HARVEY E. YATES COMPANY v. POWELL, 98 F.3d 1222 (10th Cir. 1996)

HARVEY E. YATES COMPANY, a New Mexico corporation; NEW MEXICO OIL GAS ASSOCIATION, Plaintiffs-Appellees, v. RAY POWELL, Commissioner of Public Lands for the State of New Mexico, Defendant-Appellant.

No. 95-2214.United States Court of Appeals, Tenth Circuit.
Filed October 16, 1996. Rehearing Denied November 13, 1996.

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Jan Unna, Special Assistant Attorney General, Santa Fe, New Mexico (Kelly Brooks, Special Assistant Attorney General, with her on the brief), for Defendant-Appellant.

Andrew J. Cloutier of Hinkle, Cox, Eaton, Coffield Hensley, Roswell, New Mexico (Harold L. Hensley, Jr., with him on the brief), for Plaintiffs-Appellees.

Appeal from the United States District Court for the District of New Mexico.

(D.C. No. CIV 90-715M)

Before SEYMOUR, Chief Judge, TACHA and EBEL, Circuit Judges.

EBEL, Circuit Judge.

[1] Appellees Harvey E. Yates, Co. (“HEYCO”) and the New Mexico Oil and Gas Association (“NMOGA”) filed this declaratory judgment action in state district court in Chaves County, New Mexico against the New Mexico Commissioner for Public Lands. Appellees sought a judgment declaring invalid a revised New Mexico State Land Office regulation governing the calculation and payment of royalties under state oil and gas leases (“Rule 1.059”). The Commissioner removed the action to federal district court pursuant to 28 U.S.C. § 1441, 1446 (1994) and asserted various counterclaims against Appellee HEYCO. The Commissioner’s counterclaims sought royalty payments or corresponding damages from HEYCO arising out of HEYCO’s acceptance of cash payments in settlement of certain take-or-pay disputes. The federal district court granted summary judgment to HEYCO on the Commissioner’s counterclaims, holding that no royalty was due on the settlement proceeds received by HEYCO. In a separate ruling, the district court also granted summary judgment to Appellees on their claim for declaratory relief and apparently held Rule 1.059 invalid in its entirety. The Commissioner now appeals both summary judgment rulings. We exercise jurisdiction pursuant to 28 U.S.C. § 1291 and affirm in part, reverse in part, and remand for further proceedings.

[2] I. BACKGROUND
[3] The New Mexico Commissioner of Public Lands is the executive officer of the New Mexico State Land Office (“SLO”), which holds over thirteen million acres of state land in trust for various specified beneficiaries, including schools and institutions of higher learning. See N.M. Stat. Ann. Section(s) 19-1-1, 19-1-2, 19-1-17 (Michie 1994). Revenues to support these beneficiaries are obtained in primary part from oil and gas producers, who lease oil and gas interests in the SLO lands and pay a royalty to the state pursuant to statutory leases. Although the Commissioner is authorized by statute to execute and issue oil and gas leases on SLO lands, N.M. Stat. Ann. Section(s) 19-10-1
(Michie 1994), the state legislature sets the terms and conditions of the oil and gas leases, and directs the Commissioner to use the form leases as set forth in the New Mexico Public Land Code. See N.M. Stat. Ann. Section(s) 19-10-4 (Michie 1994) (directing commissioner to use legislative form leases); see also N.M. Stat. Ann. Section(s) 19-10-4.1
to-4.3 (Michie 1994) (containing actual form leases).

[4] Appellee NMOGA is an unincorporated trade association made up of various individuals and entities involved in oil and gas exploration,

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development and production in New Mexico. Many members of NMOGA are lessees under state oil and gas leases. Appellee HEYCO is a natural gas producer which holds a number of statutory leases on lands owned in trust by the SLO.

[5] A. The Royalty Dispute
[6] In the late 1970s and early 1980s, HEYCO entered into long-term gas supply contracts with various pipeline companies pursuant to which HEYCO agreed to supply the pipeline companies, at stipulated prices, with natural gas produced from certain state gas leases. In 1989, HEYCO had thirty-three such gas supply contracts with the El Paso Natural Gas Company and two with the Transwestern Pipeline Company. These contracts each contained “take-or-pay” clauses which obligated the pipeline purchasers either to take a certain minimum amount of gas each year or, failing to do so, to pay HEYCO the difference in value between the minimum contract amount and the amount actually taken.

[7] At the time these gas supply contracts were entered into, federal regulatory price ceilings on natural gas sold in the interstate market had resulted in decreased production and availability of natural gas. See generally Prenalta Corp. v. Colorado Interstate Gas Co., 944 F.2d 677, 679-80 (10th Cir. 1991) (discussing effects of federal regulation on interstate gas market). Pipeline companies therefore were willing to enter into long-term contracts with substantial take-or-pay obligations in order to ensure a steady supply of natural gas for their customers. Id. HEYCO’s gas supply contracts with Transwestern and El Paso were representative of this type of long-term take-or-pay contract.

[8] Following deregulation of natural gas pricing in the mid-1980s, the supply of natural gas increased and the market price dropped sharply. Pipeline companies, however, continued to be obligated under their existing take-or-pay contracts to purchase large quantities of natural gas at an above-market contract price.[1] In response to these economic forces, pipeline companies generally began reducing their gas “takes” without making any corresponding take-or-pay payments to producers. See Prenalta, 944 F.2d at 680. In HEYCO’s case, for example, El Paso and Transwestern not only reduced their gas “takes,” but also unilaterally lowered to market level the purchase price of any gas actually taken.

[9] Based on these price and take deficiencies, HEYCO made a claim against Transwestern for breach of its gas supply contracts. HEYCO subsequently entered into settlement negotiations with Transwestern, during which Transwestern sought amendments to the price and quantity terms of the gas supply contracts in exchange for a “buy down” payment.[2]
Specifically, Transwestern hoped to lower its take obligations and to amend the contract to add a “market-sensitive” clause that would set the price of gas according to prevailing market rates. In January 1989, HEYCO agreed to accept a $275,000 nonrecoupable[3] buy down payment in exchange for certain price and take reduction amendments to the supply contracts. (“Letter Agreement,” Appellant App. at 135-41.) For the remaining period of the contracts, Transwestern paid HEYCO the generally prevailing market price for its natural gas, which was substantially lower than the prior contract rate. The State of New Mexico has not received a royalty payment from HEYCO on the Transwestern settlement proceeds, although

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HEYCO has paid the state all royalty on gas produced and sold at the lower spot market price since the Transwestern settlement.

