*701OPINION
{1} This litigation stems from a dispute over the proper calculation of royalty payments on state oil and gas leases. In New Mexico, the Commissioner of Public Lands (Commissioner) “is hereby authorized to execute and issue in the name of the state of New Mexico, as lessor, leases for the exploration, development and production of oil and natural gas, from any lands belonging to the state of New Mexico, or held in trust by the state under grants from the United States of America.” NMSA 1978, § 19-10-1 (1953). In a typical oil and gas lease, lessees are granted the right to extract and sell oil and gas derived from State lands; in return, lessees pay the State a royalty. Oil and gas leases may specify payment of royalty upon a number of different measures; among them are net proceeds, gross proceeds and market value. See Brian S. Wheeler, Deducting Post-Production Costs When Calculating Royalty: WhatDoes the Lease Provide?, 8 Appalachian J.L. 1, 6 (2008).
{2} In New Mexico the language of the State oil and gas leases is prescribed by statute. Over the years, the Legislature has enacted several versions of the statutory oil and gas lease, and Lessees have entered into “hundreds” of oil and gas leases with the State. Specifically, the New Mexico Legislature enacted statutory oil and gas leases in 1919,1925,1927,1929,1931,1945,1947, and 1984. See 1919 N.M. Laws, ch. 98, § 1; 1925 N.M. Laws, ch,137,§§ 1-13; 1927N.M. Laws, ch. 46, §§ 1-4; 1929 N.M. Laws, ch.125, § 1; 1931 N.M. Laws, ch. 18, § 2; 1945 N.M. Laws, ch. 111, § 1; 1947 N.M. Laws, ch. 200, § 1; 1985 N.M. Laws, ch.195, §3.
{3} The present appeal concerns the royalty clauses contained in the 1931 and the 1947 statutory lease forms. 1931 N.M. Laws, ch. 18, § 2 (1931 lease) and 1947 N.M. Laws, ch. 200, § 1 (1947 lease). The royalty clause of the 1931 lease states, in relevant part:
2. The lessee agrees to pay the lessor the one-eighth of the net proceeds derived from the sale of gas from each well. If casing-head gas produced from said land is sold by the lessee, the lessee shall pay the lessor as royalty one-eighth of the net proceeds of said sale; if casing-head gas produced from said lands is utilized by the lessee otherwise than for carrying on the lessee’s operations for producing oil or gas from said lands, then the lessee shall pay the lessor the market value in the field of the equal one-eighth part of the casing-head gas so utilized at the time of such utilization.
1931 N.M. Laws, ch. 18, § 2. The royalty clause of the 1947 statutory lease form provides, in relevant part:
2. Subject to free use without royalty, as hereinbefore provided, the *702lessee shall pay the lessor as royalty one-eighth of the cash value of the gas, including casinghead gas, produced and saved from the leased premises and marketed or utilized, such value to be equal to the greater of the following amounts:
(a) the net proceeds derived from the sale of such gas in the field, or
(b) five cents ($.05) per thousand cubic feet (m.c.f.) . . . ; Provided, however, the cash value for the royalty purposes of carbon dioxide gas and of hydrocarbon gas delivered to a gasoline plant for extraction of liquid hydrocarbons shall be equal to the net proceeds derived from the sale of such gas, including any liquid hydrocarbons recovered therefrom.
1947 N.M. Laws, ch. 200, § 1. Both the 1931 lease and 1947 lease specify that the payment of royalty is to be calculated as a percentage of the “netproceeds” resulting from the sale of gas. By definition, “netproceeds” constitutes “the sum remaining from gross proceeds of sale minus payment of expenses.” Wheeler, supra, at 6. Therefore, it is clear that the statutory lease forms contemplate the deduction of certain costs.
{4} During 2005 and 2006, Commissioner audited ConocoPhillips Company’s (ConocoPhillips) and Burlington Resources Oil & Gas Company’s (Burlington) (together, Lessees) royalty payments. Following the Audit, Commissioner notified Lessees that they had been underpaying their royalty obligations and issued them assessments for the underpayment.
{5} Commissioner claimed that pursuant to the terms of the statutory lease forms Lessees could not deduct the post-production costs necessary to prepare the gas for the commercial market when calculating their royalty payments. Commissioner claimed that the improper deductions for post-production costs resulted in ConocoPhillips underpaying royalties by approximately $18.9 million and Burlington underpaying by approximately $5.6 million. In response to Commissioner’s audit and assessments, Lessees filed a complaint in the district court seeking a declaration that Commissioner’s assessment of additional royalty constituted a deprivation of due process, an unconstitutional impairment of contract, and breach of contract. In addition, Lessees claimed that Commissioner had exceeded his constitutional and statutory powers by issuing the assessments and had effectively usurped legislative power by seeking royalty payments under calculation methods not approved by the Legislature. In response, Commissioner alleged a host of counterclaims forbreach of contract, breach of the implied covenant of good faith and fair dealing, and breach of the implied covenant to market. In addition, Commissioner sought a declaratory judgment, an accounting, an injunction, and the cancellation of leases. Lessees sought, and the district court granted, summary judgment on several matters.
{6} This appeal centers around three orders granting summary judgment on behalf of Lessees and a fourth order denying Commissioner’s motion for reconsideration of the district court’s previous dismissal of his counterclaim for breach of the implied covenant to market. The district court certified these orders for interlocutory appeal pursuant to NMSA 1978, Section 39-3-4 (1999). The Court of Appeals then certified this appeal as a matter of “substantial public interest” to this Court pursuant to NMSA *7031978, Section 34-5-14(C)(2) (1972) and Rule 12-606 NMRA. We accepted certification, and we now address the district court’s four certified orders.
{7} In the first order, the district court granted Lessees’ motion for summary judgment on the meaning of three provisions in the 1931 and 1947 leases: the “net proceeds” royalty obligation, the “free use” clause, and Lessees’ obligation to pay royalty on drip condensate. In the second order, the district court granted Lessees’ motion for summary judgment on the meaning of the maximum price clause found in the 1947 lease form. In the third order, the district court denied Commissioner’s motion for reconsideration of the district court’s previous dismissal of Commissioner’s claim for breach of the implied covenant to market. In the last order, the district court granted Lessees’ motion for summary judgment on the deduction of reasonable costs of affiliated transactions in calculating royalty in State oil and gas leases, finding that the cost of post-production services provided hy Lessees’ affiliates is deductible to the extent it is “reasonable.”
