Doris FEERER; Martin Brothers, a partnership; J. Casper Heimann; Malcolm Smithson; Christine Smithson, Plaintiffs-Appellees, v. AMOCO PRODUCTION COMPANY, individually; Amerada Hess Corporation; Shell Western E & P, Inc.; Exxon Corporation, individually and as class representatives, Defendants-Appellants.
This appeal involves a dispute arising after settlement of class action litigation pertaining to the payment of royalties on carbon dioxide (CO2) produced in New Mexico and sold in West Texas oil fields for use in enhanced oil recovery projects. Pursuant to a settlement agreement, Defendants/ working interest owners assumed all post-production costs associated with compression, dehydration and gathering, marketing fees, and part of the transportation costs, thus increasing the royalties to be paid to the Plaintiffs/ royalty interest owners. When making royalty payments pursuant to the settlement agreement, however, Defendants withheld (recouped) from the newly calculated royalty that portion of the New Mexico severance tax 1 attributable to the increased royalty value. In protest of the severance tax deduction, Plaintiffs filed a Motion to Enforce Settlement Agreement with the district court.2 The district court granted Plaintiffs' motion, concluding (1) “the settlement agreement says nothing about a new method for severance tax calculations based upon differing values for royalty owners and for working interests;” and (2) under New Mexico law, “the ‘value’ of the carbon dioxide for severance tax calculations is the same for royalty interest and working interest owners,” and therefore, “Defendants are not entitled to a further ‘deduction’ in the taxable value.” Exercising jurisdiction under 28 U.S.C. § 1291 and Federal Rule of Civil Procedure 54(b), we affirm.
In the underlying class action lawsuit, Plaintiffs complained the Defendants had improperly deducted certain costs (including compression, dehydration, gathering, transportation and marketing costs) when calculating CO2 royalties owed to them. A court-approved settlement agreement specified that Defendants would no longer deduct such costs and further specified a procedure through which Defendants would remit royalties reflecting the resulting increase. However, Plaintiffs never received the full increase. Defendants deducted certain sums from the required settlement payments as additional severance taxes, reasoning that the “value” of the Plaintiffs' royalty interest increased as a result of their being relieved by the settlement from sharing in certain post-production costs.3
Defendants raise three issues on appeal, which condensed present the following question: Are Defendants entitled by state law or the terms of the settlement agreement to reallocate to Plaintiffs that portion of the state severance tax attributable to the increased value of the post-settlement CO2 royalty payments?
We answer this question in the context of affirming or reversing the district court's judgment granting Plaintiffs' Motion to Enforce Settlement Agreement. We review a district court's decision regarding the enforcement of a settlement agreement for an abuse of discretion. See Heuser v. Kephart, 215 F.3d 1186, 1190 (10th Cir.2000). An abuse of discretion occurs, however, if the district court bases it decision on an erroneous conclusion of law. See Wang v. Hsu, 919 F.2d 130, 130 (10th Cir.1990). The question presented is one of law. We review questions of law de novo. See e.g., Dang v. UNUM Life Ins. Co., 175 F.3d 1186, 1189 (10th Cir.1999).
New Mexico Law
New Mexico imposes a tax on the value of CO2 extracted from the ground:
There is imposed and shall be collected by the department a tax on all products that are severed and sold, except as provided in Subsection B of this section. The measure of the tax and the rates are:
(6) on carbon dioxide, three and three-fourths percent of the taxable value determined under Section 7-29-4.1 NMSA 1978.
N.M. Stat. Ann. § 7-29-4A(6) (emphasis added). “Value” as used in the phrase “taxable value” is defined as “the actual price received for products at the production unit, except as otherwise provided in the Oil and Gas Severance Tax Act”. N.M. Stat. Ann. § 7-29-2D.
As operators of the production unit, Defendants are charged with the responsibility of determining the “taxable value” of the CO2 they extract. See N.M. Stat. Ann. §§ 7-29-4.1, 7-29-6, 7-29-7. Then, because “[e]very interest owner shall be liable for the tax to the extent of his interest in [the CO2],” N.M. Stat. Ann. § 7-29-4(C), Defendants withhold severance taxes from payments to a royalty interest owner “for his portion of the value of products from a production unit.” N.M. Stat. Ann. § 7-29-6.
