Peaking At Chesapeake

According to Chesapeake's March 2008 Investor Presentation (click sample slide above) the Barnett Shale is the nations best resource play and is increasing production and reserves rapidly as Chesapeake ramps up drilling to prove reserves. But there is more to the story .... Could Chesapeake's interest be waning? What happens when another cute girl walks by and looks interested?

According to Chesapeake's CEO, Aubrey K. McClendon, during his 3/25/08 conference call, the Barnett Shale has the highest rate of return on capital investment of any of Chesapeake's three major drilling areas. To make sure that they hold their leases, which are becoming much more expensive to acquire due to increased competition, Chesapeake is increasing their rig count in the Fort Worth area from 40 to 45 rigs.

However, Chesapeake's CEO went on to announce (quite reluctantly due to the desire to maintain competitive security) a new shale discovery in Louisiana that he believes is even more important than the Barnett Shale. Mr. McClendon indicated that the Haynesville Shale in northern Louisiana is ... "the most important operational announcement in Chesapeake's 19 year history." With 200,000 acres leased and a goal of 500,000 acres in the next few years, this field could increase net-to-Chesapeake potential reserves by up to 20 TCFE ($200 Billion at $10/MCFE). This compares to 260,000 net acres in the Barnett Shale with about 8 TCFE in reserves. Further detail about the Chesapeake announcement is also available in the Fort Worth Star Telegram article by Maria Perotin entitled "Chesapeake discovers Louisiana gas field."

Details of the discovery were limited during the call since they are competitive sensitive. However, drilling and development net costs for the new area should be similar to the $2/MCFE that is typical of the Barnett and other prime areas being developed by Chesapeake.

In a related article the magnitude of these estimates from Chesapeake were corroborated by Cubic Energy, a competitor in the Haynesville area. In this article Cubic claims their reservoir engineering estimates indicate gas reserves for the Bossier/Haynesville shale ranges from 217 to 245 BCF/section. That is about 40% greater than the reserve estimated by XTO (160 BCF/section) for the Barnett shale of Tarrant County.

So what does this mean for the mineral owners in the Barnett Shale? Could this mean that Chesapeake will be distracted by a new opportunity? Will already strained drilling programs and dollars be diverted to other opportunities? Will this further delay the required intensive development of Fort Worth minerals (except the minimum required to hold them by production)?

Such distractions could significantly limit the royalty stream paid on leases in the Barnett Shale for many years. So if you have leased a quarter acre to Chesapeake, you might well forget about receiving any royalties above $500 per year for many years to come. Chesapeake may be "too busy" if their interest in the Barnett Shale has peaked and they are "moving on" to prettier plays where they can focus on higher returns for shareholders.

IT'S YOUR GAS ... ENJOY IT!

Misunderestimated ??

Hey ... Don't complain about my Bushisms. I was born in Midland, TX and I drank the water too.

In my previous post, I estimated that the value of recoverable gas in the Barnett Shale area is over $1,000,000 per acre. However, that may be too low since it was based on an estimated 160 billion cubic feet of gas reserve per square mile and a 50% recovery of that reserve. Actual reserve values and recovery factors vary.

It is difficult to get data on the lifetime production of an average well and it's effective acerage but the correct value could be much greater than $1,000,000 per acre. The amount in the reserve depends not only on the size (acerage) of the property but on the thickness and condition of the shale deposit.

According to the Texas RRC, a number of the new wells in Tarrant County start out producing over 50,000,000 cu.ft. of gas per month. Current prices are about $7 per 1000 cu.ft. (MCF) so these wells are producing $350,000 per month.

But does anyone think the price of natural gas will NOT increase over the next 10 years? A better estimate of the average price is probably at least $10 per MCF. Some estimates that I have seen place total production from $10 million to $30 million per well.

Of course production depends on many factors. Underground faults can both cause leakage losses and make it difficult to fracture the shale properly. The skills and techniques of the driller and completion experts can also effect production and recovery factors.

However, the greatest factor determining production is the density of drilling and fracturing. If a well has an 2000 ft long horizontal or "lateral" section and if the fractures in the shale spread out 200 feet on either side of the lateral, the area addressed by that well is 2000 ft by 400 ft or 800,000 sq.ft.