STANDARD OF REVIEW
{8} Because three of the certified orders deal with motions for summary judgment, we first address the standard of review applicable to those motions. This Court reviews “a district court’s decision to grant summary judgment de novo.” Maralex Res., Inc. v. Gilbreath, 2003-NMSC-023, ¶ 8, 134 N.M. 308, 76 P.3d 626. Summary judgment is proper when “there are no genuine issues of material fact and the movant is entitled to judgment as a matter of law.” Self v. United Parcel Serv., Inc., 1998-NMSC-046, ¶ 6, 126 N.M. 396, 970 P.2d 582. We review “the pleadings, affidavits, and depositions presented for and against a motion for summary judgment in a light most favorable to the nonmoving party.” Deaton v. Gutierrez, 2004-NMCA-043, ¶ 12, 135 N.M. 423, 89 P.3d 672.
{9} The district court found certain disputed contractual language contained in the 1931 and 1947 lease forms to be “unambiguous.” Whether contractual terms are ambiguous is a question of law, subject to de novo review. Envtl. Control, Inc. v. City of Santa Fe, 2002-NMCA-003, ¶ 14, 131 N.M. 450, 38 P.3d 891. “The standard to be applied in determining whether a contract [term is ambiguous and] is subject to equally logical but conflicting interpretations is the same standard applied in a motion for summary judgment.” Randles v. Hanson, 2011-NMCA-059, ¶ 26, 150 N.M. 362, 258 P.3d 1154 (internal citation omitted). Courts will grant summary judgment and “interpret the meaning as a matter of law” when the “evidence presented is so plain” that it is only reasonably open to one interpretation. Id. ¶ 26. If, however, a court determines that the contract is “reasonably and fairly” open to multiple constructions, then “an ambiguity exists,” summary judgment should be denied, and the jury should resolve all “factual issues presented by the ambiguity.” Id.
{10} In making the threshold determination regarding ambiguity, courts may consider “evidence of the circumstances surrounding the making of the contract and of any relevant usage of trade, course of dealing, and course of performance.” C.R. Anthony Co. v. Loretto Mall Partners, 112 N.M. 504, 508-09, 817 P.2d 238, 242-43 (1991). “[I]f the proffered evidence of surrounding facts and circumstances is in dispute, turns on witness credibility, or is susceptible of conflicting inferences, the meaning must be resolved by the appropriate fact-finder . . . .” *704Mark V, Inc. v. Mellekas, 114 N.M. 778, 781, 845 P.2d 1232, 1235 (1993).
DISCUSSION
{11} Before we begin our review of the district court’s findings we will briefly discuss the natural gas production process. When gas is extracted from a well, it is in a form that is not commercially merchantable. In order to be sold on the commercial market, the gas must be processed. The processing of natural gas begins at the wellhead. See Natural Gas Processing: The Crucial Link Between Natural Gas Production and Its Transportation to Market, Energy Information Administration, Office of Oil and Gas, January 2006, 2, available at http://www.arcticgas.gov/ sites/default/files/documents/ 2006-eia-ng-processing.pdf. The wellhead is the location at which the gas is extracted from the ground. See 8 Howard R. Williams & Charles J. Meyers, Oil and Gas Law, at 1143 (2011) (defining wellhead as “where the mineral product is severed or removed from the ground”). Once the gas is extracted from the ground, several processes may be necessary to transform the gas into a merchantable product. These processes include: gathering, compressing, dehydrating, and treating the gas. The expenses associated with these processes are referred to as “post-production costs.” See 8 Williams & Meyers, supra, at 787 (citing Schroeder v. Terra Energy, Ltd., 565 N.W.2d 887, 890 (Mich. Ct. App. 1997), which defined post-production costs as “costs associated with making the natural gas marketable after the gas is severed or removed from the ground”).
{12} Oil and gas wells produce various types of gas: casinghead gas, conventional gas, and coalbed methane gas. Gas that is produced from an oil well is casinghead gas. 8 Williams & Meyers, supra, at 132. In processing casinghead gas, the oil and gas are separated and the gas stream is measured by a meter near the wellhead. The meter measures the volume of the gas stream and its heat content. The heat content provides information regarding how much natural gas liquids (NGLs) are present in the gas stream. The gas is then transported from the meter to a processing plant or treatment facility via pipelines or gathering lines. In order for the gas to move through the gathering lines to the processing plants, the gas must be compressed at compression stations along the pipelines. When the gas reaches the processing or treatment facility the NGLs are extracted. The NGLs are then sent further downstream for fractionation. See 8 Williams & Meyers, supra, at 405 (defining fractionation as “[a] process of separating various hydrocarbons from natural gas or oil as produced from the ground”). During fractionation the NGLs are segregated into their individual components, which are then sold. After the NGLs are extracted, the remaining gas, or the residue gas, is pure methane gas, which is then sent through different pipelines to various places throughout the country.
{13} Conventional gas is similar to casinghead gas, except that conventional gas is produced from a gas well, whereas casinghead gas is produced from an oil well. This gas moves through a separator during which some hydrocarbon liquids drip out. These hydrocarbon liquids, or drop out liquids, are sold as oil with royalties then paid on the drop out liquids as oil. After the separation, the gas is then processed in the same manner as casinghead gas.
{14} Coalbed methane gas is gas produced from coal seams and contains carbon dioxide. 8 Williams & Meyers, supra, at 152. This gas *705is gathered, compressed, and transported to the treatment plant where the carbon dioxide is removed from the methane. After the carbon dioxide is separated, the methane is sent down stream via the pipelines. Coalbed methane gas does not contain any NGLs.
Order 1: Summary Judgment on the Meaning of Net Proceeds Royalty Obligation, the Free Use Clause, and the Drip Condensate Royalty Obligation
{15} The district court’s order granting summary judgment determining the meaning of the free use clause and the extent of the Lessees’ obligation to pay royalties on drip condensate was based on its interpretation of the net proceeds language. We, therefore, begin our review with the district court’s findings regarding the meaning of the net proceeds royalty obligation.