[10] In February 1989, HEYCO also negotiated a settlement agreement with El Paso. (“Settlement Agreement and Release,” Appellant App. at 143-46.) Pursuant to this agreement, HEYCO accepted a $312,181 nonrecoupable “buy out” payment[4] from El Paso. In exchange, HEYCO agreed to terminate the El Paso gas supply contracts and to discharge El Paso from any further obligations thereunder. HEYCO has not paid the State of New Mexico any royalty on the buy out proceeds received from El Paso.

[11] Before the district court, the Commissioner asserted a counterclaim against HEYCO arising out of HEYCO’s failure to pay royalties on the El Paso and Transwestern settlement proceeds. The Commissioner’s counterclaim sought royalty payments under five separate legal theories: (1) breach of the duty to market and breach of the duty of good faith and fair dealing; (2) constructive sale of gas; (3) breach of the duty to pay royalties; (4) unjust enrichment; and (5) third-party beneficiary. The district court held that no royalty was due under the express terms of the New Mexico statutory lease and granted summary judgment to HEYCO on the Commissioner’s counterclaim.

[12] B. The Rule 1.059 Controversy
[13] On June 1, 1988, the Commissioner circulated a proposed amendment, entitled “Calculating and Remitting Oil and Gas Royalties,” to Rule 1.059 of the SLO regulations. The amendment to Rule 1.059 was the Commissioner’s attempt to standardize the practice of calculating royalties under state oil and gas leases (Rule 1.059(A), Appellant App. at 352), and to combat what the Commissioner perceived to be widespread underreporting of royalties by lessees. After the notice and comment period, the amendment to Rule 1.059 was adopted and became effective on January 1, 1990. For purposes of this appeal, the most important provision added by the amendment is a detailed definition of “proceeds” upon which lessees must now base their royalty payments to the state. See Rule 1.059(B)(13). The “proceeds” definition requires lessees to pay royalties to the state based on “the total consideration accruing to the lessee,” and provides an extensive, yet nonexhaustive, list of examples. Id.[5]

[14] In addition to the “proceeds” definition, amended Rule 1.059 imposes upon state lessees complicated accounting requirements with respect to oil and gas that is either sold, processed or transported under contracts which are not “arm’s-length” agreements as defined by the Rule. According to the Commissioner, the purpose of the “arm’s-length” provisions is to value oil and gas for royalty purposes at a true market value rather than an artificially low non-arm’s-length price. Amended Rule 1.059 also requires lessees to obtain SLO approval of accounting procedures contained in non-arm’s-length contracts for the sale of processed gas. Under subsection (F) of the Rule, the Commissioner

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may disapprove of a lessee’s proposed methodology for calculating deductible processing costs and impose a different methodology which more reasonably reflects the actual costs of processing. See Rule 1.059(F)(2)(c).

[15] Appellees argue that by promulgating Rule 1.059, the Commissioner unilaterally has imposed substantial new obligations upon state oil and gas lessees. Appellees contend that Rule 1.059 thus constitutes an unconstitutional impairment of contracts and a denial of due process under both the federal and state constitutions. Appellees also argue that the Commissioner exceeded his authority under state law and usurped the legislative power in promulgating the Rule. The district court, in granting summary judgment to Appellees, agreed that the Commissioner acted without authority in promulgating Rule 1.059. The court also agreed with Appellees’ argument that the Commissioner’s action was a usurpation of legislative power. The court did not address Appellees’ other state or federal constitutional claims.

[16] II. DISCUSSION
[17] We review the grant of a motion for summary judgment de novo, under the same standard applied by the district court pursuant to Fed.R.Civ.P. 56(c). Universal Money Ctrs., Inc. v. ATT, 22 F.3d 1527, 1529 (10th Cir.), cert. denied, 115 S.Ct. 655 (1994). Summary judgment is appropriate “if the pleadings, depositions, answers to interrogatories, and admissions on file, together with the affidavits, if any, show that there is no genuine issue as to any material fact and that the moving party is entitled to a judgment as a matter of law.” Fed.R.Civ.P. 56(c). If there is no genuine issue of material fact in dispute, we must determine whether the substantive law was correctly applied by the district court. Applied Genetics Int’l v. First Affiliated Sec., Inc., 912 F.2d 1238, 1241 (10th Cir. 1990).

[18]A. HEYCO’s Obligation to Pay Royalties on the Settlement Proceeds
[19] We first address whether HEYCO breached its duty to pay royalties by failing to pay the state its royalty share of the settlement proceeds received from El Paso and Transwestern. Our inquiry begins with the gas royalty clause of the New Mexico statutory lease, which reads in part as follows:

Subject to the free use without royalty, as hereinbefore provided, at the option of the lessor at any time and from time to time, the lessee shall pay the lessor as royalty one-eighth part of the gas produced and saved from the leased premises, including casing-head gas. Unless said option is exercised by lessor, the lessee shall pay the lessor as royalty one-eighth of the cash value of the gas, including casing-head gas, produced and saved from the leased premises and marketed or utilized, such value to be equal to the net proceeds derived from the sale of such gas in the field. . . .

[20] N.M. Stat. Ann. Section(s) 19-10-4.1 (Michie 1994).[6]

[21] Although the terms of the New Mexico oil and gas lease are prescribed by statute, the lease itself is a contract between the State as lessor on the one hand and

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HEYCO as lessee on the other. We therefore apply general New Mexico contract principles in ascertaining the effect of the particular provisions of the lease. See Leonard v. Barnes, 404 P.2d 292, 302 (N.M. 1965) (noting that an oil and gas lease “is merely a contract between the parties and is to be tested by the same rules as any contract”). Unless its provisions are ambiguous, “the lease must be given the legal effect resulting from a construction of the language contained within the four corners of the instrument.” Owens v. Superior Oil Co., 730 P.2d 458, 459 (N.M. 1986) (citing cases). A contract is ambiguous when its language “can be fairly and reasonably construed in different ways.” Harper Oil Co. v. Yates Petroleum Corp., 733 P.2d 1313, 1316 (N.M. 1987).

