Court Opinion

ID: 9603717
Source: CourtListenerOpinion
Date Created: 2023-08-22 02:09:12.895773+00
Date Added: 2024-06-11T09:11:59.156203
License: Public Domain

DURHAM, Justice,
dissenting:
Two of Enron’s leases are at issue in this appeal, one entered into on January 2, 1953, by Continental Oil Co. (Enron’s predecessor in interest) and the State Land Board, and the second entered into on April 10, 1964, by Midwest Oil Corporation (also a predecessor in interest) and the State Land Board. Both leases establish that Enron must pay 12⅜% of the “reasonable market value” at the well of all gas produced and saved or sold from the leased premises. The leases define reasonable market value as the “price at which the production is sold” in a contract either approved or conditionally approved by the lessor.
Enron and the Division differ on the proper meaning of the language “price at which the production is sold.” The Division refers to section 65-1-18 of the Utah Code:
All mineral leases issued by the board shall contain such terms and provisions as the board deems to be in the best interest of the state and shall provide for such annual rental and for such royalty as the land board shall deem fair and in the best interest of the state of Utah, but the annual rental shall not be less than fifty cents per acre per annum nor more than one dollar per acre per annum and the royalty shall not exceed 12%% of the gross value of the product at the point of shipment from the leased premises.
Utah Code Ann. § 65-1-18 (Supp.1967) (repealed 1988) (emphasis added).1 The Division contends that for royalty purposes, price is equivalent to “the gross value of the product at the point of shipment.” Gross value, as defined by the federal courts and the oil and gas industry in general, includes tax reimbursements. See, e.g., Enron Oil & Gas Co. v. Lujan, 978 F.2d 212, 215 (5th Cir.1992); Hoover & Bracken Energies, Inc. v. United States Dep’t of Interior, 723 F.2d 1488, 1492 (10th Cir.1983), cert. denied, 469 U.S. 821, 105 S.Ct. 98, 83 L.Ed.2d 39 (1984); Wheless Drilling Co., 13 I.B.L.A. 21, 30-31 (1973). The majority has essentially adopted the Division’s broad definition of gross value, a definition derived from section 65-1-18, into the lease language.
The words used by the parties to these lease agreements, not the language of section 65-1-18, are the primary indication of the content of their promises. In issuing or renewing these leases, the Division could easily have used the exact language now found in section 65-1-18 to describe the royalty assessment, but it did not. The court’s function is to give the lease language its ordinary meaning, not to read statutory material into it. Furthermore, the Division could have used a royalty provision similar to that used in the section dealing with royalty payments for oil, section 4(a) of the lease. Section 4(a) states in relevant part:
When paid in money, the royalty shall be calculated upon the reasonable market value of the oil at the well, including any subsidy or extra payment which the lessees, or any successor in interest thereto, may receive, without regard as to whether such subsidy or extra payment shall be made in the nature of money or other consideration....
The fact that the lease specifically makes provision for any “subsidy or extra payment” which may be received by the lessee in exchange for oil production implies that subsidies and extra payments were contemplated in the preparation of the lease and that the parties chose to include them in the royalty provisions for oil, but not for natural gas.
Finally, the majority, by adopting the Division’s argument, misinterprets the significance of section 65-1-18 with respect to the computation of royalties. Section 65-1-18 exists to create a cap on the royalty amounts. *513Under the statute, royalties may not “exceed 12½% of the gross value of the product at the point of shipment from the leased premises.” Utah Code Ann. § 65-1-18 (emphasis added). This statute does not establish “gross value” as the basis for calculating royalties. In fact, as long as the royalty does not exceed 12½% of the gross value of the gas from the point of shipment, section 65-1-18 is not relevant to the task of determining the value of the state’s royalty share.
THE GAS PURCHASE AGREEMENTS
The most compelling indication that the “price at which the production is sold” does not mean what the majority claims is found in the gas purchase agreements Enron entered into with Colorado Interstate Gas Co. (“CIG”) and Mountain Fuel Supply Co. (“Mountain Fuel”). These agreements established the price at which Enron sold the gas. Article V, section 5.1 of the Enron-CIG agreement contained the original price provision. Provisions (A) and (C) established that after 1982, all gas purchased by CIG would be bought at the national ceiling price provided by the Federal Power Commission (“FPC”) (now the Federal Energy Regulatory Commission or “FERC”). However, in an amendment to the gas purchase agreement dated May 21, 1981, the parties agreed to increase the rate prior to 1982. The amendment stated that the rate would include
the highest prices allowed by the Federal Energy Regulatory Commission (FERC) under Section 107(c)(5) of the Natural Gas Policy Act of 1978 (NGPA) for gas delivered to Buyer by Seller from formations that qualify for such prices. Such rate shall change to conform to all such adjustments and escalations and any revisions on the date they become effective as to the sale of gas covered hereby.