1. Net Proceeds
{16} “Net proceeds” is defined as “the sum remaining from gross proceeds of [a] sale minus [the] payment of expenses” and “expressly contemplates deductions.” Wheeler, supra, at 6; see also Cartwright v. Cologne Prod. Co., 182 S.W.3d 438, 445 (Tex. App. 2006) (stating net proceeds “expressly contemplates deductions”). Here, the parties do not dispute that the term net proceeds contemplates deductions. Instead, the parties’ disagreement regarding the net proceeds language centers around what costs may be taken into account when calculating Lessees’ royalty obligations and the point in time at which the value of the gas is fixed for the purpose of calculating the royalty obligation.
{17} In oil and gas leases it is typical for the royalty clause to specify the calculation of net proceeds “at the well.” Scott Lansdown, The Marketable Condition Rule, 44 S. Tex. L. Rev. 667, 671 (2002-2003) (emphasis added) (internal citation omitted). When the well is specified as the point of valuation, it is generally understood that the “lessee is entitled to deduct all costs that are incurred subsequent to production, including those necessary to transport the gas to a downstream market and those costs, such as dehydrating, treating, and processing the gas, that are either necessary to make the gas saleable in that market or that increase the value of the gas.” Lansdown, supra, at 672 (footnote omitted). In Ramming v. Natural Gas Pipeline Co. of America, the Fifth Circuit interpreted a 1930 and a 1937 lease form which specified for royalty to be calculated based on “net proceeds from sales at the mouth of the well.” 390 F.3d 366, 369 (5th Cir. 2004). The court concluded that such language prohibited lessees from deducting costs incurred prior to production {i.e., those costs necessary to extract the gas from the land), but permitted the deduction of post-production costs {i.e., those costs incurred following extraction of the gas from the ground). Id.
{18} New Mexico courts have also endorsed this approach to interpreting a royalty obligation when the language provides that such payments are to be payable on net proceeds at the well. See Creson v. Amoco Prod. Co., 2000-NMCA-081, ¶¶ 11-12, 129 N.M. 529, 10 P.3d 853. In Creson, the lease specified for the payment of royalties on “net proceeds derived from the sale of Carbon Dioxide Gas at the well.” Id. ¶ 6. The Court of Appeals held that the language was “unambiguous,” id. ¶ 15, and permitted lessees to deduct the costs of post-production expenses incurred after the gas exited the wellhead, id. ¶ 24.
*706{19} Thus, if the 1931 and 1947 statutory lease forms provided for royalty on net proceeds at the well, there would be little controversy because such language typically entitles the lessee to deduct all post-production expenses. See Lansdown, supra, at 671. However, the lease forms at issue here provide for royalty to be paid on net proceeds “from the sale of such gas in the field” (1947 lease) and “from the sale of gas from each gas well” (1931 lease). Thus, the key question is whether a lease which provides for royalty payable upon “net proceeds ... in the field” or “from the sale of gas from each gas well” compels a different royalty calculation than a lease which provides for “net proceeds ... at the well.”
{20} The district court determined that the net proceeds royalty obligation contained in the 1931 and 1947 lease forms was unambiguous and found that Lessees may “net (deduct) from their gross sales price any post-production costs they reasonably and necessarily incur in selling the gas ... whether the gas sold is casinghead gas, conventional gas or coalbed methane gas, and whether the sale occurs at the wellhead, the plant tailgate or farther downstream.”1 The district court found that its interpretation was confirmed by the circumstances contemporaneous to the enactment of the 1931 and 1947 leases, subsequent lease forms enacted by the Legislature, subsequent regulatory policy, and the course of performance and dealing between Lessees and Commissioner. Furthermore, the district court found it could not follow Commissioner’s interpretation of the statutory lease forms because such an interpretation imposed an additional royalty obligation on Lessees, an action which can only be taken by the Legislature.
{21} Commissioner asserts that the district court’s interpretation of the net proceeds royalty obligations is erroneous as the express language of the lease forms sets the valuation point “in the field” and prevents Lessees from deducting any post-production expenses incurred between the wellhead and the field, i.e., plant tailgate, when calculating royalty payments. Commissioner submits that the “in the field” language requires the use of a net-back methodology, with the “field,” or plant tailgate, as the valuation point, before which deductions cannot be taken. See Wheeler, supra, at 5 (providing that under the work-back or net-back method, “the costs of transportation, processing and treatment are deducted from the ultimate proceeds of sale of the oil or gas and any extracted or processed products to ascertain wellhead value”). Commissioner contends thatbecause the lease forms place the valuation point “in the field,” Lessees are not allowed to deduct any post-production costs that are incurred between the wellhead and the plant tailgate when calculating their royalty payments. Commissioner’s main contention, therefore, centers around the valuation point and the district court’s conclusion that the net proceeds language allows for Lessees to deduct post-production costs that are incurred beyond the wellhead when calculating Lessees’ royalty obligation.
{22} Lessees contend thatthe netproceeds language indicates that the Legislature *707intended the valuation point to be at the wellhead. Lessees argue that by using the term “net proceeds” in both the 1931 and 1947 lease forms, the Legislature intended to permit lessees to deduct the post-production costs incurred in connection with the sale of their gas. Lessees, therefore, assert that the lease forms require royalty payments to be based simply on the “net proceeds” from the gas that is sold, whether it is conventional gas from a gas well or casinghead gas from an oil well. Lessees assert that the “in the field” language has no bearing on the interpretation of the 1931 lease, and does not limit their ability to deduct post-production costs from the gross sales price under the 1947 lease. Lessees, therefore, submit that the lease forms require royalty payments to be based simply on the “net proceeds” from the gas that is sold, regardless of where the sale occurred and regardless of whether it is conventional gas from a gas well or casinghead gas from an oil well.
