delivered the Opinion of the Court.
The following question of law was certified to this court by the United States District Court for the District of Colorado in accordance with C.A.R. 21.1:
Under Colorado law, is the owner of an overriding royalty interest in gas production required to bear a proportionate share of post-production costs, such as processing, transportation, and compression, when the assignment creating the overriding royalty interest is silent as to how post-production costs are to be borne?
The district court provided three examples of post-production costs but left the term “post-production costs” undefined. We recognize that each of the activities posited in the certified question occurs throughout the gas production process. Gas may require processing to remove impurities for market*654ing, and once marketable may be further processed into additional component products. Transportation is required when gas is moved from the wellhead to a central location to prepare it for transmission and consumption, commonly referred to as gathering. See John C. Jacobs, Problems Incident to the Marketing of Gas, 5 Inst, on Oil & Gas L. & Tax’n 271, 273 (1954). If no market for the gas exists near the wellhead, transportation may be required to move the gas to a distant market.1 Compression may be required to create sufficient pressure for the gas to enter a purchaser’s pipeline,2 or compression may occur to transform the gas into additional products.3 The parties understand the nature of the gas production, and agree that there exists a point in the production process when an overriding royalty owner may become obligated to bear a proportionate share of costs. They do not agree when proportionate allocation should occur. Because we cannot anticipate every conceivable type of post-production cost, and whether it occurs before or after a marketable product is obtained, we consider the certified question as if it were posed without the examples.
In addition, our consideration of the certified question is based on our understanding that “the assignment creating the overriding royalty interest” is indeed silent with respect to the allocation of post-production costs. The district court posed the certified question in. general terms, and we answer to provide guidance when an assignment does not address the allocation of post-production costs. Had the district court wanted this court to consider the assignment from the Garmans to Lee A. Adams, who eventually assigned the leases to Conoco, we believe the question would have been framed to elicit a more specific response. However, the briefs submitted by the parties and amici curiae focused on the general principles of oil and gas law relating to the allocation of post-production costs. Other than a limited request by the Garmans to consider the language of the assignment in this case, they also assumed that the “response to the question should be a statement of the general principles of Colorado law applicable to the issue.” While the Garmans asked us to “address the application of the legal principles announced to the undisputed facts of this case” we decline to do so.4 We believe we can respond appropriately to the district court on the law in Colorado without considering the specific assignment terms.
With this background in mind, limiting our response to those post-production costs undertaken to convert raw gas into a marketable product, and relying on the basic proposition that every oil and gas lease contains an implied covenant to market, we answer the certified question in the negative. We now turn to the facts which provide a foundation for the certified question and our answer.
I
During the years 1951 through 1953, M.B. and B.K. Garman acquired eight federal oil *655and gas leases covering approximately 10,742 acres situated in Rio Blanco County, Colorado (the Leases). Through a series of assignments the Leases were transferred to Cono-co, Inc. (Conoco) subject to a reserved 4.00% overriding royalty interest now owned in equal shares by James P. Garman, Robert D. Garman and Mark Bruce Garman (collectively Garmans).5
The Leases are located in Dragon Trail Unit (Unit) and continue in full force and effect by the production of gas. Conoco operates both the Unit and the Dragon Trail Processing Plant (Plant).6 The Plant is located outside of both the Lease and the Unit boundaries. From the wellhead, gas enters a gathering line for transportation to the Plant. At the Plant, gas from the Unit is processed into three separate products: (1) residue gas; (2) propane; and (3) a combined stream of butane and natural gasoline (the “butane-gasoline stream”). The gross proceeds from the sale of the individual products are greater than the revenues which would have been obtained from the sale of the raw, unprocessed gas at the wellhead. Plant operations are typical of processing operations performed to enhance the value of gas. The parties have not stipulated as to the reasonableness of the processing costs.