The provisions for “price” in the original gas purchase agreement and each of its amendments make no reference to tax reimbursements.
Under the Enron-CIG agreement, the payment of tax reimbursements is governed by article V of exhibit A, entitled “General Conditions Gas Purchase Agreement.” This provision is not included in the article dealing with price, nor is it considered an element of the price. According to the gas purchase agreement, the tax reimbursement, while a part of the total value of the contract, is not part of the value of the gas itself. See Belnorth Petrol. Corp. v. Tax Comm’n, 845 P.2d 266, 270 (Utah Ct.App.1993) (“The fact that a natural gas purchaser is willing to absorb the ad valorem tax liability of the seller in addition to the value it pays for the gas itself, does not increase the value of the gas.” (emphasis in original)).2
The Enron-Mountain Fuel gas purchase agreement, though not as clear as the CIG agreement, compels the same conclusion. Article VII-l(a) of the Mountain Fuel agreement sets the price of gas purchased under the agreement: “The price of any gas whose maximum base price is regulated by the FERC or by a properly constituted state authority at the time of delivery (“regulated gas”) shall be the highest applicable base price, including all applicable escalations, on the date the gas is delivered.” Article I, section 15 of the agreement defines base price as “the wellhead price per MMBTU [million British thermal units] of gas, exclusive of any adjustments for taxes and production-related costs such as compression, gathering, processing, treating or other similar costs.” However, the majority has identified the base price as the “price at which the production is sold” for royalty purposes. It has concluded that we must use “total price” as defined in section Vll-l(a) of the Mountain Fuel agreement as the basis for calculating Enron’s royalty payments, i.e., total price includes báse price, plus cost and tax reimbursements allowed by statute and made pursuant to the agreement.
I agree with Enron that the “price at which the production is sold” under both gas purchase agreements is the base price, excluding tax reimbursements. The majority incorrectly assumes that all value given by the buyer in the gas purchase agreement is exchanged for a unit of production. I disagree. The tax reimbursement provisions are properly viewed as a separate part of the *514contract, distinct from the price terms. Although I recognize that the tax reimbursements are a part of the total economic value associated with the purchase agreements, I believe that they should not be viewed as having been given in exchange for the gas itself.
In the natural gas industry, producers typically enter into long-term contracts with buyers. A buyer is usually a transmission company which must extend its pipelines to the source of supply. This capital outlay may be justified only if the transmission company is assured a long-term supply of gas. Sellers, however, are unwilling to commit to long-term contracts with fixed prices given that future tax increases could turn a profitable contract into a poor deal. Therefore, the buyer is willing to give value for a long-term contract. The buyer usually bears the costs of ad valorem taxes (severance taxes) and the risk of future tax increases during the life of the contract. See Belnorth, 845 P.2d at 270. Thus, Enron receives tax reimbursements in return for its commitment to a long-term contract, not as consideration for the gas itself. Cf. Diamond Shamrock Exploration Corp. v. Hodel, 853 F.2d 1159 (5th Cir.1988) (payments made pursuant to “take-or-pay” provisions do not represent part of the value of the gas); see also Earl A. Brown, The Law of Oil and Gas Leases § 6.09(1)(A) (2d ed. 1984).
I would hold that for royalty purposes, the reasonable market value of the gas produced and saved or sold by Enron is determined by the unit price, exclusive of tax reimbursements, at which the production is sold under the gas purchase agreements entered into with CIG and Mountain Fuel.
THE “FEDERAL FLOOR” LEASE PROVISION
Notwithstanding the foregoing determination of the correct method for calculating reasonable market value, I also address the Division’s argument concerning the “federal floor” royalty provision contained in the lease agreements. The Land Board’s lease agreements contain the following clause:
Gas — LESSEE also agrees to pay to LESSOR twelve and one half per cent (12⅞%) of the reasonable market value at the well of all gas produced and saved or sold from the leased premises. Where gas is sold under a contract, and such contract has been approved in whole or conditionally by the LESSOR, the reasonable market value of such gas for the purpose of determining the royalties payable hereunder shall be the price at which the production is sold, provided that in no event shall the price for gas be less than that received by the United States of America for its royalties from gas of like grade and quality from the same field.
(Emphasis added.) In its brief, the Division characterized this provision as requiring that “the price for gas used to determine the royalty shall not be less than the price used to determine the royalties ‘received by the United States of America for its royalties from gas of like grade and quality from the same field.’” I am in complete agreement with this reading of the lease language. The majority, however, goes further, concluding that this provision requires that the state receive at least as much as the federal government receives in royalties. I cannot accept this interpretation.