{23} As discussed above, whether a contract contains an ambiguity is a matter of law that is reviewed de novo; therefore, we review the district court’s conclusions regarding the language contained in the 1931 and 1947 lease forms de novo. See Envtl. Control, Inc., 2002-NMCA-003, ¶ 14. In interpreting oil and gas leases, courts have generally applied the rules governing contract interpretation. Leonard v. Barnes, 75 N.M. 331, 345, 404 P.2d 292, 302 (1965). “The purpose, meaning and intent of the parties to a contract is to be deduced from the language employed by them; and where such language is not ambiguous, it is conclusive.” Cont’l Potash, Inc. v. Freeport-McMoran Inc., 115 N.M. 690, 704, 858 P.2d 66, 80 (1993) (internal quotation marks and citation omitted). A contract term may be ambiguous if it is “reasonably and fairly susceptible [to] different constructions.” Mark V, Inc., 114 N.M. at 781, 845 P.2d at 1235. In evaluating whether a term is ambiguous, “a court may hear evidence of the circumstances surrounding the making of the contract and of any relevant usage of trade, course of dealing, and course of performance.” C.R. Anthony Co.. 112 N.M. at 508-09, 817 P.2d at 242-43 (1991). If a court concludes that there is no ambiguity, “[t]he words of the contract are to be given their ordinary and usual meaning.” Rust Tractor Co. v. S. Union Gas Co., 85 N.M. 323, 324, 512 P.2d 83, 84 (1973). When interpreting an unambiguous contract, a court is limited to interpreting “the contract which the parties made for themselves [as a court] may not alter or make a new agreement for the parties.” Davies v. Boyd, 73 N.M. 85, 87-88, 385 P.2d 905, 951 (1963). Therefore, when parties have entered into a valid lease of land for oil and gas purposes, and the terms contained therein are “plain and unmistakable,” a court does not have the power to place a different interpretation upon such terms. 2 W.L. Summers, The Law of Oil and Gas § 16:3, at 505 (3rd ed. 2006).
{24} The term net proceeds refers to the “amount received in a transaction minus the costs of the transaction.” Black’s Law Dictionary 1325 (9th ed. 2009). Under a net proceeds royalty clause, royalties are to be paid based on the amount actually received by the lessee from the sale of the product less post-production costs. See Frederick R. Parker, Jr., Costs Deductible by the Lessee in Accounting to Royalty Owners for Production of Oil or Gas, 46 La. L. Rev. 895, 897 (1985-1986). The costs associated with production generally burden only operating interests and, absent an express contractual provision to the contrary, are not chargeable against the royalty interest. 3 Williams & Meyers, supra, § 645.1, at 598; 8 Williams & Meyers, supra, *708at 823 (providing production is “the act of bringing forth gas from the earth”). Even though royalty interest holders are not generally subject to the costs of production, they are usually subject to the costs that are incurred subsequent to production. Id. at 920. The costs incurred subsequent to production are considered post-production costs and are generally deducted from the sale of the product regardless of where the sale takes place. See Bice v. Petro-Hunt L.L.C., 2009 ND 124, ¶ 19, 768 N.W. 2d 496, 502 (discussing that in North Dakota the royalty owed is calculated by deducting processing costs from the gross sales revenue, a method known as the work-back method); 8 Williams & Meyers, supra, at 826; 3 Williams & Meyers, supra, § 645.2, at 598-99 (providing post-production costs are costs other than “production costs” and may include the cost of compressing, gathering, processing, treating, dehydrating, storing . . : , or transporting”). Therefore, the plain meaning of the net proceeds royalty obligations confirms the district court’s conclusion that the net proceeds royalty obligations are unambiguous as a matter of law.
{25} The extrinsic evidence considered by the district court also supports the district court’s interpretation of the net proceeds royalty obligation. In 1959, the then sitting commissioner of public lands sent a letter to state lessees directing them to remit royalty payments in the same manner in which they were to remit their state taxes in New Mexico. In New Mexico, taxes on oil and gas were to be paid based on the value of the gas at the production unit, i.e., the wellhead. See 1959 N.M. Laws, ch. 51, § 1. Thus, the commissioner directed state lessees to remit royalties based on a value at the wellhead.
{26} Thepassage ofNMSA 1978, Section 19-10-61 (1972), also sheds light on how the post-production costs are to be allocated between the state and state lessees. Section 19-10-61 requires the state to bear the post-production costs when the commissioner elects to take royalty payments in kind. Section 19-10-61 provides that
[t]he commissioner of public lands shall have the authority to negotiate and enter into agreements for the sale or exchange of royalty gas taken in kind under oil and gas leases issued by the state. Provided, however, he shall not dispose of said gas for a net consideration of less than that being received at the time of exercising the option. In selling or exchanging the gas, the commissioner of public lands shall be entitled to use the lessee’s gathering, processing and compression facilities provided that reasonable compensation is made to the lessee for such use.
Id. The district court found that requiring the state to pay reasonable compensation to state lessees for the use of their post-production facilities indicated that the Legislature was aware of the reality that was occurring in the field with respect to post-production costs. Therefore, Section 19-10-61 ’s requirement that the state pay reasonable compensation to state lessees for the use of their post-production facilities further supports the district court’s determination that post-production costs may be netted from the gross sales price when calculating royalty payments.
{27} After reviewing the statutory lease forms, the parties’ interpretations of the net proceeds language, the plain meaning, and the extrinsic evidence presented to the district court, we hold that the district court was *709correct in finding that the net proceeds royalty obligations are unambiguous as a matter of law.
{28} We now turn to Commissioner’s contention that the district court relied on inappropriate sources to guide its interpretation of the net proceeds royalty obligation. Commissioner contends that: (1) the district court could not rely on the parties’ course of dealing and course of performance because estoppel does not apply against the state; (2) the district court could not rely on extrinsic factual evidence because under the bifurcation order, the court was only to consider legal issues in the first phase of the case; and (3) the district court’s reliance on factual circumstances to interpret the lease was erroneous in light of its decision not to permit full discovery on how Lessees calculated their royalty obligations.
{29} Commissioner contends that the district court erred in its interpretation of net proceeds royalty obligations to the extent it relied on course of dealing and course of performance evidence because relying on such evidence contravenes New Mexico law prohibiting the use of equitable estoppel against the State and its agencies. Generally equitable estoppel will only be an effective defense against the state when there is a “shocking degree of aggravated or overreaching conduct or where right and justice demand it.” Waters-Haskins v. N.M. Human Servs. Dep’t, 2009-NMSC-031, ¶ 16, 146 N.M. 391, 210 P.3d 817 (quoting Wisznia v. State Human Servs. Dep’t, 1998-NMSC-011, ¶ 17, 125 N.M. 140, 958 P.2d 98). Therefore, Commissioner is correct in his assertion that New Mexico law disfavors the defense of equitable estoppel when asserted against the state or a state agency. See Lopez v. State, 1996-NMSC-071, ¶ 19, 122 N.M. 611, 930 P.2d 146 (“New Mexico courts have been reluctant to apply estoppel against the state and its agencies.”). However, it does not follow that the district court necessarily relied on an equitable estoppel defense when it relied on course of dealing and course of performance evidence in interpreting the meaning of net proceeds. The summary judgment order in question did not address whether Lessees can present an equitable estoppel defense; it explicitly only addressed the meaning of the net proceeds royalty obligations. Therefore, because New Mexico law clearly permits courts to consider course of dealing and course of performance evidence when determining whether a contractual term is ambiguous, Mark V, Inc., 114 N.M. at 781, 845 P.2d at 1235, the district court’s reliance on course of dealing and course of performance evidence was proper.
