Whenever we need to get home repairs—roof, driveway, plumbing—we ALL shop around to find the best contractor at the best price to do the work.
Royalty owners should do the same.
A recent working paper published by the Federal Reserve Bank-Kansas City titled “Capturing Rents from Natural Resource Abundance: Private Royalties from U.S. Onshore Oil and Gas production (Jason Brown –Federal Reserve Bank-Kansas City, Dr. Timothy Fitzgerald-Texas Tech University, Dr. Jeremy G. Weber-University of Pittsburgh) used over 1.5 million lease records obtained from DrillingInfo to study the pass -through of financial benefits to royalty owners in resource plays.
It made me think of the time when I was travelling from a Utica conference in Columbus OH to Pittsburgh and I stopped at a McDonald’s in Washington PA.
As I walked in there were two good ol’ boys jawing at each other, and the conversation went something like this:
Good ol’ boy #1:” You got your draft yet? Shoulda paid you by now , since you only getting’ $300/acre..”
Good ol’ boy #2: “May be, but I got that sweet 18% royalty….what’d YOU get, fool?”
Good ol’boy#1: “Crap, I only got 16% but I beat your$300/acre by $200/acre more!”
Good ol’bopy#2: “Say what??”
And therein lies the crux of the matter….especially given the authors’ conclusion that: “Thus, mineral owners benefit from resource abundance primarily through greater production, not by negotiating better lease terms from extraction firms.”
The value of producing minerals is determined by many factors , not just by bonus, or even royalty.
So we’re going to look at some of the due diligence—the “shopping around”—that royalty owners should perform when they are making their decision to lease.
1. Are you actually going to get iron on the ground?
I have a friend who has family minerals in West Texas who was approached by two separate outfits that wanted to lease her 120 acres. One group was offering about $200/acre more than the other; the proposed royalty burden was the same.
When I used DrillingInfo to check permit and completion activity and production results for the company offering $200/acre more, I found no drilling history in Texas.
Nada, bupkis, zilch. So it was pretty obvious that they were leasing to flip to somebody that might drill.
The other company had no West Texas experience, minimal drilling and minimal completions activity, meager production history, and lots of dry holes. Not a great resume for efficiently executing a drilling program that would include her minerals.
So she waited 6 months before leasing to an operator with a better track record.
If, as a mineral owner, you lease to someone who’s going to flip your acreage, you may be waiting an extra year or two for your acreage to get drilled. Suppose that the type curve for your area indicates that in the first two years of production you should expect 150,000 barrels of produced oil. At $45/bbl and a 20% royalty, that’s $1,350,000 in royalty payments. If you didn’t have to wait for it, that money could be returning 3-5%/yr—enough to pay for a couple years of college, some great bass boats, or the beginnings of a trust fund for the kids.
2. What operator extracts maximum value from your minerals?
No one is great at EVERYTHING they do. Companies that want to lease your minerals are no different. An operator who is great in producing deep Gulf Coast reservoirs may struggle to find the right mix of interpretation and completion tools in the Bakken. Or in the Marcellus. Or name your play/basin.
Fortunately we have tools that can help identify the best performers, the group of companies that you would like to lease to because they extract the most oil and gas.
For example, let’s look at the Marcellus.
This graphic shows all the operators in the Marcellus. The red vertical line represents the median BOE produced by all operators. As a mineral owner who is being approached to lease your minerals, you would be far better served by leasing to the companies that are doing well (represented by the green circles), especially the companies with a fair number of wells to their credit (bigger circles).
Even better would be to lease to an operator that has shown a history of quick adaptation to the geology of the area; they learn from their previous work and show progressively better results.
Say your acreage in the PA Marcellus is located at the blue turquoise dot.
You can use the DI analytics creaming curve display to determine who is learning their lessons the fastest. An operator that is adding proportionally more production with each succeeding well will have a more vertical curve.
As a mineral owner , you should prefer to do “business” with the operator represented by the blue curve because they’ve shown marked improvement in boosting their production, and they’ve done it while drilling in a number of locales.
What Operators are getting good results?
This is THE crucial part of the value equation. If a mineral owner is considering two valid, comparable leasing offers, she/he should compare the type curves for each company to determine who will probably deliver the best production results.
So given the choice between the type curve of Operator A:
a lessor should prefer Operator A as a lessee, assuming that Operator A has drilled wells in the area of the lessor’s minerals.
What Price should I expect?
Mineral owners should also account for operator sales pricing differentials.
We’ve commented before on the dangers of using a media- sourced WTI
price as a proxy for well head prices. Not only because different plays have different oils with different API gravities—and therefore different prices—but even within a play there can be meaningful differences in wellhead prices.
For example, mineral owners in Texas can use the MarketView feature in DI Classic to search for prices within a range, bubble the wells by wellhead price, and then see them on a map
The range of pricing in this area is $39.39-$44.16. The royalty proceeds from a well that has produced 100,000 bbl with a sale price of $39.39/bbl will leave nearly $500,000 on the table compared to a price of 44.16!!
How do I model my royalty cash flow?
I once looked at an oil and gas deal for a friend. The promoters’ deal structure was horribly punitive for investors, and key to the awfulness of the deal was the use of initial potential flow rates in the calculation of future production rates and therefore potential reserves.
I would guess that some, but not all, mineral owners are aware of the decline behavior of resource plays. I suspect that many will be relying on the “typical” well rule of thumb—in other words the typical well in the Karnes county Eagleford produces X, or the “typical well” in the SCOOP play produces Y.
This graph of Bone Spring production for wells with first production 8/1/2015-present illustrates the fallacy of the “typical well”
Knowing EUR (Estimated Ultimate Recoveries) for the wells producing from your minerals is critically important in being able to responsibly estimate future production—and therefore cash flow.
For example, one of the wells in the group has produced about 60,000 barrels of oil in 11 months. It’s most recent production was just over 170 BOPD. How much more production can the mineral owner count on production from this well?
Using Probabilistic Decline curve modeling in Production Workspace,
the EUR for this well at P90 level of confidence is 106,751. So the mineral owner can expect the operator to produce an additional 48,000+ barrels of oil before abandonment—or expected added cash of about $400,000(assuming $45/bbl and 20% royalty)
Understandably, bonus payments and royalty rates are often the sole factors that mineral owners consider when leasing, but maximizing the value of that lease is a complex function of variables that too often are not considered when choosing a lessee!
What do you think? Leave a comment below.
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