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Natural Gas Royalties and Chaos Theory

We all know the famous (and oversimplified) explanation of chaos theory. If a butterfly flaps in Moscow, it creates typhoons in Manila.

The basic point being there are no closed systems. Everything is affected by everything else. Even very distant things.

U.S. producer Range Resources proved yesterday the same is true for natural gas royalties.

One of Range's main producing regions is the Marcellus shale in Pennsylvania and Ohio. Like many producers, the company drills wells here and then connects them to pipeline. The gas is transported away for processing (stripping of liquids and other substances), compression, and eventual shipment to market.

As in many gas plays, Range pays royalties on production to local landholders. If you own the ground above a gas pool, you get a small percentage of the revenue from each MCF flowed to surface.

But Range had a "chaos theory" issue with the definition of revenue. The company felt revenues are affected not only by what happens at the production site, but also by happenings at more distant locations.

Specifically, the company believed it should be able to deduct costs for transporting and processing gas before calculating royalty payments. Such costs are usually paid to third-party pipeline and facility operators, and can represent a significant amount.

Here's (quickly) how it works. Suppose a landholder has been given a 20% royalty on gas production. If a gas consumer (or third-party supplier) buys an MCF from the producing company for $6, the landowner gets $1.20.

But a gas buyer won't always take gas right out of the ground. A producer like Range may be distant from a pipeline gate where buyers accept delivery. And the gas may need processing before it meets specs for being allowed into the buyer's pipeline.

In such case, the producer can build its own pipeline to transport gas to the sale point. And construct its own processing plant along the way. Or, if this infrastructure has already been built by another company in the area, the producer can simply pay the owner of these facilities a fee to transport and clean the gas.

Here's where the problem comes in. Suppose our producer pays $1 per MCF in transport and processing fees to the third-party facilities owner. Once this gas arrives at the point of sale, the buyer still pays the producer a normal wellhead price. Remember, we assumed $6 per MCF in the above example.

Landowners looking at the arrangement see the producer selling gas for $6. You owe $1.20 in royalties. End of story.

But Range felt that what happened along the way matters. If the company has to pay $1 to get the gas to market, the value of that MCF is actually only $5. The 20% royalty should only apply on this amount, for a total of $1.

Range's Marcellus landowners didn't agree and the matter went to court. And in March judges upheld Range's claims. The upshot being that yesterday the company announced a new royalty arrangement. Range will be able to deduct $0.72 in transport and process costs per MCF of dry gas from its sale price before calculating royalty payments. For wet gas (which requires more processing), the deduction will be $0.80.

The change will have a material impact on the net present value of Range's operations. A good lesson in how modeling of oil and gas projects can get complex very quickly. Too often, investors (and even companies themselves) oversimplify things like royalties. Leading to poor judgment on a project's economic viability.

This analysis gets especially tough in many overseas production sharing contracts. Where government take (in terms of royalties and payable profit oil) can be affected by all kinds of outside variables. Commodity prices, production rates, "ring-fencing" of capital expenditures.

Bottom line: it usually sounds simpler than it is. A 20% royalty may seem straight-forward. Calculating it often isn't. Investor beware.

By. Dave Forest of Notela Resources




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