ceasarApparently unsatisfied with its analysis in Chesapeake Exploration v. Hyder, the Texas Supreme Court revisited its original opinion on an overriding royalty clause. The Hyders remain the winners. In effect, the court replaced its reliance on earlier decisions interpreting royalty clauses with its own analysis (which looks a lot like the original).

The Basics

Let’s start with the rules:

  • An override is free of production costs but bears its share of post-production costs.
  • The parties to a contract are free to agree otherwise.
  • A royalty paid on the market value of oil at the well bears post-production costs.  That value is the commercial value less processing and transportation expenses that must be paid before the gas reaches the commercial market.
  • A royalty based on the price a lessee actually receives for gas (a “proceeds lease”) does not bear post-production costs.  The price-received basis is sufficient in itself to excuse charges to lessors of post-production costs.

The analysis

The override at issue is: “cost-free (except only its portion of production taxes) … of five percent … of gross production obtained …”.

The exception for production taxes (which are post-production expenses) cuts against Chesapeake.  It would make no sense to say that the royalty is free of production costs except for post-production taxes (no dogs, except for cats, opined Justice Hecht).

The court doesn’t agree with Hyder that cost-free cannot refer to production costs.  Drafters frequently specify that an override does not bear production costs even though it is already free of costs because it is a royalty interest. I call it the “belt and suspenders” school of document drafting.

Chesapeake argued that because the override is paid “on gross production” the reference is to production at the wellhead, making the royalty based on the market value of production at the wellhead, which bears post-production costs.  The court concluded that gross production is a reference to volume only. Specifying that the volume is determined at the wellhead says nothing about result:  “Cost-free” includes post-production costs.

The dissent

Four justices dissented, essentially seeing the same language as did the majority and disagreeing on just about every point. A highlight is their analysis of so-called production taxes. They are really post-production costs, according to the majority.

 The dissent thinks not everyone understands that distinction, and parties can allocate taxes differently than other post-production costs.

The dissent believes a statute does not turn a production cost into a post-production cost.  It simply creates a statutory exception to the common law default rule that an override is free of production costs. Second, the pro rata nature of production taxes bolsters the reading that cost-free does not refer to post-production costs.  The dissent believes that “cost free” is indicated to emphasize the default rule, clarifying that Hyder was still obligated to pay its share of production taxes.

Takeaways

  • Some operators, Chesapeake chief among them, have been condemned for gangsterism in their treatment of lessors. Think Imperator Ceaser ravishing the Roman hinterlands. Will Chesapeake go the way of most of the Ceasers? Maybe, but losing five-to-four twice suggests a legitimate legal position this time.
  • Don’t look for a policy you an count on in this case or in Heritage, other than the court will read the lease and interpret the text.

Our musical interlude – dedicated to the dissenters.

still freeWhat is your guiding principle when writing agreements?

“The more the words the less the meaning, and how does that profit anyone?” Ecclesiastes 6:11.

or

“The beginning of wisdom is the definition of terms.” Socrates

The Legal Issue

A lease grants “a perpetual, cost-free (except only its portion of production taxes) overriding royalty of five percent … of gross production obtained” for directional wells drilled on the lease but bottomed on nearby land (emphasis mine). Are deductions of post-production costs allowed? No, says the Texas Supreme Court in Hyder v. Chesapeake Exploration, a decision long-awaited by those of us who pay attention to these matters.

The court of appeals decision was the subject of a prior post.  The Supreme Court affirmed the court of appeal, which had affirmed the trial court.

Is This a Big Deal?

It certainly is for the Hyders and lessors with the same provision. Otherwise, I’m not so sure.

  • The court was split five to four.
  • The court emphasized that it was merely determining the parties’ intentions based on the language of the lease, disclaiming a broader agenda.
  • The court recognized a basic proposition in Texas law: A royalty is usually subject to post-production costs, but the parties can modify the general rule by agreement. They just didn’t do it in this case, said the court.
  • The court declined to read into Heritage Resources, Inc. v. NationsBank anything other than that the meaning of a lease is governed by a fair reading of its text.

The Rationale

In the Hyder lease the basis for royalty payment is the price received by the lessee, which the court noted is often sufficient in itself to excuse lessors from bearing post-production costs. “Cost free”, said the majority, is not merely a synonym for an ORRI. Scriveners often include “cost free” in a royalty clause to make certain that everybody understands the royalty is free of production costs, but not necessarily post-production costs, even though the language is not necessary (royalties are cost-free as a matter of law).

The court did not believe that “cost free” means free of post-production costs. But the Ecclesiastes way didn’t serve Chesapeake well.  In order to prevail Chesapeake had to prove that “cost free” could not refer to post-production costs.  The court concluded that the ORRI was to be paid on the price received by Chesapeake after post-production costs are paid.