[22] 1. “Production is the key to royalty”
[23] Here, we find the royalty clause to be clear and unambiguous: Under its plain terms, the lessee need only “pay the lessor as royalty one-eighth of the cash value of the gas . . . produced and saved from the leased premises. . . .” N.M. Stat. Ann. Section(s) 19-10-4.1
(Michie 1994) (emphasis added). Thus, the lessee is not obligated to pay a royalty on the “cash value of the gas” in the abstract, but only on the cash value of gas which is actually “produced and saved” from the leased property. See Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159, 1165-68 (5th Cir. 1988) (holding that under similar “production”-type royalty clause, “royalties are not due on `value’ or even `market value’ in the abstract, but only on the value of production saved, removed or sold from the leased property.”). This construction of the lease agreement not only is compelled by the plain language of the royalty clause, but also comports with the interpretation adopted by the majority of courts which have addressed the “production”-type royalty clause. See, e.g., Mandell v. Hamman Oil Ref. Co., 822 S.W.2d 153, 165 (Tex.Ct.App. 1991) (citing Diamond Shamrock, 853 F.2d at 1167-68) (“Production is the key to royalty.”); Killam Oil Co. v. Bruni, 806 S.W.2d 264, 267 (Tex.Ct.App. 1991) (“[T]he lease entitled the [lessor] to royalty payments on gas actually produced.”); State v. Pennzoil Co., 752 P.2d 975, 981 (Wyo. 1988) (“By its clear terms, [the lease] manifests the intention of the parties that royalty payments were to be made only in the event of production from the lease, that is, after physical extraction of the gas from the land and its sale or use.”); Diamond Shamrock, 853 F.2d at 1165 (“[R]oyalties are not owed unless and until actual production. . . .”).

[24] In State v. Pennzoil Co., the Wyoming Supreme Court was called upon to interpret a similar lease provision requiring the payment of royalties “on gas . . . produced from said land saved and sold or used off the premises. . . .” 752 P.2d at 976 (emphasis in original). At issue in that case was whether the State of Wyoming was entitled, as lessor, to a royalty on recoupable take-or-pay payments received by the lessees. Id. The State argued that the royalty clause was ambiguous and thus should be interpreted broadly to require royalties “on all proceeds relating to th[e] gas whether or not actual production and sale had occurred.” Id. at 978-79. The court rejected this argument, holding that the express terms of the lease required actual “production” of gas to trigger the lessees’ duty to pay royalty:

The word “production” has an established legal meaning when used in a royalty or habendum clause of an oil and gas lease. “Production” requires severance of the mineral from the ground. . . . [T]he lease demonstrates that the parties intended the general meaning of “production.” . . . This language manifests the proposition that royalties are due only upon physical extraction of the gas from the ground and its removal.

[25] Id. at 979 (citations omitted).

[26] Similarly, in Diamond Shamrock Exploration Co. v. Hodel, 853 F.2d 1159, 1163 (5th Cir. 1988), the Fifth Circuit construed a federal off-shore lease calling for royalties of a certain percentage, “in amount or value of production saved, removed, or sold from the leased area.” The court held that this language expressly conditioned the payment of royalties upon “production” of gas, id. at 1165, and that “[f]or purposes of royalty calculation and payment, production does not

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occur until the minerals are physically severed from the earth.” Id. at 1168. Thus, the court concluded, because take-or-pay payments are not payments for produced gas, but rather are payments for the pipeline-purchaser’s failure to take produced gas, such payments are not subject to the lessor’s royalty interest. Id. at 1167.

[27] Other courts have applied the reasoning of Pennzoil and Diamond Shamrock to hold that, under a “production”-type royalty clause, no royalties are due on cash payments received in settlement of the take-or-pay provision of a gas supply contract. In Mandell v. Hamman Oil Ref. Co., 822 S.W.2d 153, 164 (Tex.Ct.App. 1991), for example, the Texas Court of Appeals held that royalties were not due on the take-or-pay portion of a settlement because “[t]ake or pay is not a payment for production; it is a payment for nonproduction.”[7]
Similarly, in Killam Oil Co. v. Bruni, 806 S.W.2d 264, 268
(Tex.Ct.App. 1991), the court held that a lessor was “not entitled to royalties on the settlement proceeds arising from the take-or-pay provision of the contract . . . because under a standard lease, take-or-pay payments do not constitute any part of the price paid for produced gas. . . .” Accord Lenape Resources Corp. v. Tennessee Gas Pipeline Co., 925 S.W.2d 565, 569-70 (Tex. 1996); TransAmerican Natural Gas Corp. v. Finkelstein, No. 04-95-00365-CV, 1996 WL 460010, at *6-*8 (Tex.Ct.App. Aug. 14, 1996) (en banc); Roye Realty Developing, Inc. v. Watson, No. 76,848, 1996 WL 515794, at *9 (Okla. Sept. 10, 1996); Independent Petroleum Ass’n of Am. v. Babbitt, 92 F.3d 1248, 1259-60 (D.C. Cir. 1996).

[28] From these cases, we believe that three guiding principles emerge that are applicable to the issues here. First, royalty payments are not due under a “production”-type lease unless and until gas is physically extracted from the leased premises. Second, nonrecoupable proceeds received by a lessee in settlement of the take-or-pay provision of a gas supply contract are specifically for non-production and thus are not royalty bearing. Third, any portion of a settlement payment that is a buy-down of the contract price for gas that is actually produced and taken by the settling purchaser is subject to the lessor’s royalty interest at the time of such production, but only in an amount reflecting a fair apportionment of the price adjustment payment over the purchases affected by such price adjustment.