{30} Commissioner also contends that the district court’s bifurcation of the legal and factual questions precluded it from considering extrinsic evidence in making the legal determination that the net proceeds language was unambiguous as a matter of law. Even though a district court may consider evidence of course of dealing and course of performance in determining the initial question regarding whether a contractual term is ambiguous, the question regarding whether a contract contains an ambiguity remains a question of law to be decided by the district court. See id. at 781, 845 P.2d at 1235 (“The question whether an agreement contains an ambiguity is a matter of law to be decided by the trial court. The court may consider collateral evidence of the circumstances surrounding the execution of the agreement in determining whether the language of the agreement is unclear.” (internal citation *710omitted)). Because New Mexico law permits courts to consider extrinsic evidence when making the legal determination regarding whether a contract term is ambiguous, we disagree with Commissioner’s argument that the district court’s reliance on extrinsic factual evidence in finding the net proceeds language was unambiguous as a matter of law was improper.
{31} We refrain from addressing Commissioner’s contention regarding the propriety of the district court’s discovery ruling because that order was not certified for our review. Orders entered on procedural motions that do not practically dispose of the case on the merits are not final orders and therefore are generally not appealable. Griego v. Grieco, 90 N.M. 174, 176, 561 P.2d 36, 38 (Ct. App. 1977); see In re Estate of Pino, III, 115 N.M. 759, 760, 858 P.2d 426, 427 (Ct. App. 1993) (providing “orders requiring or denying discovery . . . generally do not constitute a final disposition of the proceedings . . . [and therefore are not normally appealable, except upon the granting of an interlocutory appeal”). “[AJppellate review of non-final orders is allowed only in limited circumstances” when the district court certifies the order pursuant to Section 39-3-4. Candelaria v. Middle Rio Grande Conservancy Dist., 107 N.M. 579, 581, 761 P.2d 457, 459 (Ct. App. 1988). Therefore, because the district court’s discovery order is not certified for our review, we refrain from conducting such a review.
{32} Accordingly, we conclude that the district court’s reliance on extrinsic evidence was proper, and the district court was correct in its determination that the net proceeds language of the 1931 and 1947 lease forms was unambiguous as a matter of law.
2. Free Use Clause
{33} A free use clause is an express provision that appears in most oil and gas leases and governs the right of a lessee to use products derived from the leased premises in the operation of said lease. 3 Williams & Meyers, supra, § 644.5, at 573-574.1. Both the 1931 and 1947 statutory lease forms contain such a provision. The relevant language of the free use clauses contained in the 1931 and 1947 statutory lease forms provides:
[T]he said lessor has granted and demised, leased and let, and by these presents does grant, demise, lease and let unto the said lessee, exclusively, for the sole and only purpose of exploration, development and production of oil and/or gas thereon and therefrom with the right to own all oil and gas so produced and saved therefrom and not reserved as royalty by the lessor under the terms of this lease, together with rights of way, easements and servitudes for pipe lines, telephone and telegraph lines, tanks, power houses, stations, gasoline plants, and fixtures for producing, treating and caring for such products, and . . . any and all rights and privileges necessary, incident to or convenient for the economical operation of said land, for oil and gas, with right for such purposes to the free use of oil, gas, casing-head gas, or water from said lands, but not from lessor’s water wells ....
1931 N.M. Laws, ch. 18, § 2; 1947 N.M. Laws, ch. 200, § 1 (emphasis added). The parties’ dispute surrounding the free use *711clause centers on the scope of the clause and whether it grants Lessees the free use of plant and field fuel. Plant fuel is the “[f]uel employed by a lessee in operating a plan . . . to remove sulfur from oil or gas [that is] produced by the lessee.” 8 Williams & Myers, supra, at 775. Field fuel is consumed in powering compressors located on the field gathering system. The district court found that field fuel and plant fuel are costs that Lessees remit to post-production service providers, do not amount to proceeds, and are not subject to royalties.
{34} Commissioner has previously conceded that plant fuel can be netted in computing Lessees’ royalty. Ftowever, before this Court, Commissioner argues that the free use clause does not encompass Lessees’ use of field or plant fuel. Additionally, Commissioner asserts that the free use clause restricts Lessees’ use of oil and gas without the payment of royalty to the leased premises and should not be read as allowing the unlimited use of gas for gathering, processing, or other operations that occur off the leased premises. Commissioner relies on Roberts Ranch Co. v. Exxon Corp., 43 F. Supp. 2d 1252 (W.D. Okla. 1997), to support this assertion.
{35} In Roberts Ranch, the lessees claimed that they had a right to the free use of gas in the post-production treatments that were required to make gas marketable and which occurred off the leased premises. Id. at 1257. The lessors asserted that the gas used by lessees at a treatment plant located off the leased premises was subject to royalties. Id. at 1256. The court concluded that because lessees were obligated to bear all costs associated with making gas marketable, a free use clause should not be read as passing the post-production costs on to the lessors. Id. at 1257. The court based its decision on the marketable condition rule, which requires lessees to bear all costs associated with placing the gas in marketable condition.
{36} Lessees assert that Commissioner’s reliance on Roberts Ranch is misplaced. Lessees contend that requiring royalties to be paid on the use of field and plant fuel would contradict both the free use clause and net proceeds language of the lease forms and would transform a permissive benefit into an affirmative obligation.
{37} Lessees point out that in the standard form field service contracts, the service-provider bargains to retain a small percentage of the gas produced from the leases for use as field and plant fuel. This fuel is used as partial compensation for post-production service providers. Lessees contend that because field and plant fuel is used as partial compensation for post-production service providers and because they do not derive proceeds from such use, they do not have to pay royalties on such fuel. We agree.