Since an acre is 43,560 sq. ft., this 2000 ft lateral can recover gas from just under 20 acres. Thus we see that a single well can only tap the gas from a fairly small area. If only one well is drilled in a 160 acre pooled drilling unit, not much of the gas will be recovered. The density of wells is thus the most significant factor in producing gas from the Barnett Shale.

By drilling eight wells in a 160 acre drilling unit and using techniques like simultaneous fracturing, recovery can exceed 50% ... perhaps significantly. While this may be optimistic estimates, it would thus seem that a resonable estimate might be over $1.5 million per acre!

*********** $1,500,000.00 per acre ************

Note that when a property owner signs the typical lease, they are allocating 75% or more of their gas to the well operator. The owner only retains benefits from the 25% (or less) royalty.


Estimates of well cost range from $2 million to $5 million per well. If a single well costs less than $5 million and taps the gas in about 20 acres, the owners of land may be agreeing to pay the operator an average of $15 million for drilling that $5 million well ... a $10,000,000 per well profit! Even if the profit is only about $5,000,000 per well, is it any wonder operator representatives are being paid to go door to door and are offering almost $20,000 per acre in signing bonuses.


Hey ... I'm open to other information on the productivity of typical Barnett Shale wells. However, to date not a single expert in the oil and gas business has challenged my previous estimate. It's been several weeks since I published it and NOT ONE email or comment has been received to challenge this finding.

Perhaps no corrections were suggested because the experts know that the estimate was VERY conservative. Correcting the value would not be in the interest of the operators since owners would likely become more aggressive in pressing for higher royalties and bonuses if groups were aware of the profits margins.

I wonder what will happen now. Note that I have also heard (but not yet confirmed) that, based on recent drilling data, higher recovery factors may be possible with new techniques. Could $2 million per acre be more correct? Could $0.5 million or more per acre in royalties be possible? Probably not but who will step up to help owners understand the basic economic considerations of a gas lease? And is a 100% plus profit fair?

I am reluctant to sign anything till I know for sure that the deal is fair and drillers are being forthright in their dealings. What about you?

IT'S YOUR GAS ... ENJOY IT!

Haven't Signed Yet??

Know more about where you stand if you have not signed a lease yet. See this article on the Star Telegram Blog.

IT'S YOUR GAS ... ENJOY IT!

Mineral Owners Lose In Court

There are several MUST read documents available at Texas A&M Real estate Center . These documents explain many issues to consider when leasing.

For example, surface owner rights are subordinate to mineral owners. Also surprisingly, even if the lease indicates royalties are to be paid without post-production expenses being deducted, that is not supported by case law. In fact, owners end up sharing in those expenses.

Here are some quotes from these documents.

1. One of the earliest and most significant cases decided by the Texas Supreme Court held that the mineral estate is dominant over the surface estate. The grant of the mineral lease gives the mineral lessee the implied right to use as much of the surface as is reasonably necessary for the exploration and development of the minerals. The surface owner’s consent is not required for this right to be exercised. The mineral lessee is liable for surface damages only in limited situations.

2. The shared expenses depend partly on where the lease fixes the royalty. Commonly, the royalty for oil is set "at the well" or "wellhead." In such cases, the mineral owner’s royalty payment is free of production costs, but all costs subsequent to production are shared. (Two 1996 Texas Supreme Court decisions, Heritage Resources, Inc. v. Nations Bank, 09-0515, and Judice v. Mewbourne Oil Co., 95-0115, so held even though the lease addendum stated the royalty was free of such costs.) If the lease fixes the royalty "in the pipeline," "at the place of sale" or at other delivery points, different costs subsequent to production may be shared. These costs may include items such as compression expenses necessary to make the product deliverable into the purchaser’s pipeline, expenses necessary to make the product salable, transportation costs and the expenses used in measuring production.

Until you sign the lease, you own both the surface and mineral estate in a single deed and have control over your estate. After signing, the mineral and surface estates are in separate deeds and will never be combined again. Plus you end up losing control of the surface estate too. I am not a lawyer and can not give legal advice but the old saying "BEWARE of strangers bearing gifts" seems to apply.

IT'S YOUR GAS ... ENJOY IT!