[29] In adopting this three-part framework, we reject the Commissioner’s suggestion that the “production” language in the royalty clause lease should not be strictly construed. The Commissioner argues that the entire lease agreement should be evaluated in light of the parties’ intent in entering into the contract, which the Commissioner characterizes as a “cooperative venture” between lessor and lessee to develop the land and split all economic benefits arising therefrom. The Commissioner’s “cooperative venture” theory is an extension of the so-called “Harrell rule.” See Thomas A. Harrell, Developments in Nonregulatory Oil and Gas Law, 30 Inst. on Oil Gas L. Tax’n 311 (1979). Under the Harrell rule, a gas lease is a symbiotic endeavor in which “the lessor contribut[es] the land and the lessee contribut[es] the capital and expertise necessary to develop the minerals for the mutual benefit of both parties.” Id. at 334. A corollary to the “cooperative venture” theory is the argument that buy-down or buy-out settlement payments enable the lessee to sell the released gas on the open market at a cheaper price, and, accordingly, that subsequent production and sale of such gas to a third party should be deemed to be at a price consisting of two figures: the spot price received from the third party and an allocated portion of the settlement payment. The Commissioner relies on two cases which have applied the Harrell rule to require the payment of royalties on take-or-pay settlement proceeds:

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Frey v. Amoco Prod. Co., 943 F.2d 578 (5th Cir. 1991) [“Frey I”], withdrawn in part on reh’g and question certified, 951 F.2d 67 (5th Cir. 1992) (per curiam), certified question answered, 603 So.2d 166 (La. 1992) [“Frey II”], reinstated in part on reh’g, 976 F.2d 242 (5th Cir. 1992) (per curiam); and Klein v. Jones, 980 F.2d 521 (8th Cir. 1992), aff’d after remand, 73 F.3d 779 (8th Cir. 1996), cert. denied, 64 U.S.L.W. 3808 (U.S. Oct. 7, 1996) (applying Arkansas law).

[30] In Frey, a private lessee-producer received a $66.5 million take-or-pay buy down payment from a pipeline company. $20.9 million of this amount represented a nonrecoupable settlement payment; the remaining $45.6 million represented a payment for accrued take-or-pay deficiencies, but which the pipeline could later recoup in the form of make-up gas. Frey I, 943 F.2d at 580. The royalty clause in the relevant lease agreement required the producer-lessee to pay a “royalty on gas sold by Lessee [at] one-fifth (1/5) of the amount realized at the well from such sales.” Id. (brackets in original.) Although the lessee eventually paid royalties on the recoupable portion of the settlement (as the corresponding make-up gas was taken), no royalties were ever paid on the $20.9 million in nonrecoupable settlement proceeds. The lessors filed suit in federal district court seeking payment of royalties on the nonrecoupable settlement proceeds. Applying Louisiana law, the district court ruled against the lessors. 708 F. Supp. 783, 787 (E.D. La. 1989), rev’d, 943 F.2d 578
(5th Cir. 1991). The Fifth Circuit reversed, holding that a royalty was due the lessors under the express terms of the lease agreement, which tied royalties to “sales” of gas rather than the “production” of gas. See Frey I, 943 F.2d at 581. In so holding, the Fifth Circuit distinguished its earlier Diamond Shamrock decision, where take-or-pay payments were held not subject to a royalty under a lease agreement requiring royalties to be paid on the “amount or value of production saved, removed, or sold.” Id. (emphasis in original). The Diamond Shamrock case was distinguishable, the Fifth Circuit concluded, because unlike the “sale” of gas, which in Louisiana is accomplished at the time the gas purchase contract is executed, the “production” of gas requires actual severance of the minerals from the ground. Id.; see also id. at 588 (Jones, J., concurring) (“[W]e are not attempting to overrule the Diamond Shamrock case, whose outcome depended upon a standard production-type royalty clause.”).

[31] On rehearing, the Fifth Circuit withdrew that portion of its opinion dealing with the royalty issue and certified the question to the Louisiana Supreme Court. Frey v. Amoco Prod. Co., 951 F.2d 67 (5th Cir. 1992) (per curiam). Responding to the certified question, the Louisiana Supreme Court agreed with the Fifth Circuit’s distinction between the “production”-type royalty clause construed in Diamond Shamrock and a clause requiring royalties to be paid on the “sale” of gas. See Frey II, 603 So.2d at 179. According to the court, the “sale” of gas — as opposed to the “production” of gas — occurs under Louisiana law when the gas purchase contract is executed. Id. (citing La. Civ. Code. Ann. arts. 1767, 1775, 2450, 2471 (West 1987)). Thus, the settlement proceeds constituted a part of the amount realized by the lessee from the “sale” of gas, and the lessors therefore were entitled to a royalty share under the express terms of the lease agreement. Id. at 178.

[32] Although the Louisiana Supreme Court found that the settlement payments were part of the amount realized from the “sale” of gas, the court chose not to base its decision on this fact alone. Rather, the court also invoked Professor Harrell’s “cooperative venture” theory. Frey II, 603 So.2d at 173. In this regard, the court noted that under Louisiana law, an oil and gas lease is a “cooperative venture in which the lessor contributes the land and the lessee the capital and expertise necessary to develop the minerals for the mutual benefit of both parties.” Id. (citing Henry v. Ballard Cordell Corp., 418 So.2d 1334, 1338 (La. 1982)). Based on Professor Harrell’s rule, the Frey II court gave the royalty clause an “expansive reading,” id., such that the receipt by the lessee of any economic benefit traceable to the mineral lease triggers the lessee’s duty to pay royalties:

The lease represents a bargained-for exchange, with the benefits flowing directly

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from the leased premises to the lessee and the lessor, the latter via royalty. An economic benefit accruing from the leased land, generated solely by virtue of the lease, and which is not expressly negated, is to be shared between the lessor and the lessee in the fractional division contemplated by the lease.

[33] Id. at 174 (citations omitted). Applying this reasoning, the court held that the take-or-pay settlement payments were subject to the lessor’s royalty interest because the payments were traceable to the lessee’s right to develop and explore the property — a right expressly granted by the lease agreement. Id. at 180.

[34] The Eighth Circuit’s decision in Klein v. Jones, 980 F.2d 521
(8th Cir. 1992), aff’d after remand, 73 F.3d 779 (8th Cir.), cert. denied, 64 U.S.L.W. 3808 (U.S. Oct. 7, 1996) applied the Harrell rule to a standard “production”-type lease arrangement. In Klein, the court reversed a district court’s order that certain payments made to the lessee-producer arising out of a take-or-pay dispute were not subject to the lessor’s royalty interest under Arkansas law. 980 F.2d at 533. In remanding the case, the Eighth Circuit opined that Arkansas, like Louisiana, would apply the “cooperative venture” approach in interpreting oil and gas leases. Id. at 531 (“We also recognize . . . that a lease arrangement is in the nature of a cooperative venture . . . to develop the minerals for the mutual benefit of both parties.”).

