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Высокие технологии Non-Producing Fee Minerals
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Non-producing fee minerals are often owned directly by individuals or indirectly through FLPs or limited liability companies and often are involved in estate-planning transactions. For example, family ranches or farms (and underlying minerals) in south Texas (Eagle Ford shale), North Dakota (Bakken shale), West Virginia/Ohio (Utica shale) or Pennsylvania (Marcellus shale) have created dramatic wealth in recent years. Petroleum engineers (PEs) usually don’t want to provide valuations of non-producing minerals if geological and reservoir data don’t exist, so there are a limited number of valuation experts in this area.

In some cases, non-producing minerals are simply included with producing minerals in a valuation. For example, if the producing minerals (royalty interests) are valued using a cash flow multiple, the non-producing minerals often get overlooked and are implicitly assigned no value. Some clients will value the non-producing minerals at a token $1 per net acre, not knowing how else to do so. The best and most defensible approach for valuing non-producing minerals is to use a price per net acre multiple (the market approach) for an arm’s-length comparable mineral sale (as opposed to a working interest sale) that occurred near the valuation date. While this information has rarely been available in the past, our relationship with EnergyNet, Inc., an oil and gas advisory firm headquartered in Amarillo, Texas, allows us access to such data.3

In situations in which there isn’t sufficient market data or the subject non-producing minerals have significant value (because they’re located in an active area of exploration), an income approach can be used. Sophisticated mineral buyers who have geoscience and engineering professionals on staff rely on this approach. These professionals will develop a cash flow projection based on:

· Type curves or expected production profiles for nearby or analogous wells

· The number of rigs operating in the area

· Oil and gas price levels and economic return to operator’s working interest

· Lease terms in area or actual terms, if minerals are leased

· Unit sizes/current field spacing requirements in the area (number of wells

The following factors impact the selected discount rate applied to the projected cash flow stream:

· Whether minerals are already leased and, if so, the operational and financial strength of the operator

· Operational and mechanical risk

· Environmental risk (hydraulic fracturing and water use/ discharge issues)

· Commodity price risk

It’s important to remember that a sophisticated valuation model may be built, but the subject minerals may never be leased, because oil operators in the area might, ultimately, deem them not prospective for exploration. The valuation must, therefore, consider the probability that the subject minerals won’t be leased and won’t generate income.

Another method for valuing non-producing minerals in an estate or gift tax valuation context is to rely on a simplistic approach called the “Multiple of Lease Bonus.” The method is to multiply the lease bonus per acre in effect at the valuation date, by the number of net mineral acres held by the client. The selected multiple or lease bonus per acre is increased if nearby drilling and production results are favorable.