into greater detail, not understanding that part...
Permalink Reply by HMI on December 1, 2010 at 3:12
Shirley,

In some areas of the play where there had been production, either gas or oil, that was shallower those areas were often leased by the landowners without them having the extensive exhibits that we saw people requiring during the Haynesville Shale leasing. So when someone signs a generic, Bath Lease form it most often gives the operator the right to "all depths" if they haven't put a vertical pugh clause in the agreement or specified exactly what depth the lease shall apply to. So in that environment, when the operator has rights to all depths and drills shallow gas or oil, that lease will be "held by production" aka HBP'd for as long as that well is producing economic amounts of gas or oil. So if a landowner has land that is held by the production of shallower gas or oil and then another formation is found deeper, as was the case in the Haynesville/ Bossier Shale, the landowner is often not entitles to another lease bonus even though they may have signed the initial lease (that had a shallower target at that time) for say $100.00/ $200.00 an acre. Without a depth limitation on the initial lease, the operator can run right on down to the lower formation and start producing.
Permalink Reply by Oklahomachic on December 1, 2010 at 3:33
This brought me to another topic.... May be related, not sure. If Section is HBP and the lease is producing Oil (not very much at this point) when will they go into deeper or shallower to get the frac going? I know this question does not apply..... I am trying really hard to understand. My late father was a Landman and bought interest in Desoto, Claiborne, Union, Acadia, Webster, Franklin, ect..... Some are HBP when will they be able to get to the shale?

Oil & Gas ProPermalink Reply by Les Bamburg on December 1, 2010 at 3:59
SS, the Haynesviile Shale underlies only a portion of Northwest Louisiana so of the parishes you listed only DeSoto Parish may be relevant.

If you have acreage where the Haynesville Shale is present, many factors will determine if and when a Haynesville Shale well is drilled. First, does the company that controls the deep mineral rights possess the technical and financial ability to drill and complete a horizintal Haynesville Shale well? Second, are there deep mineral rights within the section under lease that are not held by shallower production? Third, is the acreage located in a porttion of the Haynesville Shale play that is economic to drill?

There are other factors but the above three are the most critical in determining if your section will be developed in today's economic environment.
StevewPermalink Reply by Stevew on November 30, 2010 at 18:50
Thanks for the article. This is over my head beyond a certain point but I'm learning more all the time. The comments are also worth reading.

However, what about a fundamental Supply vs. Demand analysis? The amount of NG has increased hugely in the last two years. The estimated supply has leaped because of frac tech and the new discoveries around the United States.

However, on the Demand side it's quite different. Not only have we had a severe recession, but mild winters. Despite all the possible uses from NG they still have not created a lot of new, big demand.

There may be more demand when/if the economy picks up, but until then where will all this new gas be sold?? How about in the next 2-3 years??

Companies have to drill a certain amount just to hold leases and pay debt. Aren't most of the bigger HS drillers heavily in debt with thousands of leases yet to be drilled and held? Again, over supply.

Am I missing something? By my simple supply and demand outlook it seems that prices could stay low for some time without some new outside force (like tax breaks for NG or a very hard winter)

thanks again for the article. I'd like to hear other people's ideas for the near/long term future of NG.

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