Sharpe: The Hope for the San Juan Basin! Maybe
It is against my pessimistic nature to allow hope to enter my heart, but if I talk fast enough, I will allow it, for the moment, to enter the conversation.
In proper pessimistic fashion, last month’s article lamented the lack of drilling rigs in the San Juan Basin. The reason is that the finding costs here (the cost to drill divided by the amount of reserves found) is double what it is in some of the more prolific basins with which we compete.
With double the bang for the buck in the Permian, it is no wonder that ConocoPhillips and now WPX are exiting the San Juan Basin and taking their marbles down to Hobbs and Midland to play there.
However, drilling finding costs alone do not tell the whole story. There are other costs that really need to be factored in, and in particular, the costs of buying the leases well before drilling even starts. Ironically, the hope for the San Juan Basin is based on the fact that because it is a marginal basin, land costs here are dirt cheap, so to speak.
Yay for mediocrity!
Let’s look at the metrics of the recent ConocoPhillips sale to Hilcorp for some insight. Here is what has been released to the public concerning the deal:
• Purchase Price = $2.7 billion
• Well Count = +-12,000
• Production = +- 750,000 MCFD
• Annual Cash Flow = $200 million
• Net Acres = 1.3 million
Putting our fear of fractions aside, let’s calculate a few telling ratios which will help us evaluate this deal from the outside looking in. It’s a fuzzy view, but it’s all we’ve got.
First, the 750,000 MCFD divided by 12,000 wells is only 63 MCFD per well. The new BP horizontal Mancos well came on at 12,900 MCFD, which puts 63 MCFD in perspective. Most of those wells are very late in their lives and are barely eking out a profit. Ultimately, Hilcorp will have to plug those wells. At $50,000 a piece to plug, that represents a $600 million pending liability. Ouch!
The $2.7 billion price tag divided by the $200 million annual cash flow represents 13.5 years of cash flow. The going rate for producing reserves is more in the 5 to 6 years of cash flow range, so the actual production is maybe worth $1.2 billion on the high end. That means that Hilcorp may have paid some $1.5 billion (more than half of the price tag) for the drilling opportunities that come with the 1.3 million acres. On that basis, the land purchase costs were approximately $1150 per acre.
That sounds like a lot until you compare it to costs as high as $40,000 per acre to buy into the Permian or $20,000 per acre to buy into the Marcellus in the Appalachian Basin. When these costs are factored into the mix, it drastically changes the comparison of finding costs. The table below estimates the finding costs based on drilling costs only, but also calculates an “All-In Finding Cost” which includes the acreage cost to buy the leases.
Although the San Juan Basin still has higher estimated finding costs than other basins, it at least becomes competitive on an all-in basis. Keep in mind the numbers in my chart are horseback estimates at best. Reality may well be in our favor.
If savvy operating companies in the basin can find ways to tighten up those well costs or increase the reserves per well, the ratios can potentially turn in our favor.
In summary, if a company already owns acreage both in the San Juan and the Permian Basins (like ConocoPhillips, WPX, or Encana), they are going to want to drill their Permian acreage up first as the highest and best use of their capital dollars.
However, if a startup company (like Logos or Juniper Resources) has no acreage to begin with in any basin, then the San Juan provides a much cheaper entry into the game. So, don’t let my pessimism kill the buzz generated by BP’s new Mancos gas well. There is a glimmer of hope for the San Juan Basin.
George Sharpe is an Investment Manager with Merrion Oil & Gas in Farmington.