[35] We believe Frey II and Klein are distinguishable from the instant case. First, the Frey II and Klein courts adopted the “cooperative venture” approach largely because of unique state statutes which expanded the definition of “royalty” in mineral leases. In Louisiana, for instance, the Mineral Code states:

“Royalty,” as used in connection with mineral leases, means any interest in production, or its value, from or attributable to land subject to a mineral lease, that is deliverable or payable to the lessor or others entitled to share therein. . . . “Royalty” also includes sums payable to the lessor that are classified by the lease as constructive production.

[36] La. Rev. Stat. Ann. Section(s) 31:213(5) (West 1989). Similarly, the Arkansas statutes provide that “[i]t shall be the duty of both the lessee . . . [and the purchaser] to protect the royalty of the lessor’s interest by paying to the lessor or his assignees the same price, including premiums, steaming charges, and bonuses of whatsoever name for royalty oil or gas that is paid the operator or lessee under the Lease for the working interest thereunder.” Ark. Code. Ann. Section(s) 15-74-705 (Michie 1987). Both the Frey II and Klein courts relied on these statutory provisions in concluding that royalties were due on all economic benefits, including take-or-pay settlements, attributable to the leased land. See Frey II, 603 So.2d at 171-72
(noting the “expansive definition of royalty” provided in the Louisiana mineral code); Klein, 980 F.2d at 529 (noting the Arkansas legislature’s attempt to “expand the scope of `royalty’ by special definitions and concepts”). In contrast, the New Mexico statutes do not contain an expanded definition of royalty.[8] Rather, New Mexico’s only pertinent statute specifically connects the payment of royalties to the production of gas. N.M. Stat. Ann. Section(s) 19-10-4.1 (Michie 1994) (royalties are due on gas which is “produced and saved from the leased premises”). Thus, because Frey and Klein were decided against a different statutory backdrop, we do not find their reasoning persuasive here. See John S. Lowe, Defining the Royalty Obligation, 49 SMU L. Rev. 223, 257 (1996) (“[B]oth Frey and Klein were based in part upon unusual state statutes that may expand

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the royalty obligation. . . . Most states . . . apparently have no such legislation. Thus, to the extent that Frey and Klein were based upon statutory language, they may stand alone.”).

[37] Second, the fact that New Mexico has expressly conditioned the payment of royalties upon “production” of gas distinguishes this case from Frey, where the relevant royalty clause was triggered by “sales” of gas. Both the Fifth Circuit in Frey I and the Louisiana Supreme Court in Frey II recognized this crucial distinction. See Frey I, 943 F.2d at 581 (“The Lease affords royalty on the amount realized from sales, not on production.”); Frey II, 603 So.2d at 179 (“The Frey-Amoco Lease explicitly predicates Amoco’s obligation to pay royalty on the sale of gas. . . . Had the parties desired to condition the payment of royalties on production of gas, the Lease could easily have so provided.”).

[38] Third, the “cooperative venture” theory advocated by Professor Harrell has not apparently received very much additional support, and several recent cases have eschewed that approach in favor of a literal reading of the lease terms. For example, in Independent Petroleum Ass’n of Am. v. Babbitt, 92 F.3d 1248, 1259-60 (D.C. Cir. 1996) [“IPAA”], the court declined to require royalties to be paid upon payments to settle or adjust contract obligations unless such payments were recoupable against production and were, in fact, recouped by the settling party through actual production taken by the settling party. The mere fact that the lessee-producer ultimately produced gas freed up by the settlement and sold it on the spot market to other buyers did not provide a nexus between that production and the settlement payment such that royalties were due on the settlement payment. (Of course, the lessee-producer would owe royalties on the spot price actually obtained for any such replacement sales.) The IPAA court explained:

When gas is actually severed and sold to a substitute purchaser, the settlement payment does not serve as payment for the gas. The link between the funds on which royalties are claimed and the actual production of gas is missing. . . . The relevant question in both cases [take-or-pay payments and contract settlement payments], under Diamond Shamrock, is whether or not the funds making up the payment actually pay for any gas severed from the ground. When take-or-pay payments (or settlement payments) are recouped, those funds do pay for severed gas. But when payments (of either variety) are nonrecoupable, the funds are never linked to any severed gas. Therefore, no royalties accrue on those payments.

[39] IPAA, 92 F.3d at 1259-60 (footnote omitted). The Texas Court of Appeals reached the same result in TransAmerican Natural Gas Corp. v. Finkelstein, No. 04-95-00365-CV, 1996 WL 460010 (Tex.Ct.App. Aug. 14, 1996) (en banc overturning of prior panel decision reported at 1996 WL 148175 (Tex.Ct.App. Apr. 13, 1996)). There, the court rejected the argument that take-or-pay settlements should be allocated to subsequent production sold on the spot market to third parties. The court stated, “we reaffirm . . . that a royalty owner, absent specific lease language, is not entitled to take-or-pay settlement proceeds, whether or not gas is sold to third parties on the spot market.” Id. at *9; accord Roye Realty Developing, Inc. v. Watson, No. 76,848, 1996 WL 515794, at *9 (Okla. Sept. 10, 1996); see also Lenape Resources Corp. v. Tennessee Gas Pipeline Co., 925 S.W.2d 565, 569-70 (Tex. 1996) (holding that “the pay option under a take-or-pay contract is not a payment for the sale of gas”). But see Williamson v. Elf Aquitaine, Inc., 925 F. Supp. 1163, 1168-69 (N.D. Miss. 1996) (following the panel decision in TransAmerican Natural Gas Corp. v. Finkelstein which, as noted above, was subsequently reversed by the Texas Court of Appeals sitting en banc).

[40] Because the present case involves a standard “production”-type lease and arises under New Mexico statutory law (which is devoid of provision similar to those in Arkansas and Louisiana expanding the lessee’s royalty obligation), we predict that New Mexico would not adopt the “cooperative venture” approach. We therefore apply the plain terms of the statutory lease and conclude that the state is not entitled to a royalty unless the contested proceeds received by

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HEYCO were ultimately recouped by HEYCO in exchange for actual “production” of gas from the leased tracts — i.e., “physical extraction of the gas from the ground and its removal.” Pennzoil, 752 P.2d at 979.[9]

[41] 2. Are the El Paso and Transwestern settlement proceeds attributable to the “production” of gas?
[42] Our conclusion that royalty is tied to production does not, of course, end our inquiry. We must now determine whether the El Paso and Transwestern settlement proceeds, or any portions thereof, were paid to HEYCO for produced gas as opposed to simply buying out contractual obligations. We can attribute the settlement payments to production only if, and to the extent, the settling purchaser recoups recoupable take-or-pay payments by taking future make-up gas or takes actual production at a reduced price because of the settlement provisions.

