POST PRODUCTION COSTS – WRITING A CLEAR CLAUSE (AS THE HAYNESVILLE RECOVERS)

Generally speaking, post–production costs are the expenses incurred in order to get natural gas from the wellhead to market. These costs include gathering, compression, dehydration, processing, fractionation, treating, handling, and transportation.

For many years, natural gas sales were at the wellhead and price regulated (by the Federal Power Commission and later the Federal Energy Regulatory Commission). However, the days of price regulation are now behind us, and sales occur in an open, competitive market. Generally, sales occur at a central location (such as a “natural gas hub”). So, the well operator sees a sale price at a distant location but often must absorb the “costs” (post-production costs) of getting the product to the distant trading location. By analogy, a grower of corn can sell his crop in the field, or, alternatively, absorb some out-of-pocket costs (e.g. harvesting, storing, and transportation) and sell his corn at a central location (a distant silo). Either way, post-production costs are relevant – your product is more valuable if it is near the central sales location and needs relatively little treatment. The concept is simple – and universal, at least to a certain extent, for all commodities.

In this discussion, the question is whether a royalty owner should incur a proportionate share of post-production costs. Obviously, this is a matter of negotiation – but whatever is ultimately agreed upon, it is necessary to properly document that agreement in the contract (oil and gas lease).

If your oil and gas lease reads something like the following (a Lessee royalty clause):

“Notwithstanding the provisions of the printed portion of the lease, for any oil, gas, or other minerals that Lessee produces from the lease or is otherwise attributed to the lease, including casinghead gas, condensate, distillate, natural gas, or any other gaseous or liquid substance or mineral that may exist in the oil or gas stream as produced at the wellhead, Lessee shall pay Lessor royalties on such oil or gas in amount equal to ________% of the market value of the oil or gas at the “wellhead” – that is, the location where Lessee extracts the oil or gas from the ground.”

…. well, the royalty owner is almost assuredly going to bear a share of the post-production costs.

This is, by the way, the clause oil and gas operators should offer to potential lessors.

That is because of a ruling by the Texas Supreme Court in 1996 (Heritage Resources, Inc. v. NationsBank, 939 S.W.2d 118 (Tex. Sup. Ct. 1996)). For simplicity sake, the lease clause in that case read as follows:

Lessee shall pay the following royalties subject to the following provisions: … (b) Lessee shall pay the Lessor ¼ of the market value at the well for all gas (including all substances contained in such gas) produced from the leased premises and sold by Lessee or used off the leased premises, including sulphur produced in conjunction therewith; provided, however, that there shall be no deductions from the value of Lessor’s royalty by reason of any required processing, cost of dehydration, compression, transportation, or other matter to market such gas.

The Court held that “royalty” and “market value at the well” have well accepted meanings in the oil and gas industry. The post-production clauses in issue here plainly state that there “shall be no deduction from the value of the Lessor’s Royalty.” The leases clearly set the lessor’s royalty as a fraction (1/4 or 1/5) “of the market value at the well.” Under the leases, the lessee must determine the value of the lessor’s royalty. The lessee accomplishes this by determining market value at the well and multiplying it by the fraction specified in the royalty clause (1/4 or 1/5). This result is the value of the lessor’s royalty. The post-production clauses then specify that there can be no deduction from this value (the value of the lessor’s royalty) by reason of any post-production costs. This can be determined by looking to comparable wellhead sales, or, if none, the nearest downstream sale adjusted for [you guessed it] post-production costs.

Based on this decision, if a lease provided for the computation of royalties based on “market value at the wellhead,” it is difficult, if not impossible, to exclude deductions from royalty obligations for post-production costs attributable to royalty interest.

Two subsequent Texas Supreme Court Cases (Chesapeake Exploration, LLC et al v. Hyder et al, 483 SW 3d 870 (Tex. Sup. Ct., 2016) and Burlington Resources Oil & Gas Company LP v. Texas Crude Energy (Tex. Sup. Ct. Docket No. 17-0266, Mar. 1, 2019)) attempt to give draftsmen, and perhaps oil and gas companies, guidance on reading these clauses.

First our Supreme Court has ruled that the “default” rule is that royalty owners will share a proportionate part of the post-production costs. But, this default rule can be modified by careful drafting. Second, our Supreme Court has ruled that if the valuation point for royalties is at – or near – the wellhead, the royalty owner will bear a share of the post-production costs.

So, in conclusion, here is my royalty clause, for a royalty owner, that provides that they never, ever share in post-production costs:

“Notwithstanding the provisions of the printed portion of the lease, for any oil or gas that Lessee produces from the lease or is otherwise attributed to the lease, including casinghead gas, condensate, distillate, natural gas, any other gaseous or liquid substance or mineral, or any constituent product contained in the oil or gas that Lessee produces from the lease, Lessee shall pay Lessor royalties on such oil or gas in an amount equal to __________% of the price, free of costs, that Lessee actually receives on selling the oil or gas to an unrelated and unaffiliated third party in an arm’s length transaction at the point of sale, free of all costs, including but not limited to post-production costs. If the Lessee sells any of its oil or gas production to an affiliated entity, then Lessee shall pay Lessor royalties on such oil or gas in an amount equal to __________% of the price, free of costs, that the affiliated entity, or any subsequent affiliated entity in the chain of sale, actually receives on the first sale of the oil or gas to an unrelated and unaffiliated third party in an arm’s length transaction at the point of sale, free of all costs, including but not limited to post-production costs.

If the Lessee processes its gas production before selling it to an unrelated and unaffiliated third party in an arm’s length transaction, then Lessee shall pay Lessor royalties on all of the products that Lessee may receive and sell from processing the gas, including residue gas and any and all forms of natural gas liquids. The royalties that Lessee shall pay to Lessor on each of those products an amount equal to ___% of the price, free of costs, that Lessee actually receives on selling those products to an unrelated and unaffiliated third party in an arm’s length transaction. If Lessee sells any of those products to an affiliated entity, then Lessee shall pay Lessor royalties on those products in amount equal to _____% of the price, free of costs, that the affiliated entity, or any subsequent affiliated entity in the chain of sale, actually receives on the sale of each product in an unrelated and unaffiliated third party in an arm’s length transaction.

Volumes attributable to the leased premises on which royalties are to be paid shall be computed for oil at the wellhead; volumes attributable to the leased premises on which royalties are to be paid shall be computed for gas, and its constituent products, at the point of sale.

Lessor and Lessee agree that the holding the case of Heritage Resources, Inc. v. NationsBank, shall have no application to the terms and provisions of the Lease.”

But, have I really solved the problem? How should volumes be determined (e.g. at what location)? And, if volumes and prices are being computed at a downstream sales location, why shouldn’t the royalty owners’ share be computed based on sharing in the costs of getting the product to the downstream market?

Let the debate begin – and let other draftsmen figure out how to write an even better clause!

Edward Wilhelm and Jack Wilhelm provide assistance to buyers and sellers of oil and gas properties.

THE WILHELM LAW FIRM, 5524 Bee Caves Road, Suite B5, Austin, Texas 78746; (512) 236 8400 (phone); (512) 236 8404 (fax); www.wilhelmlaw.net

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