Defendants' primary argument on appeal assumes the New Mexico statutes require or at least contemplate that severance taxes may be based on different “taxable values” for different interest owners. Specifically, Defendants would have us interpret “taxable value” to mean actual price received by each interest owner (i.e., royalty interest owner versus working interest owner) as adjusted to reflect the allocation of post-production costs, rather than “actual price received for products at the production unit.” This interpretation would justify Defendants' attempt to calculate the taxable value of the Plaintiffs' proportionate share of CO2 based on its “tailgate” value (a sales price reflecting the benefit of compression, gathering, transportation and marketing), but to calculate the taxable value of the working interests' proportionate share of CO2 on the “wellhead” value (a lesser value reflecting a deduction of post-production costs from the actual price received). We reject Defendants' interpretation.
“Value” as defined by the plain language of the statute does not reflect the price received anywhere by anyone, but rather that price received “at the production unit.” The New Mexico Oil and Gas Commission has defined “production unit” to mean the “wellhead.” N.M. Admin. Code tit. 3, § 184.108.40.206; see also N.M. Stat. Ann. § 7-29-2B. As Plaintiffs note, severance tax valuation at the wellhead is logical inasmuch as the CO2 is severed from the ground at the wellhead. Moreover, it is only by valuing CO2 at the wellhead that Defendants are entitled to deduct post-production costs from the severance tax calculation at all. Because there is no sale at the wellhead, no actual price is received for CO2 at that location. Under these circumstances, the State permits operators to calculate the taxable or wellhead value by deducting costs for compression, dehydration, gathering, and transportation from the downstream sales price (such as a tailgate price) received for the product. See N.M. Stat. Ann. § 7-29-4.2C; see also N.M. Admin. Code tit. 3, §§ 220.127.116.11, 18.6.7. Defendants have provided no cogent authority to support their contention New Mexico law requires a second valuation for any portion of production attributable to an interest owner not required to share in post-production costs.4 Our obligation is to “give effect to the intent of the legislature as expressed rather than determine what the law should or should not be.” Beck v. Northern Natural Gas Co., 170 F.3d 1018, 1024 (10th Cir.1999) (quotation marks and citation omitted).
Defendants suggest at one point in their brief they were required to remit to the State of New Mexico additional severance taxes on the incremental increase in royalty payments made to Plaintiffs, and therefore should be allowed to recoup such taxes. This suggestion is misleading. We find no evidence in the record that the total amount of severance tax to be paid to the State of New Mexico increased-i.e., Defendants were not remitting to the State the amount they deducted from the increased royalty payments to the Plaintiffs. The record instead indicates that Defendants simply were attempting to reallocate the existing tax burden so as to increase the proportion paid by the royalty interest owners, and thereby decrease the working interest owners' tax payments by a corresponding amount.
In sum, we hold the calculation of severance taxes under New Mexico law is based on a single valuation of a total quantity of CO2 extracted at the wellhead during a given time period. See N.M. Stat. Ann. §§ 7-29-4.2 (taxable wellhead values of products from the same field should be comparable), and 7-29-7 (operator reports the “total value”). Although New Mexico law makes clear that each interest owner is liable for its proportionate share of the calculated tax, N.M. Stat. Ann. § 7-29-4C, the law does not mandate or even contemplate the determination of different taxable values for each of the various interest owners based on proceeds received downstream from the wellhead. We believe so long as (1) CO2 production is accurately measured and valued as a whole at the wellhead, (2) the appropriate tax rate is applied to that production to calculate the total tax owed, and (3) the total tax is allocated to the various interest owners in proportion to their fractional interest in that production, the pertinent New Mexico statutes are satisfied. Any readjustment in the allocation of the tax burden among working interest owners and royalty interest owners is left to private contract.
The Settlement Agreement
The key aspect of the settlement agreement is the calculation of royalty payments to the class vis a vis Defendants' liability for post-production costs. Specifically, Defendants agreed they would not deduct costs of compression, dehydration, gathering and marketing fees when calculating CO2 royalties. They also agreed to limit the amount of deductible transportation charges. Defendants agreed to deposit additional sums payable as royalties under the settlement agreement with the district court pending final settlement approval. Thereafter, Defendants would make the agreed upon royalty payments directly to the class members.