[43] The district court granted summary judgment to HEYCO on the ground that the settlement proceeds received by HEYCO were not tied to actual “production” of gas. Our independent review of the record, however, leaves us less certain of this fact, at least as to certain portions of the settlement proceeds. We believe there exists a genuine issue of material fact whether the El Paso and Transwestern settlement proceeds are attributable solely to take-or-pay deficiencies (i.e., non-production), or whether they are attributable, at least in part, to a price adjustment for the actual production of gas from the SLO lands acquired or to be acquired by El Paso or Transwestern. We therefore reverse the grant of summary judgment in favor of HEYCO on the royalty issue and remand to the district court for further proceedings on this question.

[44] Although not entirely clear, the record in this case suggests that HEYCO sought payment from the pipelines for: (1) the difference in price between what the pipelines should have paid under their gas supply contracts with HEYCO and the lower spot market price they actually paid for gas produced prior to the settlement (“past price deficiencies”)[10] ; (2) the difference between what the pipelines would have been required to pay under the gas supply contracts and the estimated future spot market price for the gas (“future price deficiencies”) for future production subsequent to the settlement taken under the modified gas supply contracts;[11] and (3) the difference in value between the volumes of gas the pipelines were required to take under the take-or-pay provisions of the contracts and the lesser quantities of gas actually taken by the pipelines both prior to (accrued take-or-pay deficiencies) and subsequent to (future take-or-pay obligations) the settlements.

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[45] As we have noted, the duty to pay royalty under a lease which conditions royalty payments on “production” is not triggered unless and until gas is physically extracted from the leased premises. Diamond Shamrock, 853 F.2d at 1168; Pennzoil, 752 P.2d at 979. Thus, proceeds received by the lessee in settlement of the take-or-pay provision of a gas supply contract (for either accrued take-or-pay deficiencies or to abrogate future take-or-pay obligations) are not royalty bearing because they are payments for non-production. Mandell, 822 S.W.2d at 164; Killam Oil, 806 S.W.2d at 268. Although it does not appear here that any portion of the settlement payment for reduced volume of gas taken was, or will be, recoupable by future production, if there is such a recoupment tied to actual production, at that point any payments so recouped would be royalty-bearing. IPAA, 92 F.3d at 1259-60.

[46] With regard to any portions of the settlement attributed to a reduction in price, HEYCO does have a duty to pay the state a royalty on those portions of the settlements which are attributable to past price deficiencies because any such payment represents HEYCO’s recovery of underpayments for gas already produced and sold from the leased SLO lands. Cf. IPAA, 92 F.3d at 1262 n. 7 (Rogers, J., dissenting) (noting that the parties there conceded that amounts paid to resolve disputes over the price of past production are royalty bearing and considering that payments to obtain future price reductions are also royalty bearing). However, any component of the settlements that pertain to future price reductions present a more difficult question. Because we hold that the New Mexico statutory lease form does not require the payment of royalty unless and until gas is physically severed from the ground, a lessee would not be required to remit royalties up front on those amounts which are paid by a pipeline company to buy down the price of future production under the supply contract. At the same time, however, it would grant a windfall to the lessee if the lessee were permitted to retain the entire lump sum cash “buy down” without ever paying a royalty to the state on the buy-down settlement amount that is used as a partial up-front payment for later gas that is produced and taken at below-contract prices. As the Commissioner correctly points out, “if the producer receives $1.00 m.c.f. today, before the gas is taken, and then receives an additional $1.00 m.c.f. in three months when the gas is actually produced and taken, royalty should be paid on $2.00 m.c.f. To hold otherwise allows the producers to pocket $1.00 of the price without justification.” Br. of Comm’r at 19 n. 3. Moreover, if royalties were not ever payable on that portion of a settlement attributable to future price reductions on actual production taken by the settling purchaser, a lessee would be encouraged to avoid its royalty obligation by accepting large nonrecoupable payments in exchange for reduced prices on future production.

[47] With these competing considerations in mind, we hold that the lessee’s duty to pay royalty on that portion of a settlement which is attributable to future price reductions is not triggered until that future production is actually taken by the settling purchaser. Thus, when a lessee negotiates a buy down payment in exchange for a reduced future price term, the state has no right to a royalty up front on that portion of the settlement proceeds. However, as the Commissioner’s hypothetical illustrates, when the future production under the purchase contract is taken at the newly “bought-down” price, the state should receive a royalty based on both: (1) the proceeds obtained by the lessee from the sale of gas at the bought-down price; and (2) a commensurate portion of the settlement proceeds that is attributable to price reductions applicable to future production under the renegotiated gas sales agreement as production occurs. We believe this approach is faithful to the express terms of the New Mexico statutory lease, which condition royalty payments on actual production. This approach also eliminates a lessee’s incentive to circumvent the royalty clause by maximizing lump sum settlements while minimizing the future price of gas.

[48] Because the record has not been fully developed on this question, we must remand this case to the district court in order to determine which portions of the settlement

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are attributable to nonrecoupable take-or-pay payments (and thus are not royalty bearing), and which portions are attributable to past and future price deficiencies (and thus are royalty bearing to the extent that the payment is linked to actual production taken by the settling purchaser at below-initial contract prices). The district court also must determine what percentage of the sums attributable to future price deficiencies currently are subject to the state’s royalty interest. The record is not clear on this point, but because the HEYCO/Transwestern settlement was reached in 1989, more than seven years ago, it is possible that Transwestern has already taken all of the then-anticipated production upon which the future price reductions were based. If this is the case, the state would be entitled immediately to its royalty share on the entire amount of the settlement attributable to future price deficiencies. However, if Transwestern has to date taken only a portion of the anticipated production at the bought down price, then only a pro rata amount of the buy down proceeds currently would be subject to the state’s royalty interest. As noted, the record before us does not adequately answer these difficult questions, and thus summary judgment at this point is premature. We acknowledge the complexity of the district court’s task on remand, yet we expect the parties will present additional evidence as to the allocation of the settlement proceeds and will cooperate fully with the district court in conducting this difficult accounting process.[12]