{38} A royalty clause that provides that the “lessee may use oil [or gas] in operating the premises ... is not under a duty to pay royalty on the amount so used.” 3 A Summers, supra, § 33:7, at 153 (footnote omitted). When a royalty clause provides that the lessee is privileged to use gas in operating the lease, it is generally held that the gas used for these purposes should be excluded in the calculation of the lessor’s royalty. Id. § 33:12, at 160. However, a lessee’s right to use gas in the operations of the leased premises is not without limits and is generally interpreted as being limited to the leased premises unless the clause expressly states otherwise. See 3 Williams & Meyers, supra, § 661.4, at 763 (providing “parties are free to authorize the *712provision of free gas without geographic limitation if their intent is expressed in the lease”).
{39} In Bice v. Petro-Hunt L.L.C., the North Dakota Supreme Court examined free use clauses similar to the free use clause contained in the 1931 and 1947 statutory lease forms. 2009 ND 124, ¶ 22, 768 N.W.2d 496, 502-03. One of the free use clauses provided that the lessees “shall have the right to use, free of cost, gas, oil and water produced on said land for its operation thereon.” Id. The court concluded that because the lessees were using the gas in furtherance of the lease operations, the free use clause did not limit the lessees’ free use of the gas to the leased premises. Id. ¶¶ 22, 27, 768 N.W.2d at 503-04.
{40} In this case, the free use clauses contained in the 1931 and 1947 lease forms granted Lessees “any and all rights and privileges necessary, incident to or convenient for the economical operation of said land, for oil and gas, with [the] right for such purposes to the free use of oil, gas casing-head gas, or water from said lands ....” (Emphasis added.) These rights were granted to Lessee “for the sole and only purpose of exploration, development and production of oil and gas thereon and therefrom with the right to own all oil and gas so produced and saved therefrom and not reserved as royalty by the lessor . . . .” This language granted Lessees the right to own all oil and gas so produced and saved from the leased premises that was not otherwise reserved as royalty by the lessor. Furthermore, it entitled Lessees to the free use of oil and gas produced from the leased premises, regardless of where the use occurred, so long as the oil and gas was being used to further the economical operations of said land. In reading the free use clause in conjunction with the net proceeds language, we conclude that Lessees are entitled to the free use of both plant and field fuel so long as it was used in the operation of the lease.
{41} Accordingly, we affirm the district court’s findings and hold field and plant fuel are post-production costs that Lessees remit to post-production service providers for the development and production of the leased premises; they are neither sold nor saved by Lessees and therefore are not subject to royalty payments.
3. Drip Condensate
{42} The district court found that the relevant provisions ofthe 1931 and 1947 lease forms require Lessees to pay royalties on their use of drip condensate to the extent that they derive profits from such use. Drip condensate is “the portion of a gas stream that becomes liquid during the transmission of the gas from [the leased premises] to a processing plant.” 8 Williams & Myers, supra, at 296.1. Within the oil and gas industry, condensate is also referred to as casinghead gas and liquid hydrocarbon. Ken Anderson, Oklahoma Historical Society’s Encyclopedia of Oklahoma History and Culture, http://digital.library.okstate.edu/encyclopedi a/entries/N/NA017.html (last visited July 11, 2012); see 8 Williams & Myers, supra, at 184.
{43} Commissioner asserts that the language of the lease forms provides him with the power to require payment of royalty for all or any part of the gas produced, and therefore provide him with the power to demand royalties on drip condensate. Commissioner, therefore, contends that the district court was correct in finding that the lease provisions require Lessees to pay royalties on drip condensate, but erred in finding that Lessees *713only had to pay royalties on drip condensate to the extent they derived profits from such use. Lessees assert that the lease provisions do not require royalties to be paid on drip condensate as drip condensate is provided to gathering companies as part of the compensation for the gathering services, and amounts to a post-production cost. Therefore, Lessees claim that because they do not receive any proceeds from the use of the drip condensate, they are not obligated to pay royalties on such use.
{44} An oil and gas lease is to be construed in the same manner as a contract. See Pub. Serv. Co. Of N. M. v. Diamond D Constr. Co., Inc.,2001-NMCA-0824 19, 131 N.M. 100, 33 P.3d 651. It is to be viewed as a harmonious whole so as to give meaning to every provision and accord each part of the lease its significance in light of other provisions. Id. A lease should not be interpreted in a manner in which one clause or provision annuls another. Id.
{45} The 1931 royalty obligations provide that “[sjubject to the free use without royalty, as hereinbefore provided, the lessee shall pay the lessor as royalty one-eighth part of the oil produced and saved from the leased premises . . .” and
lessee agrees to pay lessor the one-eighth of the net proceeds derived from the sale of gas from each gas well. If casing-head gas produced from said land is sold by the lessee, the lessee shall pay the lessor as royalty one-eighth of the net proceeds of said sale; if casing-head gas produced from said lands is utilized by lessee otherwise than for carrying on the lessee’s operations for producing oil or gas from said lands, then the lessee shall pay the lessor the market value in the field of the equal one-eighth part of the casing-head gas so utilized at the time of such utilization.
(Emphasis added.)
{46} The 1947 royalty obligations provide that “[sjubject to the free use without royalty, as hereinbefore provided, the lessee shall pay the lessor as royalty one-eighth of the oil produced and saved from the leased premises . . .” and “[sjubject to the free use without royalty, as hereinbefore provided, the lessee shall pay the lessor as royalty one-eighth of the cash value of gas, including casinghead gas, produced and saved from the leased premises and marketed or utilized . . . .”
{47} The royalty provisions contained in the 1931 and 1947 lease forms reserve for royalty all oil, gas, and casinghead gas that is not otherwise provided for under the free use clause. The free use clauses grant Lessees “any and all rights and privileges necessary, incident to or convenient for the economical operation of said land,” and allow for the free use of oil, gas, and casinghead gas for the “purpose of exploration, development, and production of oil and/or gas thereon and therefrom with the right to own all oil and gas so produced and saved therefrom and not reserved as royalty by lessor under the terms of this lease . . . .” Furthermore, the 1947 lease provides that “the cash value for royalty purposes of carbon dioxide gas and of hydrocarbon gas delivered to a gasoline plant for extraction of liquid hydrocarbons shall be equal to the net proceeds derived from the sale of such gas, including any liquid hydrocarbons recovered therefrom.” This clause indicates that payment of royalties on drip condensate, which is a liquid hydrocarbon, is to be based on net proceeds *714“derived from the sale of .. . liquid hydrocarbons recovered therefrom.”
