Changing the terms of oil leases may increasingly become a viable win-win solution for both operators and mineral owners either seeking financial relief or to strengthen their position.Such is the case with the University of Texas, owner of more than 2 million acres of prime oil assets.
The school is hoping to parlay its massive holdings into an even mightier revenue engine by renegotiating existing leases with operators under pressure to cut costs. The UT case is illustrative of the broader environment in which mineral owners and operators are more open to working together toward win-win solutions such as re-evaluating the terms of lease arrangements.
A lease renegotiation could result in a staggering threefold increase in land values for the University of Texas, which already holds the largest endowment of any public American university. Recognizing the scale of this opportunity, UT wants to adjust how royalty payments are calculated on leases that were not only signed decades ago, but built on pre-shale revolution assumptions that have now completely changed.
Before the shale boom, most conventional wells were drilled vertically downward until they punctured pools of crude lying at great depths. Now, we can drill unconventional, horizontal wells into multiple layers of pancaked rock, creating distinct zones in their own right that should arguably factor into valuation models.
Mineral owners sitting on shale deposits that are suited for newer extraction methods may have royalty rates written into old lease agreements that are far beneath the potential value of the assets. Some states require that the landowner be paid a minimum royalty, often 12.5%. However, the negotiated rate can be much higher, typically around 25%, depending on multiple variables such as geological factors, nearby drilling results, market dynamics, etc.
The geological variable is arguably the most critical component in calculating a royalty rate. Because stacked lateral drilling can increase ultimate oil and gas recovery, this could justify higher royalties for leases in a shale play with thick, stacked rock. UT not only wants to adjust how such payments are figured, but also argues that it should be allowed to lease stacked horizontal zones within shale rock separately. This would mean that acreage which had, say, a single lease permitting vertical exploration rights to the center of the earth, could now consist of multiple, separate lease arrangements for horizontal zones, all owned by UT.
The combination of additional revenue streams coming in from a greater volume of leases, in addition to higher royalty rates for leases on shale acreage, could be a boon for the University of Texas, as well as for mineral owners across the country, if the school is successful in its efforts.
A solid understanding of the geological makeup of a play can give both mineral owners and operators better footing in renegotiating a lease. This topic may become ever more important if UT can achieve a successful recalculation of royalty payments, setting a precedent for a new leasing model that could redefine the rules for how mineral owners of shale regions across the US get paid by oil companies. Furthermore, the new model would likely be replicated quickly across the country, causing numerous leases to come up for re-evaluation.
Similar to how the University of Texas has armed itself with a team of geologists to identify the plays with lease renegotiation potential, both mineral owners and operators would be well served by understanding key geological factors of the acreage they have stakes in, such as shale thickness and high-production reservoir zones, that could play a key role in negotiating royalty rates upward. Check out this Drillinginfo infographic that shows you how to identify the best horizontal zones in a stacked play.
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