[49] B. Validity of Rule 1.059
[50] The Commissioner next appeals the grant of summary judgment to Appellees on their challenge to Rule 1.059. Appellees below asserted a number of challenges to the rule under both the federal and state constitutions. The district court agreed with Appellees’ claims that the Commissioner, in promulgating Rule 1.059, had exceeded the authority given him under the New Mexico Constitution and had usurped a legislative function. Because of its holding with respect to these two claims, the district court found it unnecessary to address the balance of Appellees’ constitutional arguments. On appeal, the Commissioner contends the district court erred in three respects: first, by failing to dismiss Appellees’ challenge as unripe; second, by ruling against the Commissioner on the merits of Appellees’ state constitutional claims, and third, by striking down Rule 1.059 in its entirety without considering whether the invalid portions of the Rule could be severed and the remaining portions upheld.

[51] 1. Ripeness
[52] We first address a threshold jurisdictional issue. The Commissioner asserts that Appellees’ challenge to Rule 1.059 is not ripe because the amended Rule has not yet been applied by the Commissioner in any situation directly affecting the Appellees. Whether a claim is ripe for judicial review is a question of law which we review de novo. New Mexicans for Bill Richardson v. Gonzales, 64 F.3d 1495, 1499 (10th Cir. 1995). The familiar two-part ripeness inquiry requires us to “evaluate both the fitness of the issue for judicial resolution and the hardship to the parties of withholding judicial consideration.” Id. (quoting Sierra Club v. Yeutter, 911 F.2d 1405, 1415 (10th Cir. 1990) (quoting Abbott Labs. v. Gardner, 387 U.S. 136, 149 (1967))) (internal quotation marks omitted). In applying this test, we must “caution against a rigid or mechanical application of a flexible and often context-specific doctrine.” Yeutter, 911 F.2d at 1417.

[53] The “fitness for judicial resolution” prong requires the court to consider “both the legal nature of the question presented

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and the finality of the administrative action. . . .” Id. We believe both of these factors favor jurisdiction over Appellees’ claims. Generally, where disputed facts exist in the record and the issue presented for review is not purely a legal one, a court must exercise caution before concluding that the claim is ripe. Powder River Basin Resource Council v. Babbitt, 54 F.3d 1477, 1484 (10th Cir. 1995). However, Appellees’ challenge to Rule 1.059 presents primarily a legal question — i.e., whether the Commissioner’s promulgation of Rule 1.059 was within the bounds of the authority granted to him under New Mexico law. Resolution of this question would depend almost exclusively upon the interpretation of the relevant New Mexico statutes and constitutional provisions. Cf. id. (“[T]he question here was purely legal: Plaintiff asked the court . . . [whether a Wyoming statute] violated federal law. . . . This judgment would be based almost exclusively on Wyoming’s legal duties under federal law.”). Moreover, it is apparent from the record that Rule 1.059 is a final action. Compare Lujan v. National Wildlife Federation, 497 U.S. 871, 890-91 (1990) (challenge to Interior Department program not ripe for review under the Administrative Procedure Act because program did not constitute final agency action). Rule 1.059 became effective January 1, 1990, and, according to affidavits submitted to the district court, the Commissioner is currently applying the regulation to state oil and gas leases. We therefore conclude that Appellees’ challenge to Rule 1.059 is “fit for judicial resolution” under the first prong of the Abbott Labs. ripeness test.

[54] Applying the second prong of Abbott Labs., we believe that Appellees would suffer hardship if judicial consideration of the Rule 1.059 issue were withheld. “In evaluating potential hardship to the parties, a court should consider (1) whether the challenged rule has had a direct impact on the party challenging the rule, and (2) the possible harm to the parties of delaying judicial consideration.” Powder River, 54 F.3d at 1484 (citing Yeutter, 911 F.2d at 1415). The district court found that “the enforcement of the revised rule results in considerable financial consequences to plaintiffs in terms of new royalty payments.” Appellant App. at 413. The district court’s finding is supported by the record, which contains a host of uncontroverted affidavits from employees of various oil and gas producers who are members of NMOGA. These affidavits show that industry compliance with Rule 1.059 will be, and in some cases already is, very time-consuming and expensive.[13]
Any delay in attaining a judicial resolution of this issue will likely cause additional harm to Appellees, and thus we hold that the issue is ripe for review.

[55] 2. The Commissioner’s Authority to Promulgate Rule 1.059.
[56] The office of the Commissioner of Public Lands is established, and its powers circumscribed, by state law. In this regard, N.M. Stat. Ann. Section(s) 19-1-1 (Michie 1994) provides that:

A state land office is hereby created, the executive officer of which shall be the commissioner of public lands . . . who shall have jurisdiction over all lands owned in this chapter by the state, except as may be otherwise specifically provided by law, and shall have the management, care, custody,

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control and disposition thereof in accordance with the provisions of this chapter and the law or laws under which such lands have been or may be acquired.

[57] (emphasis added.) Similarly, the state constitution provides that:

All lands belonging to the territory of New Mexico, and all lands granted, transferred or confirmed to the state by congress, and all lands hereafter acquired, are declared to be public lands of the state to be held or disposed of as may be provided by law. . . .
The commissioner of public lands shall select, locate, classify and have the direction, control, care and disposition of all public lands, under the provisions of the acts of congress relating thereto and such regulations as may be provided by law.

[58] N.M. Const. Art. XIII, Section(s) 1-2 (emphasis added). Interpreting these constitutional and statutory provisions, the New Mexico Supreme Court has declared that the Commissioner of Public Lands “is merely an agent of the state with such powers, and only such, as have been conferred upon him by the constitution and laws of the state, as limited by the [New Mexico] Enabling Act.” Hickman v. Mylander, 362 P.2d 500, 502 (N.M. 1961); accord Zinn v. Hampson, 301 P.2d 518, 519
(N.M. 1956).

[59] In contrast to the Commissioner’s limited grant of authority, the state constitution vests the New Mexico legislature with broad powers to prescribe the terms and conditions of mineral leases on the state’s public lands. The New Mexico Constitution provides that:

Leases and other contracts, reserving a royalty to the state, for the development and production of any and all minerals . . . may be made under such provisions relating to the necessity or requirement for or the mode and manner of appraisement, advertisement and competitive bidding, and containing such terms and provisions, as may be provided by act of the legislature. . . .

