April 22, 2015 04:54 PM
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I’ve been wondering about something lately and have been asking around. The reaction I get reminds me of the movie Ferris Bueller’s Day Off. Remember the teacher asking the class history questions, getting no response, and saying, “Anyone? Anyone?”

Have you heard of the term “contango”? This is a situation where the futures price (or forward price) of a commodity is higher than the expected spot price. Sound familiar?

And surely you are hearing what is happening with oil today: “I’m not selling my oil today, because it will be worth more tomorrow.” In the past, producers would produce the oil or a buyer would buy oil today and store it, and then wait for prices to go up before selling or simply forward sell at the higher price. The trick is that the cost of storage has got to be lower than the spread between the spot price and futures price. This is an old technique in our business that now has a new twist.

E&P companies, primarily in the shale, are doing something unusual. They are drilling wells, but not completing all of them. As a general rule in 2013 The Hess Corporation said the average cost of a well in the Bakken was $4.8 million to drill and $3 million to complete. The backlog of wells drilled but not completed has been given the name “fracklog,” and it’s a growing trend. According to Harold Ham, CEO of Continental Resources, “About 85 percent of U.S. wells aren’t being completed right now…”

Bloomberg reports that there are more than 3,000 of these wells.

Let’s say you drill but don’t complete the well, to save the “completion cost,” hedge your bets and wait for higher prices. So you are effectively storing the oil in a natural reservoir (“contango”) and building a fracklog inventory. The big question is, how are your leases going to be maintained? Every lease I have ever seen, and that’s a whole lot of leases, has a shut in provision that allows the operator pay to extend the lease beyond the primary term if the well is shut in, but only for a fixed period of time and usually only if it is “capable of producing.” What I don’t know is whether or not this growing list of fracklog wells can be classified as “shut-in.”

What happens if the same lease has vertical or horizontal pugh clauses? It is estimated that more than 65 percent of leases taken in the shale plays contain horizontal and/or vertical pugh clauses, with an even higher rate of horizontal and/or vertical segregations on resulting assignments. I’m calling this the “commoditization or valuation on a formation basis.” The question I have is will the shut-in payment on non-completed wells hold all of the lease or only the unitized/pooled acreage by depth or even any of the lease? If it does, what about the non-pooled acreage and all “deeper” depths?

This is not just an academic question. It is truly a big financial question. If these non-completed wells cannot hold lease acreage or deeper depths, how will that affect the “reserve” values of the companies? I was looking at the difference between Proved Developed Producing Reserves (PDP) and non-producing reserves (which goes by many names, like Proved Undeveloped Reserves, Potential Reserves and Resource Potential) listed on the investor presentations of several big shale E&P companies. What I found interesting is the huge spread between the two categories. Non-producing reserves were usually around six to 10 times greater than Proved Develop Producing reserves.

So the question still remains, if you don’t complete the well, how are you going to hold all those leases, which obviously hold all those reserves, which make up a major portion of the company’s asset value? After speaking with a number of oil and gas attorneys and principles of E&P companies, I haven’t found anyone who feels confident about an answer in either direction.

I think it is going to be a huge factor in how a company maintains its “undeveloped” acreage position and thus its balance sheet asset valuations. We have spent a year developing our program to tell you exactly which leases, which depths, and what acreage your company will lose and how much it will cost to keep that acreage for the next year.

So what do you think about the scenario at hand? Anyone? Anyone?

Tim Supple is the president of iLandMan and has been in the oil and gas industry for nearly 40 years working as a landman, broker and E&P operator, before entering the land software business in 2005.





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