The Dissent

Four justices would have gone with the default – ORRIs bear post-production costs. The way they saw it:

  • The ORRI clause did not allow valuation of the ORRI downstream at any point of sale. It implicated only one location – the wellhead. Post-production activities would add value to the Hyders’ ORRI, but had not yet done so at the wellhead.
  • Although the ORRI may not have been expressed using the familiar market-value-at-the-well language, they read its value to be just that. The “cost free” designation did not express an intent to abrogate the default rule. They would recognize that “cost free” simply stressed the cost free nature of the royalty without struggling to ascertain any additional meaning.
  • Siding with Socrates, they focused on the vast differences between the royalty and ORRI provisions in the Hyder lease, concluding that if the extensive, specific, and detailed free-and-clear language in the royalty clause was surplusage, so should be bare bones “cost free” designation in the ORRI clause. “Cost free” is redundant, but not meaningless. We discussed the court of appeal interpretation of the detailed royalty clause in another post.

Today’s musical interlude: Backup singers.

Bobby King, Terry Evans, and (?) Herman Johnson

Mary Wilson and Florence Ballard

All of the Platters except the dude in the middle

Consider this while celebrating the resurrection of Big Tex: When a lease prohibits post-production cost deductions, can a lessee deduct those costs from a lessor’s royalty? Yes, says Potts v. Chesapeake Exploration, L.L.C. In a market value lease, where lessee sells the gas “at the well” and the court applies the netback approach to calculating market value, the lessee is entitled to deduct post-production costs incurred after the point of sale.

That might make more sense when you know the facts. 

The lease had a “no deduct” provision:

Royalties on gas were ” … the market value at the point of sale of 1/4 of the gas so sold or used. … , [a]ll royalty paid to Lessor shall be free of all costs and expenses related to the exploration, production and marketing of oil and gas production from the lease including, but not limited to, costs of compression, dehydration, treatment and transportation.”

Chesapeake sold the gas “at the well”, and deducted no expenses attributable to Potts’ royalty payments from the time the gas was produced at the well until its first sale. To arrive at the value of the gas at this point Chesapeake took the value of the downstream market-based sale and subtracted costs and expenses incurred between the point of sale and the downstream resale point.

Potts contended that Chesapeake breached the express provisions of the no-deduct clause.

The difference in the parties’ positions arose out of how post-production marketing costs are treated in the calculation. Potts contended that Chesapeake deducted post-production costs to calculate the royalty. Chesapeake, on the other hand, contended that when applying the netback approach, post-production costs may be used to determine the market value of the gas.

The “point of sale” is the point where there is a transfer of title in an arms-length transaction in exchange for compensation.  Potts contended that “point of sale” must be read together with the no-deduct language to ascertain its meaning and when doing so, point of sale means the point where the gas is ultimately sold off of the premises. The court didn’t agree.

According to the court, ” … the netback method requires ascertaining the market value of the gas where available downstream and then subtracting reasonable post-production costs from that point to the point where it is agreed to calculate the market value for royalty purposes. In this case it was the point of sale.

The court distinguished Heritage Resources v. NationsBank, even though the royalty clauses were similar. The factual difference was that the sale in Heritage took place off-premises. Had the royalty in Heritage been calculated at the off-premises point of sale, the no-deduct clause would have prevented deducting post-production costs incurred from the point of production at the well to the point of the off-premises sale.

In this case, the sale was at the well. Therefore, the no deduct provision is consistent with Heritage.

Takeaways – the best-laid plans … 

Potts said their argument had to be correct because they wrote the no-deduct provision to comply with Heritage. But what they didn’t, and perhaps couldn’t, count on was the way Chesapeake sold its gas. Did Chesapeake plan it this way?. That seems unlikely, because at one point prior to litigation it agreed that it couldn’t deduct post-production costs.

Chesapeake’s sale was to an affiliate, about which Potts didn’t  complain. With 20-20 hindsight, maybe he should have.

The court told Potts to give it up or turn it loose (their claim, that is), but not quite in this way.

A Louisiana lessee does not owe its lessor royalties based on hedging profits, said a federal district court in Cimarex Energy Co. v. Chastant. Cimarex, the lessee, hedged its gas contracts and didn’t pay its lessor, Chastant, earnings from the hedge.

As the court described it, hedging involves buying and selling financial positions as a strategy to avoid the risk of a price fluctuation. The hedging party uses financial transaction derivatives to minimize the risk if/when the price of the commodity drops below a certain level. 

Cimarex Memorandum in Support of Motion for Summary Judgment is a good description of the hedging process and its value to oil and gas producers.

The question for the court was whether additional royalties must paid on amounts the lessee generated by a separate, purely financial, transaction from the sale of the oil and/or gas at the property.  The answer is “no”.

Chastant’s royalty clause provided for payment by Cimarex, on gas, of 1/8 of the market value at the mouth of the well and on oil, 1/8 of the price received f.o.b. the leased property.  In Louisiana, a royalty is the “landowner’s share of production, free of expenses of production.”

Chastant argued that since Cimarex calculated the hedge price in filings with the SEC, the hedge price constitutes “market value” under the lease. Chastant cited Frey v. Amoco Prodcution, a 1992 case where the Louisiana Supreme Court held that royalties were owed on a take-or-pay case settlement because the the take-or-pay payments were part of the “amount realized” under the terms of the lease. Therefore, said Chastant, any benefit derived by the lessee because of oil and gas production, even separate transactions, should be included in the calculation of the royalties due to the lessor. 

