At a minimum, a no-deductions clause is supposed to prevent your lessee from deducting the costs they incur in transforming your share of the raw natural gas they bring to the surface into a marketable product. “Marketable” can be defined as “sufficiently free from impurities that it will be taken by a purchaser.” This is a vague definition at best however, as there are many types of purchasers, each of whom can have different standards for marketability. Unfortunately, most jurisdictions, with the possible exceptions of Wyoming and Colorado, have failed to enunciate a standard for marketability and thus a court would have to look at the specifics of each case to determine whether this gas or that gas had been placed in “marketable” condition prior to sale in the event a lessee was challenged by their royalty owner.
That said, a no-deductions clause is still a good clause to have in your lease, however you don’t want to make it too restrictive by disallowing deductions for improving already marketable gas or transporting same to a purchaser in another town who is offering a better deal (even after deductions.) If enough lessors (mineral owners) insist on a strict “NO-deductions” clause in their lease, it may discourage the lessee from working hard to find the best market they can, since a strict no-deductions clause will require them to pay not only for making the gas marketable at the well, but also will require them to pay for transporting your share of the gas to a potentially better market downstream (away) from the well.
If the lease is too strict on deductions, an operator may just decide to sell all the gas to a “wellhead” purchaser rather than paying your share of the costs needed to get your share to a better buyer downstream. The wellhead purchaser will offer your lessee (and thus you) less than the buyer downstream is paying since it will cost the wellhead purchaser money to transport the gas to that purchaser. I therefore usually allow deductions if (and only if) doing so results in me getting a higher price (even after deductions) than I would have received if my lessee sold to a wellhead purchaser.
I feel this “allowance” benefits both myself and my lessee as it means we both are sharing in the costs of obtaining a better market that results in a better net price (price after deductions) than could be had by selling to someone closer to or at the wellhead. It seems fair to me to offer to help pay to move my share of the gas to a better market location if one is available. “Moving” the gas might mean buying space on a wellhead purchaser’s line (while not actually selling to them) and transporting it using that line to another purchaser’s pipeline further “down the road” who is offering a better net price.
Gas marketing is complicated because there are so many variables, including some that are beyond the scope of this article such as how royalty is calculated on heavier gasses (ethane, butane etc.) that are removed (by processing) from the wellhead gas stream. There is lots of room for mischief by oil companies, especially vertically-integrated companies who may sell to their affiliated purchasers or processors and base your royalty payment on that sale, rather than the sale from their affiliate to a true arms-length purchaser.
Because we, as royalty owners, aren’t usually privy to the gas sales contracts used and thus can’t always verify whether we are being paid correctly, I usually add language relating to affiliate sales in my no-deductions clauses.
Many companies are as transparent as they can be however, and their often overworked staffs at least make an attempt to explain to their lessors exactly how royalty is calculated. With these companies I feel less of a need to insert a lot of strict clauses into my leases.
Frederick M. “Mick” Scott CMM, RPL
Manager: The Mineral Hub