Nothing in the settlement agreement speaks to severance tax liability or in any way authorizes a change to the existing method for allocating severance taxes between the working interest and royalty interest owners (i.e., allocation of tax burden based on the parties' proportionate mineral interests in the total wellhead value of CO2, as determined by the actual price received for the production as a whole at the wellhead). Some Defendants admitted, “[n]o adjustment or allocation of tax liabilities was ever discussed or agreed to in the settlement.” The settlement agreement itself states “[t]he Parties do not anticipate that any [of the additional royalty payments deposited with the court] will be subject to any taxes other than state and federal income taxes,” thus indicating that to the extent the parties contemplated any tax implications of the settlement, they specifically addressed those implications.
Given our interpretation of New Mexico law and our understanding of how Defendants historically calculated severance taxes in accordance with that law, we fail to appreciate Defendants' argument that Plaintiffs are shifting severance tax liability to Defendants in contravention of the settlement agreement. If Defendants had intended to modify the prior method of severance tax allocation as described above, we believe they could and should have done so expressly. Absent such agreement, we hold Defendants are not entitled to deduct additional amounts from the agreed upon royalty payments.
Because we find nothing in New Mexico law or the settlement agreement to support Defendants rationale for reallocating to Plaintiffs a portion of the state severance tax Defendants attribute to the increased value of the post-settlement CO2 royalty payments, we conclude the district court did not abuse its discretion. Accordingly, we AFFIRM the district court's judgment enforcing the parties' settlement agreement.
1. The parties refer to the taxes at issue collectively as “severance taxes.” They represent that various other different state taxes are involved, including the Oil and Gas Conservation Tax, the Oil and Gas Emergency Tax, and the Oil and Gas Ad Valorem Production Tax, but that the distinctions are not relevant to this appeal.
2. The district court expressly retained continuing jurisdiction as to the “implementation, construction, and enforcement of” the settlement agreement.
3. Two defendants, Amoco and Shell, did not deduct any amount for severance taxes from payments deposited with the court pending court approval of the settlement agreement; however, in order to reallocate the severance tax, all defendants reduced the amount of the royalty payments made directly to the royalty interest owners after the settlement became final.
4. Defendants cite as authority a Texas administrative decision requiring each interest owner to pay severance taxes based on the actual value received. See Texas Comptroller of Public Accounts in Decision of the Comptroller of Public Accounts, Hearing No. 11,660, 1982 WL 12798, at *13 (Tex. Cptr. Pub. Acct. June 23, 1982). That decision applying Texas statutes and regulations to determine the tax liability of a working interest owner who bears all post-production costs where the royalty interest owner (the state) is exempt from taxation, is neither binding, nor particularly persuasive under present circumstances.Looking outside New Mexico, the more persuasive authority, as the district court recognized, is Mobil Oil Corp. v. Calvert, 451 S.W.2d 889 (Tex.1970), which the Texas Comptroller dismissed as distinguishable in the administrative decision cited above. In Calvert, the Texas Supreme Court held that the taxable value of natural gas for purposes of computing occupation taxes (similar to severance taxes) due the state is the same for royalty and working interest owners, notwithstanding the fact the producer had agreed to pay the royalty owners one-eighth of the gross receipts from the sale of gas. Id. at 890-92. The court held the tax to be paid to the state was “not affected by Mobil's agreement to assume payment of the processing costs theretofore paid by the royalty owners.” Id. at 892. The Texas court found “no sound basis in the [Texas] statutes for holding that the tax imposed thereby must be computed on each ownership interest separately.” Id. Accordingly, it heldthe market value of gas at the mouth of the well in cases such as this is measured, as to all ownership interests, by the total proceeds of the sale of the component parts of the gas after processing, less transportation and processing costs; and that each taxable ownership interest is liable to the State for its proportionate part of the tax computed on market value as thus ascertained.Id.; see also Tex. Att. Gen. Op. No. M-968 (Oct. 7, 1971) (specifically applying Calvert to the allocation of taxes between different interest owners when a royalty owner is tax exempt and bears no processing or transportation costs).
BRORBY, Circuit Judge.
Was this helpful?