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.