[60] N.M. Const. Art. XXIV, Section(s) 1 (emphasis added). Thus, because the state legislature is the body constitutionally empowered to enact laws governing mineral leases on public lands, and because the Commissioner’s delegated authority is circumscribed by “such regulations as may be provided by law,” N.M. Const. Art. XIII, Section(s) 2, the Commissioner has no authority to promulgate rules or regulations inconsistent with legislative enactments in this area. Accordingly, in order for Rule 1.059 to be within the Commissioner’s power to promulgate, the Commissioner must show that Rule 1.059 is consistent with the terms of the statutory leases.

[61] The district court’s summary judgment order focused on only one aspect of Rule 1.059 — the Rule’s definition of “proceeds.” In essence, this aspect of Rule 1.059 requires lessees to remit royalties based on the “proceeds” obtained from the sale of gas removed from state lands, and defines “proceeds” as

the total consideration accruing to the lessee. It includes but is not limited to: reimbursement for dehydration, compression, measurement, or field gathering to the extent that the lessee is obligated to perform them at no cost to the lessor; reimbursements, payments, or credits for advanced prepaid reserve payments subject to recoupment through reduced prices in later sales; advanced exploration or development costs that are subject to recoupment through reduced prices in later sales; any other consideration given to the lessee, or any action taken or not taken in exchange for reduced prices; take-or-pay payments; and tax reimbursements.

[62] Rule 1.059(B)(13). This expansiveness of Rule 1.059’s “proceeds” definition is its downfall. Whereas the statutory lease only requires the payment of royalties on “production,” Rule 1.059 would require state lessees to pay royalties even when gas is not physically extracted from the leased premises. Specifically, Rule 1.059’s “proceeds” definition requires royalty payments based on “take-or-pay payments” — which we have now held do not bear royalties under the state leases. Moreover, as the district court pointed out, the “proceeds” definition “creates new categories of payments not already in State Leases . . . [such as] reimbursement for dehydration, compression and measurement

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of field gathering.” (Aplt. App. at 413.) Because the definition of “proceeds” in Rule 1.059 attaches new and different obligations upon lessees under the New Mexico statutory lease, we agree with the district court’s conclusion that the Commissioner exceeded his authority under state law and usurped a legislative function in promulgating that aspect of the Rule.

[63] 3. Severability of the “Proceeds” Definition
[64] Although the district court considered only the “proceeds” definition, the court apparently invalidated Rule 1.059 in its entirety. The Commissioner now argues that even if the “proceeds” definition is invalid — which we hold it is — the district court erred in not considering whether the remaining portions of the Rule could be preserved under the Rule’s severability clause. This clause provides that “[i]f any part or application of this rule is held invalid, the remainder or its application to other situations or persons shall not be affected.” Rule 1.059(G).[14]

[65] Severability of a state regulation is a question of state law. National Solid Wastes Management Ass’n v. Killian, 918 F.2d 671, 679 n. 8 (7th Cir. 1990), aff’d, 505 U.S. 88 (1992); cf. Panhandle E. Pipeline Co. v. Oklahoma ex rel. Comm’rs of Land Office, 83 F.3d 1219, 1229 (10th Cir. 1996) (addressing a statute, not a regulation). Under New Mexico law, the valid portion of a partially invalid statute can continue in force if the following three criteria are satisfied:

(1) the invalid part must be separable from the other portions without impairing the force and effect of the remaining parts; (2) the legislative purpose expressed in the valid portion can be given force and effect without the invalid part; and (3) when considering the entire act, it cannot be said that the legislature would not have passed the remaining part if it had known that the objectionable part was invalid.

[66] Giant Indus. Ariz., Inc. v. Taxation Revenue Dep’t, 796 P.2d 1138, 1140 (N.M.Ct.App. 1990) (citing Bradbury Stamm Constr. Co. v. Bureau of Revenue, 372 P.2d 808 (N.M. 1962)). The existence of a severability clause raises a presumption that the legislating body would have enacted the remaining portions of a statute even without the invalidated sections. Chapman v. Luna, 678 P.2d 687, 693 (N.M. 1984), aff’d after remand, 701 P.2d 367 (N.M.), cert. denied, 474 U.S. 947
(1985). Although these rules of construction are designed to test the severability of a statute, we see no reason why a similar inquiry should not also govern the severability of a regulation. See Marez v. State Taxation Revenue Dep’t., 893 P.2d 494, 497 (N.M.Ct.App. 1995) (noting the “commonplace technique of legislative drafting to provide for survival of non-affected provisions if portions of a statute or regulation are found to be invalid”) (emphasis added).

[67] In light of Rule 1.059’s severability provision, we hold that the district court’s failure to consider the independent validity of the other portions of Rule 1.059 was erroneous. Because severability is a legal question, Panhandle E. Pipeline XoCo., 83 F.3d at 1229-31, a reviewing court may conduct a severability analysis on appeal without resort to remand. However, the district court here never even considered the predicate question whether the other provisions of the Rule were valid. Compare Leavitt v. Jane L., 116 S.Ct. 2068, 2069
(1996) (per curiam) (considering severability of statute where district court had invalidated one provision of the statute but held the remainder valid). Thus, in the absence of a more developed record on this question, it would be imprudent in this case to conduct a severability analysis for the first time on appeal. Accordingly, we vacate that portion of the district court’s order invalidating Rule 1.059 in its entirety and we remand

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with instructions to consider: (1) whether the remaining portions of Rule 1.059 are valid; and (2) if so, whether the invalid “proceeds” definition is severable from the lawful portions of the Rule under New Mexico law.

[68] III. CONCLUSION
[69] The district court’s grant of summary judgment in favor of Appellee HEYCO on the Commissioner’s counterclaim for royalty payments is hereby REVERSED and REMANDED to the district court for further proceedings consistent with this opinion. The declaratory judgment in favor of Appellees NMOGA and HEYCO invalidating Rule 1.059 is AFFIRMED IN PART as to the “proceeds” definition but otherwise is VACATED and REMANDED to the district court in order to determine the validity of the remaining features of Rule 1.059, and to determine whether any valid portions of the Rule are sustainable under the Rule’s severability clause.