- April 29, 2012
- Posted by: Art Berman
- Category: The Petroleum Truth Report
This has been a tough period for Chesapeake Energy and Aubrey McClendon with his loans and losses on drilling investments. Despite these issues, I give him and his company credit for vision and leadership in the shale revolution.
He once described me as “a third-tier geologist who considers himself a reservoir engineer, that somehow [knows] more about the shale gas revolution in America than companies that have combined market caps of almost $2 trillion and have spent hundreds of billions of dollars to develop these new resources, I mean, it’s ludicrous.”
Nice.
The logic is that corporations that spend billions of dollars of shareholder money are inherently more knowledgeable and credible than industry professionals who have published dozens of technical papers on the questionable reserves and economics of shale gas.
What the revelations about McClendon’s losses really mean is that what we have been saying for years is true: shale gas is an economic loser.
Still, McClendon has shown singular direction and foresight in an exploration and production industry commonly characterized by the herd mentality of late adopters.
13 Comments
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Are you talking about dry gas?
I am talking about balance sheets: profit and loss.
Here are the facts according to Reuters (http://www.reuters.com/article/2012/04/18/us-chesapeake-mcclendon-loans-idUSBRE83H0GA20120418):
In 2010, he (McClendon) had a net capital loss of $142 million on his investments in Chesapeake’s wells.
In 2009, his loss was $116 million.
In 2008, he lost $63 million.
If his 2.5% of Chesapeake wells lost this much, the other 97.5% were equally unprofitable.
Dry gas, wet gas, NGLs, oil and lease condensate, the whole package–unprofitable.
These are not my opinions. Let’s get over the love affair with shale and move on to the relationship.
Art
“If his 2.5% of Chesapeake wells lost this much, the other 97.5% were equally unprofitable.”
What about ‘sweet spots’?
Chesapeake drills a lot of wells and spends a lot of money on land. A Haynesville or Eagle Ford Shale well costs around $9 million. At one time, they had 45 rigs drilling in the Haynesville and currently have 34 in the Eagle Ford. Sweet spots are great after you find them and if your position is in one.
The average CHK well in the Haynesville will produce about 2-3 Bcf but it takes at least 6 or 7 Bcf to break even. Their Barnett position is good. They got out of the Fayetteville and Woodford so that tells you something. Their Marcellus position is good.
Authur:
I have been following you since I learned your name.
I have come up with a simple method to calculate the decline model of the Barnett Shale, given only publicly available information on well counts and annual production. Please see it here:
http://seekingalpha.com/instablog/121744-mark-anthony/563001-a-mathematical-model-of-shale-gas-well-production-decline
Interestingly I super-imposed my projection curve onto your chart. They match perfectly.
The UER is around 2 BCF if there is very little terminal decline rate. If there is a terminal decline rate of 6% or 7%, as some claimed, then the UER will be only 1.7 BCF.
It does not surprise me that your mathematical approach to the Barnett Shale matches our empirically-based forecasts.
The trick, however, is to establish those decline rates from early data only so plays with little production history can be evaluated.
The other important part of the story is net present value.
People can have esoteric debates all day about terminal decline rates but, if there is little to no present value in these “tails” of production then, the EUR isn’t really a reserve after all–it’s simply a volume that proxies for a reserve only because of the artificially low terminal decline rate which nobody knows because no well has achieved terminal decline.
We are currently using the standard semi-log rate vs time plot along with an arithmetic rate vs cumulative production plot to calibrate decline rates and forecasts. We have recently added a log rate vs log cumulative to help qualitatively determine the hyperbolic exponent “b”–how the rate of change in decline changes over time.
Dr. Henry Lee, a long-time expert on petroleum engineering and decline models, is experimenting with another approach called the Duong Model which uses log rate vs. cumulative production and may offer hope for early-time forecasting.
Many thanks for your dialogue on this subject!
I think you will see that the tough talking shale promoters have gone underground and will remain silent. On the top of this list is Tudor, Pickering and Holt. I still pull out “The Letter” from time to time and read that pompous criticism of your work. Believe me, that big mouth has been shut as tight as the Haynesville Shale and will remain so.
Art, I think you should pour it on these guys, especially Aubrey. It was just a question of time until the house of cards fell. Most shale gas CEO’s are cold hearted money grubbers that deserve what they are about to get
Art,
Does anyone know if the volumetric production payments are restricted to specific assets or acreage or are the spread over the entirety of Chesapeakes assets?
If a specific asset can not produce the required volume what recourse is available?
Will Chesapeake have to make up delivery volumes with purchases on the open market or will it have to settle accounts with cash plus a guaranteed rate of return?
Finally Art, I applaud your graciousness to AM. You are a gentlemen.
John S. Midland, Texas
John,
VPPs are common in the oil and gas business. They are not unique to Chesapeake Energy nor are they illegal or unethical.
VPPs are area-specific. They are carefully defined– and disclosed–to include a particular geography and wells. Chesapeake has many VPPs in different areas but they are all clearly defined.
The WSJ article by Russell Gold claiming $1.4 billion in undisclosed liabilities is off-base. I am neither one to defend Chesapeake nor to unfairly condemn fully disclosed, legitimate practices like VPPs.
The bad news for Chesapeake is not that they entered into VPPs but that many of their assets under VPPs are pledged and, therefore, cannot be sold to raise cash.
Art
Thanks Art,
Perhaps I misspoke. My question is;”What happens if the assets pledged to a VPP cannot produce the reserves pledged against it.”.
we both know that historically reservoir engineers were very very conservative when they booked reserves. That is not always the case these days.
John
John,
There is language in the VPP agreement that states what happens in the case that the production is insufficient to satisfy the obligation. I imagine it is somewhat different depending on the VPP.
But your point is well taken. I imagine the VPPs assume decades of well life and the supposed residual is put into a fixed asset account held by the producer. In the event that there is little residual, there would have to be a write down.
Art
I woulde like to go a bit back and suggest to define a subject of discussion (shale) more difinite.
Since the beginning of Barnett gas shale boom it was assumed that shales (and the name is used for some limestones) are reservoirs of kind unknown to the petroleum geology and industry. The industry got convinced that the only way to develop hydrocarbon reserves in these plays is a combination of horizontal drilling and multiple stages hydrofracturing.
But more and more participants recognize that many of these pools produce from naturally fractured rocks.
The Monterey “shale” has fractured sections. The carbonate rich Eagle Ford is naturally fractured. The Niobrara limestones are naturally fractured. The development of the Marcellus shale, according to Terry Engelder, an acknowledge expert, is “… all about the [vertical] fractures in the rock and how you tap into them.”
I would not wonder if the Austin Chalk will be declared “shale” soon.
Best regards.
Simon Strazhgorodskiy