United States lease royalties are based on more than just the unit price of production. In Hoover & Bracken Energies, Inc. v. United States Department of Interior, 723 F.2d 1488, 1492 (10th Cir.1983), the Tenth Circuit posed this question: “What is the value of production? Is it contract price, or contract price, plus severance? The latter is the value of production for payment of royalties.” In Wheless Drilling Co., 13 I.B.L.A. 21 (1973), the Interior Board of Land Appeals (“IBLA”) came to the conclusion that tax reimbursements were, in fact, given as consideration for natural gas production:
It seems obvious to us that the buyer thus is paying to the seller an amount greater than the established field price for the natural gas it purchases from the # 1 T.L. James well. It follows, therefore, that it is reasonable to compute the Federal royalty of the natural gas taken from this well on a unit value consisting of the field price established by FPC plus the amount of the severance tax reimbursed by the buyer.
*51513 I.B.L.A. at 30. Since Wheless, federal courts addressing this issue have taken the position that tax reimbursements are given as consideration for the gas itself and, as such, must be included in the computation of the United States’ royalty share. Enron Oil & Gas Co. v. Lujan, 978 F.2d 212, 215 (5th Cir.1992); Hoover, 723 F.2d at 1490.
However, in Wheless, Hoover, and other federal eases cited by the Division and the majority, the IBLA and federal courts were interpreting 30 C.F.R. § 221.47, which states:
The value of production, for the purpose of computing royalty shall be the estimated reasonable value of the product as determined by the supervisor, due consideration being given to the highest price paid for a part or for a majority of production of like quality in the same field, to the price received by the lessee, to posted prices and to other relevant matters. Under no circumstances shall the value of production of any of said substances for the purposes of computing royalty be deemed to be less than the gross proceeds accruing to the lessee from the sale thereof or less than the value computed on such reasonable unit value as shall have been determined by the Secretary.
(Emphasis added.) Wheless, for example, focused on the interpretation of the term “gross proceeds” as contained in 30 C.F.R. § 221.47. Wheless established that for purposes of federal royalties, gross proceeds include “the established field price for the natural gas plus any additional sums paid by the purchaser of the gas to the unit operator as consideration for the purchase of gas from the unit of which the federal lease is a part.” 13 I.B.L.A. at 30-31 .3
In the case at hand, 30 C.F.R. § 221.47 has no application. As I mentioned previously, section 65-1-18 does not require that the state’s royalty be based on “gross value” or “gross proceeds,” as does the federal statute. The state’s royalty, as established by the leases in question, is based on the “reasonable market value,” as indicated by the price of the gas sold under a contract. Moreover, our standard of review is entirely different from that employed by the federal courts. In Wheless, the IBLA was construing its own regulations. 13 I.B.L.A. at 30-31. In Hoover, the court deferred to the IB LA’s interpretation of its own regulations. 723 F.2d at 1489-90. We are not required to grant deference to the Division. Rather, we may decide for ourselves the proper basis for the state’s royalty share. The federal cases relied on by the Division and the majority are thus entirely distinguishable and not, in my view, persuasive.
Furthermore, as Enron points out in its brief, both the Chapita Wells and the Natural Buttes Units consist predominantly of oil and gas leases issued by the United States. The gas produced from these United States leases is sold under the same gas purchase agreements as the gas sold from the wells on state land. Both CIG and Mountain Fuel pay exactly the same rate for gas from state and federal lands. Enron’s lease agreement with the state merely stipulates that the price received for production under approved natural gas purchase agreements shall not be less than the price received for production on federal leases. It certainly does not require that all elements of royalty valuation be the same for state leases as for federal leases. Therefore, I would hold that Enron is in compliance with the “federal floor” provision of its lease because the prices for gas sold from state and federal lands in the Chapita Wells Unit Area and the Natural Buttes Unit Area are identical.
ZIMMERMAN, C.J., concurs in the dissenting opinion of DURHAM, J.
HALL, J., acted on this case prior to his retirement.

. The text of section 65-1-18 relied on by both parties, the majority, and this dissent was not adopted until 1967. Compare Utah Code Ann. § 65-1-18 (1953) with Utah Code Ann. § 65 — 1— 18 (Supp.1967). As the parties are unconcerned with the discrepancy and both leases have since been renewed under the current text of section 65-1-18, I note the distinction purely for informational purposes.

. Belnorth Petroleum Corporation is the predecessor in interest to Enron.

. Even if Utah royalties were based upon "gross value,” we would not necessarily include tax reimbursements in the calculation, because, as observed earlier, tax reimbursements are not necessarily given as consideration for the natural gas itself, but for other economic value associated with the contract.