CO2 Separation Anxiety—Is the cost of separating CO2 from casinghead gas a “production” or “post-production” cost for purposes of calculating royalties in Texas?


In a recent decision, the Supreme Court of Texas concluded that the cost of removing carbon dioxide (“CO2”) from casinghead gas after completing enhanced oil recovery operations is a “post-production” cost, thus clarifying that royalty owners may be charged their proportionate share of such costs before receiving royalties.

In most states, including Texas, the general rule is that royalties are free of “production” costs (i.e., the costs incurred by the lessee for activities necessary to extract oil or gas).[1] However, absent lease language to the contrary, both the lessor and lessee may share proportionately in any “post-production” costs (i.e., those costs incurred for activities at any point between the wellhead on the surface and the sales point that render oil or gas more marketable).[2] The classification of the cost of activities as either production or post-production costs triggers many disputes between royalty owners and their lessee-operators.

The distinction between production and post-production is particularly significant with respect to enhanced oil recovery projects that involve injecting CO2 into reservoirs to aid in the extraction of oil. In certain oil fields with wells that have experienced a decline in production rates, operators sometimes engage in enhanced oil recovery operations by injecting CO2 into the reservoirs to increase well productivity. As a consequence of the recovery operation, however, wells sometimes produce “casinghead gas” (gas associated with recovered oil) that may be heavily laden with CO2 that should be removed.

Until recently, it was unclear whether the removal of CO2 from casinghead gas after enhanced oil recovery qualified as a production cost or a post-production cost. In French v. Occidental Permian Ltd., --- S.W.3d ---, 2014 WL 2895999 (Tex. June 27, 2014), the Supreme Court of Texas resolved the question.

The French case involved oil and gas leases that granted the lessors royalty “on gas, including casinghead gas or other gaseous substance produced from said land and sold or used off the premises or in the manufacture of gasoline or other product therefrom” equal to “the market value at the well of one-eighth (1/8th) of the gas so sold or used.” In addition, one of the leases at issue granted a royalty of “1/4 of the net proceeds from the sale” of “gasoline or other products manufactured and sold” from casinghead gas “after deducting [the] cost of manufacturing the same.”

Under both leases, the lessors shared in the post-production costs associated with the sale of casinghead gas. In addition, the lessee pooled the leases in 1954 pursuant to a unitization agreement which gave the lessee the discretion to use casinghead gas as part of its enhanced recovery operations.[3] As is typical of many royalty clauses regarding gas use, the parties agreed that no royalty would be paid on the use of such gas for operations.[4]

The lessee in French initiated a tertiary recovery operation in 2001 to stimulate oil wells and remedy the long decline in production in the oil field that included the leased properties at issue. As a result of this process, the wells resumed economically viable production, and the operator recovered oil that would have been lost otherwise. However, as a consequence of the recovery operation, the wells produced casinghead gas that was heavily laden with CO2. The lessee entered into an agreement with a third party, whereby the third party would process the gas and extract a majority of the CO2. The lessee agreed to pay the third party a monetary fee and an “in-kind” fee equal to 30 percent of the natural gas liquids and all of the residue gas extracted from the stream. When the lessee paid royalties, it deducted the value of the in-kind payment in proportion to the royalty owners’ interest as it would with other post-production costs.

The royalty owners sued, alleging the lessee underpaid royalties by deducting the value of the in-kind fee.  They claimed that royalties should have been paid on all the gas that came out of the well and not the gas remaining after the CO2 was removed (which was a much smaller quantity of gas).

The trial court agreed with the royalty owners and awarded $10.5 million in compensation for underpaid royalties.

The Texas Eleventh Court of Appeals reversed the decision of the trial court and the $10.5 million judgment. Among other rulings regarding the sufficiency of expert testimony to estimate market value of casinghead gas infused with CO2, the court treated the CO2 extraction as a post-production activity that may be shared by the royalty owners. The court reasoned as follows: “Because we have held that it is necessary to render the stream marketable, we also hold that it is a cost of manufacturing that must be deducted in order to determine the net proceeds from the sale, and thus the royalty.”[5]

The Supreme Court of Texas granted the royalty owners’ petition for review in January 2014[6] on whether the costs of removing the CO2 deducted by the lessee were properly considered to be production costs or post-production costs.[7]

Noting that the issue was one of first impression, the Supreme Court affirmed the appellate court’s conclusion that the CO2 separation is a post-production activity that may be shared by royalty owners and lessees if the lease so provides. The court noted that the injected CO2 remained the lessee’s property and the royalty owners were entitled to a royalty based only on the non-CO2 portion of the casinghead gas.[8] The court reasoned that, “under the parties’ agreements, [the royalty owners], having given [lessee] the right and discretion to decide whether to reinject or process the casinghead gas, and having benefitted from that decision, must share in the cost of CO2 removal.”[9] As a result, the lessee properly deducted the value of the in-kind payment from royalties.

CO2 floods, and other enhanced recovery projects, are integral to the successful management and production of valuable oil and gas resources in the state of Texas and in other jurisdictions. The French decision clarifies how those costs should be treated when calculating royalty payments pursuant to a lease that authorizes the parties to share in post-production costs. The decision reflects the potential challenges that lessees may face when sharing costs with royalty owners for necessary operations that enhance the value of production but do not fit neatly into the “production” category or “post-production” category. In addition, while the issue may be resolved in Texas, the question remains open in other jurisdictions. Lessees may wish to consider a review and analysis of their leases to identify possible areas of dispute with royalty owners over proper cost-sharing for activities that fall into a gray area between production and post-production. 


[1] Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 121-122 (Tex. 1996) (citing Martin v. Glass, 571 F.Supp. 1406, 1410 (N.D.Tex. 1983), aff'd, 736 F.2d 1524 (5th Cir. 1984)).

[2] Delta Drilling Co. v. Simmons, 338 S.W.2d 143, 147 (Tex. 1960).

[3] French, 2014 WL 2895999 at *2.

[4] Id.

[5] Id. at 224.

[6] 57 Tex. Sup. Ct. J. 154 (Jan. 15, 2014).

[7] French, 2014 WL 2895999 at *1.

[8] Id. (citing Humble Oil & Refining Co. v. West, 508 S.W.2d 812, 816-19 (Tex. 1974) (holding natural gas stored in a reservoir to prevent destruction of the field was not subject to a royalty interest upon its production with native natural gas).

[9] Id. at *7-8.

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