Cimarex argued that the lease royalty provisions are in keeping with well-established Louisiana principles in which “market price” is based on the market price at the well or field for the oil and/or gas. Therefore, the market price cannot be tied to some future financial transaction because of the oil and gas produced.

The court rejected Chastant’s arguments. To agree with Chastant would overturn decades of Louisiana oil and gas law by holding that standard lease language allows royalties to be based on something other than the price or value of the oil and/or gas. According to the court, such a holding would allow royalties to be based on monies earned by any transaction remotely connected to the oil or gas. Therefore, Cimarex did not owe royalties based on its hedging profits.

Many thanks to Ann Weissman for her contribution to this post.

One impediment to the correct resolution of lessors’ claims for unpaid royalties is the complexity of the contractual arrangements between producers and purchasers of production. Occidental Permian, Ltd. v. French et al offers a good example.

It is also a refresher on the basic rules of royalty calculation in Texas and, for royalty owners in suits for unpaid royalties, a look at what the court did and didn’t consider as evidence from experts. This second topic will be the subject of my next post.

Rules of Royalty Calculation (unless the lease says otherwise)

Royalties may not be reduced by production costs; postproduction costs are deducted prior to calculating royalty.

Postproduction costs include taxes, treatment costs to render hydrocarbons marketable, and transportation costs.

In a “market value at the well” lease, the market value of production from a well may be proved by one of two ways: (1) the comparable sales method, or (2) the net-back method.

Under the comparable sales method the sale price is compared to other sales that are comparable in time, quality, quantity and availability of market outlets.

The net-back method involves subtracting the reasonable post-production marketing costs from the market value at the point of sale.

A market-value lease does not give rise to an implied duty to market.

In a proceeds lease the standard of care in testing the performance of the lessee’s implied covenant is that of a reasonably prudent operator under the same or similar facts and circumstances.

The Royalty Clauses

Royalties on the Fuller lease were due on “the market value at the well of one-eighth (1/8th) of the gas so sold or used.”

Under the Cogdell Lease the lessors would receive for gas sold, “1/4 of the market value at the field.” Royalties on “ . . . gasoline and other products manufactured and sold . . . 1/4 of the net proceeds of the sale thereof, after deducting cost of manufacturing the same.”

The leases were subject to unitization agreement establishing a field wide unit for tertiary recovery using CO2 injection.

The Contractual Arrangements

Occidental was the lessee under both leases and operator. The field produced oil and casinghead gas, which was 85% CO2.

Occidental contracted with Kinder Morgan (KM) to supply the CO2 injected into the formation. After production, KM took the casinghead gas stream to its Cynara facility, where it extracted a majority of the CO2 and two-thirds of the NGLs.

KM then sent the CO2 back to the unit for reinjection and sent the remaining gas stream and the separated NGLs to the Snyder Gas Plant, where the remaining CO2 was extracted, the NGLs stabilized, the stream processed for sale, and the remaining CO2 returned to the unit. KM paid a processing fee of 25 cents per mcf to the plant owner, Torch.

Occidental paid KM an in-kind processing fee of 30% of the NGLs and 100% of the residue gas. Occidental paid royalties on 70% of the NGLs and no royalties on the residue gas. The royalty owners sued to recover royalty payments.

The Court’s Analysis

The trial court held that the entire CO2 project – transportation of CO2-laden gas to Cynara and the SGP, extraction of CO2 at both places, and return of CO2 to be re-injected – was all a production activity. The “in-kind” fee was a cost of production improperly charged to French.

The court of appeals considered two issues: (1) Did Occidental underpay royalties under either lease; and (2) Did Occidental breach an implied duty to market under either lease?

Calculation of Royalties

For the Fuller lease the trial court used the comparable-sales method. It determined that market value was equal to the value received by KM under its contract with Torch, minus the in-kind processing fee.

The court then considered the net-back method. The lessors’ damage model only subtracted the 25¢ processing fee KM paid to Torch, assuming that all activities at Cynara were production costs. At least one of the activities performed at Cynara was a post-production activity that operators could charge against royalty: removal of hydrogen sulfide. The costs of H2S removal was not presented to the court. Because that component was missing, there was no evidence to support the market price.

The Cogdell Lease paid royalties based on the net proceeds from the sale of the gas after deducting the costs of manufacturing. As discussed, the removal of H2S was necessary to render the stream marketable. Consequently, it was a manufacturing cost that must be deducted to determine net proceeds. Because the trial court did not deduct this cost, there was no evidence that Occidental had underpaid.

The Implied Duty to Market

The next issue was whether Occidental breached an implied duty to market under either lease. Because the Fuller Lease was a “market-value” lease, there was no implied duty to market.

A duty to market was implied in the Cogdell lease because it was a “proceeds” lease. The trial court had found that Occidental breached its implied duty by deducting the “in-kind” fee paid to KM, thereby obtaining a financial benefit for itself that was not shared with royalty owners. The court of appeals disagreed, for reasons that will be discussed in the next post.

Thanks to Bill Drabble for his assistance on this post.

Merry Christmas again, literally.