{48} Lessees’ use of drip condensate amounts to a post-production cost that is remitted to post-production service providers. Construing the leases so as to give effect to every provision, we conclude that the royalty obligations contained in the 1931 and 1947 lease forms are limited by their respective free use clauses and do not require royalties to be paid on Lessees’ use of drip condensate to the extent that Lessees do not derive proceeds from such use. We affirm the district court’s finding that Lessees are only obligated to pay royalties on the use of drip condensate to the extent that they receive proceeds from such use.
Order 2: Summary Judgment on the Meaning of the Maximum Price Provision
{49} In the second certified order, the district court addressed the meaning of the “maximum price” provision. This issue pertains only to the construction of the 1947 lease form as there is no maximum price clause in the 1931 lease. The maximum price provision of the 1947 lease provides:
Notwithstanding the foregoing provisions, the lessor, acting by its commissioner of public lands, may require the payment of royalty for all or any part of the gas produced and saved under this lease and marketed or utilized at a price per m.c.f. equal to the maximum price being paid for gas of like kind and quality and under like conditions in the same field or area or may reduce the royalty value of any such gas (to any amount not less than the net proceeds of sale thereof in the field) if the commissioner of public lands shall determine such action to be necessary to the successful operation of the lands for oil or gas purposes or to encouragement of the greatest ultimate recovery of oil or gas or to the promotion of conservation of oil or gas.
{50} The district court found the maximum price provision to be “plain, clear and unambiguous” and entitled Commissioner to identify a “maximum price being paid for gas of like kind and quality and sold under like conditions in the same field or area, and to utilize that price as the starting point in calculating net proceeds.” Thus, the district court found that the maximum price clause does not require Lessees to pay a royalty based on the “highest gross price in the field or area, without netting (deducting) costs incurred by [Lessees] in selling the gas.”
{51} Commissioner asserts that the district court’s interpretation of the maximum price clause renders the clause meaningless. Commissioner claims that the clause grants the Commissioner of Public Lands the discretion to require payment of a royalty value equal to the maximum price being paid for natural gas in the same field or area. Commissioner asserts that because the clause provides him with the discretion to reduce the maximum price royalty payment to a net value, the maximum price clause must be based on a gross value, and not a net value. Commissioner, therefore, interprets the maximum price clause as providing him with the authority to prohibit Lessees from deducting field-related expenses when calculating their royalty payments.
{52} Lessees assert that Commissioner’s interpretation of the maximum price clause of *715the 1947 lease attempts to convert the “net proceeds” royalty obligation to a “gross proceeds” royalty obligation. Lessees further argue that Commissioner’s interpretation confuses the concept of “payment of royalty” and “price,” and assert that the maximum price provision allows for Commissioner to require the royalty payments to be calculated based on the “maximum price being paid for gas of like kind and quality and under like conditions in the same field or area” if he determines such action is necessary to the successful operations of the lands.
{53} In oil and gas leases the price, or market price, is considered to be the price that would be paid by a willing buyer to a willing seller in a free market. 3 Eugene Kuntz, A Treatise on the Law of Oil and Gas § 40.4(d), at 329 (1989). Market price is determined by looking to comparable sales, which “are those [sales] that are comparable in time, quality, quantity, and availability of marketing outlets.” Id. at 335. The language of the 1947 maximum price clause allows Commissioner to, in his discretion, require Lessees to calculate theirroyalty obligations based on the maximum market price being paid for similar gas in the same field or area. The clause also provides Commissioner with the discretion to reduce the royalty payments to an amount not less than the royalty value of the net proceeds in the field. This clause, therefore, does not affect Lessees’ ability to deduct post-production costs. Instead it provides Commissioner with the authority to require that Lessees deduct their post-production expenses from the maximum price being paid for gas of like kind and quality in the same field or area.
{54} Accordingly, we affirm the district court and hold that the maximum price clause of the 1947 statutory lease form grants Commissioner the authority to require royalty payments based on the maximum market price in the field or area if “such action [is] necessary to the successful operation^] of the lands for oil or gas purposes.”
Order 3: Denying Commissioner’s Motion for Reconsideration of Dismissal of Commissioner’s Breach of the Implied Covenant to Market Claim
{55} Commissioner filed a counterclaim against Lessees for breach of the implied covenant to market. In that counterclaim, he alleged that the implied covenant to market requires Lessees to place the gas in a marketable condition and requires that the expenses incurred in obtaining a marketable product, such as gathering, dehydrating, and treating, be born by Lessees.
{56} Lessees moved for judgment on the pleadings on Commissioner’s breach of the implied covenant to market claim. The district court granted Lessees’ motion, and dismissed the claim. Subsequently, Commissioner moved for reconsideration in light of this Court’s opinion in Davis v. Devon Energy Corp., 2009-NMSC-048, 147 N.M. 157, 218 P.3d 75. In Davis we considered whether certification of a class action was appropriate where a group of royalty owners claimed that the defendant gas producers breached an implied covenant to market; however, Davis expressly avoided establishing the existence or scope of a marketable condition rule under New Mexico law. Id. ¶¶ 3, 14-15.
{57} The district court denied Commissioner’s motion for reconsideration of its previous dismissal of Commissioner’s implied covenant to market claim. The district court reasoned that to imply a covenant which forces Lessees to bear the costs of placing the *716gas in a marketable condition would require the district court to alter the express terms of the lease, and it ruled it had no power to so alter the lease. Accordingly, the district court found that because the statutory royalty obligation is based on “net proceeds,” Lessees are permitted to net the costs associated with placing the gas in a marketable condition.
{58} Ordinarily “[w]e review judgments on the pleadings made pursuant to Rule 1-012(C) NMRA according to the same standard as motions for failure to state a claim under Rule 1-012(B)(6) NMRA.” Vill. of Angel Fire v. Bd. of Cnty. Comm’rs of Colfax Cnty., 2010-NMCA-038, ¶ 5, 148 N.M. 804, 242 P.3d 371. However, “[i]f, on amotion for judgment on the pleadings, matters outside the pleadings are presented to and not excluded by the court, the motion shall be treated as one for summary judgment.” Rule 1-012(C). Therefore, because the district court conducted a full review of the record, Lessees’ motion for judgment on the pleadings will be treated as a motion for summary judgment and reviewed accordingly.
{59} On appeal, Commissioner claims that “under New Mexico law, the [sjtate leases inherently include a duty to market gas.” Therefore, he maintains that because Lessees have an implied duty to place the gas in a marketable condition Lessees are prohibited from deducting post-production costs when calculating their royalty obligations. Although Commissioner’s counterclaim is couched in terms of a breach of the implied covenant to market, the substance of the counterclaim relies upon an offshoot to the implied covenant to market, termed the “marketable condition rule.” See Davis, 2009-NMSC-048, ¶ 6 (internal quotation marks and citation omitted).
{60} Lessees assertthatthe district court’s dismissal of Commissioner’s claim was correct because New Mexico law does not recognize “any variant of. . . the marketable condition rule.” Lessees further contend that because the statutory lease provisions expressly and unambiguously allow for the deduction of post-production costs, it is improper for courts to imply duties.
{61} In Davis, we recognized that “whether a covenant may be implied in a given contract, [depends upon] the legal theory supporting the implication of that promise.” Id. ¶ 32. The legal theory supporting the implication of a promise determines the court’s analysis and whether a covenant is to be implied in fact or at law. Id.; see 5 Williams & Meyers, supra, § 803, at 18.2 (discussing implied covenants as being divided into two categories, implied covenants in fact and implied covenants at law).
{62} An implied covenant in fact springs from the language of the parties’ agreement. Davis, 2009-NMSC-048, ¶ 32. Thus, by implying a covenant in fact, a court is “effectuating the parties’ intentions by interpreting the written terms of an agreement and analyzing the parties’ conduct.” Id. An implied covenant at law, however, has its origins not in the parties’ agreement, but ratherinlaw. Id. ¶¶ 32-3 3. Thus, by implying a covenant at law, a court is “stating that a duty imposed by law creates an obligation on one or more of the parties to the agreement.” Id. ¶ 32.
{63} In Davis, we noted that an implied covenant in fact “requires an analysis of the parties’ intentions,” as expressed in the agreement, while an implied covenant at law “is merely a judicial determination of the duties the law imposes on the parties” and *717does not require analysis of the agreement. Id. ¶¶ 32-33. In so doing, we held that the implied covenant to market is an implied covenant at law and does not require an analysis of the parties’ agreement. Id. ¶ 35. This holding was consistent with our previous cases, namely Darr v. Eldridge, 66 N.M. 260, 346 P.2d 1041 (1959) and Libby v. De Baca, 51 N.M. 95, 179 P.2d 263 (1947), where we implied the covenant to market “in equity, without looking to the language of the agreements or other evidence of the parties’ intentions.” Davis, 2009-NMSC-048, ¶ 35. Davis, therefore, makes clear that the implied covenant to market “applies in equity irrespective of the parties’ intentions.” Id.
{64} However, in Davis we declined to address whether the marketable condition rule is inherent in the implied covenant to market, Davis, 2009-NMSC-048^35, and whether, if recognized in New Mexico, the marketable condition rule would be implied in fact or at law. We do not need to reach the issue in this case. When the Legislature adopted the statutory oil and gas leases that we have referenced in this opinion, the Legislature expressed the policy decision that lessees under such leases are entitled to recover some post-production costs associated with making the gas marketable. How much and what kinds of post-production costs remain at issue in this case. However, because of this legislative policy decision we do not need to decide whether the marketable condition rule is inherent in the implied covenant to market. As we indicated in Davis, whether the marketable condition rule applies in New Mexico is not yet ripe for review. 2009-NMSC-048, ¶ 15. This opinion should not be interpreted as affecting private oil and gas lease agreements. Accordingly, we affirm the district court’s dismissal of Commissioner’s counterclaim for the breach of the implied covenant to market.
Order 4: Allowing the Deduction of the Cost of Post-Production Services Provided by Lessees’ Affiliates to the Extent it Is Reasonable
{65} The parties submitted corresponding motions for summary judgment to the district court regarding the amount Lessees are entitled to deduct for post-production services when such services are provided by one of Lessees’ affiliate entities. The district court found that Lessees’ deductions for post-production services must be reasonable.
{66} Commissioner argues that the district court erred in finding that Lessees’ deductions must only be reasonable and asserts that deductions for post-production services performed by Lessees’ affiliated entities must be both actual and reasonable. Lessees counter that the Legislature intended for the post-production costs incurred from transactions with affiliated and non-affiliated third-party processors to be treated the same.
{67} Neither the 1931 nor the 1947 statutory lease forms contain an express clause governing affiliate transactions. When a contract is clear as written, a court “must give effect to the contract and enforce it as written.” Ponder v. State Farm Mut. Auto. Ins. Co., 2000-NMSC-033, ¶ 11, 129 N.M. 698, 12 P.3d 960. Courts “cannot create a new agreement for the parties,” Montoya v. Villa Linda Mall, Ltd., 110 N.M. 128, 129, 793 P.2d 258, 259 (1990), and “will not give effect to a party’s undisclosed intentions,” Ponder, 2000-NMSC-033, ¶ 14. When a contract is silent regarding the subject matter at issue, “[ejvidence of custom and usage may be used to ascertain the intention in reference to matters about which the contract is silent.” *71821A Am. Jur. 2d Customs and Usages, § 25 (2012). Moreover, when “a contract is silent on an issue, the law implies a reasonable term to cover that issue.” Melvin Aron Eisenberg, Probability and Chance in Contract Law, 45 UCLA L. Rev. 1005, 1027 (1998); see, e.g., Castle v. McKnight, 116 N.M. 595, 598, 866 P.2d 323, 326 (1993) (providing that when a contract is silent as to the time of performance a reasonable time will be implied).
{68} The district court found thatbased on the statutory and regulatory history, the New Mexico Legislature and the Commissioner of Public Lands intended both affiliated and non-affiliated transactions to be treated the same. Therefore, Lessees were permitted to deduct reasonable costs incurred for post-production services. We agree with the district court’s finding that there was no support for Commissioner’s contention that deductions for affiliated transactions must be limited to actual costs. Accordingly, because there is nothing in the 1931 or 1947 statutory lease forms to indicate that the Legislature intended to treat affiliated and non-affiliated transactions differently when deducting post-production costs, we affirm the district court’s finding that deductions used in calculating Lessees’ royalty obligations must be reasonable.
CONCLUSION
{69} For the foregoing reasons, we affirm the district court’s orders.
{70} IT IS SO ORDERED.
PETRA JIMENEZ MAES, Chief Justice
WE CONCUR:
PATRICIO M. SERNA, Justice
RICHARD C. BOSSON, Justice
EDWARD L. CHÁVEZ, Justice
CHARLES W. DANIELS, Justice