Historically, Conoco has deducted the cost of certain post-production operations from the overriding royalty payments due to the Garmans.7 From January, 1987 until April, 1993, the Garmans’ proportionate share of post-production costs was $459,511 on overriding royalty payments totaling approximately $2.2 million. In 1993, the Garmans filed an action in federal court requesting declaratory relief to determine the parties’ rights under the original 1956 assignment creating the overriding royalty interest, and an accounting to determine whether post-production charges for the previous six years were properly assessed against their overriding royalty interest.
The Garmans argue post-production costs incurred to convert raw gas into a marketable product should not be charged against nonworking interest owners. Accordingly, they object to Conoco’s deduction, of the costs necessary to make gas from the Leases marketable. The Garmans concede that costs incurred after the gas is made marketable, which actually enhance the value of the gas, should be borne proportionately by all parties benefitted by the operations.8 *656They argue, however, that no evidence exists to show Conoco’s operations increase the actual royalty amount paid to the Garmans. Finally, they argue under the doctrine of expressio unius est exclusio alterius that the assignment creating their overriding royalty prohibits Conoco from assessing post-production costs against their royalty.9
Conoco argues that all post-production costs incurred after gas is severed from the ground and reduced to possession should be borne proportionately by royalty, overriding royalty and working interest owners. Cono-co asserts severance occurs at the wellhead and that all expenses incurred after severance improve or enhance the value of the gas from its natural, unprocessed state. Thus, it claims that royalty and overriding royalty interest owners who benefit from these operations ought to share in the cost of all post-production operations.
II
A
“The fundamental purpose of an oil and gas lease is to provide for the exploration, development, production and operation of the property for the mutual benefit of the lessor and lessee.” Davis v. Cramer, 808 P.2d 358, 360 (Colo.1991). The lessor relinquishes its right to the mineral estate in exchange for a smaller non-risk and non-cost bearing royalty interest10 in any minerals discovered. See Wood v. TXO Production Co., 854 P.2d 880, 882-83 (Okla.1992) (“The lessor, who generally owns the minerals, grants an oil and gas lease, retaining a smaller interest, in exchange for the risk-bearing working interest receiving the larger share of the proceeds.”). Similar to a royalty, an overriding royalty is an interest in oil and gas produced at the surface, free of expense of production, generally assessed in addition to the usual mineral owner’s royalty. See, e.g., 8 Williams & Meyers at 859; see also Hagood v. Heckers, 182 Colo. 337, 347, 513 P.2d 208, 214 (1973). While the lease agreement creates the royalty obligation, overriding royalty interests are typically reserved or created by separate agreement.11 See 2 Williams & Meyers § 418. Though their contractual origins may differ, both royalty and overriding royalty interests are non-risk and non-cost bearing interests. See id. § 418.1 (“An overriding royalty is, first and foremost, a royalty interest.... it is an interest in oil and gas produced at the surface, *657free of the expense of production.”). Naturally, the contracting parties are free to allocate the costs of compression, transportation and processing in their agreements. E.g., Magnetic Copy Serv. v. Seismic Specialist, Inc., 805 P.2d 1161, 1163 (Colo.App.1990). Often, however, these agreements fail to apportion expenses that may be incurred after the discovery of oil or gas.12
Though a lease is entered into for the mutual benefit of the parties, not all parties participate equally in lease development decisions. Royalty and overriding royalty interest owners (nonworking interest owners) defer to the risk-bearing parties (working interest owners) to decide where and when to drill, the formations to be tested and ultimately whether to complete a well and establish production.13 Here, Conoco objects to the Garmans’ desire to get a “free-ride” on certain costs incurred after the gas is brought to the surface. We believe, however, that the relationship between the parties specifically provides for a “free-ride” on costs incurred to establish marketable production..
B
No consensus exists regarding the allocation of expenses incurred after the discovery of gas. See 3 Kuntz § 40.5.14 Two lines of cases have developed in the oil producing states based upon differing views of when production is established and a royalty interest accrues. Texas and Louisiana have adopted the rule that nonoperating interests must bear their proportionate share of costs incurred after gas is severed at the wellhead. See, e.g., Dancinger Oil & Refineries v. Hamill Drilling Co., 171 S.W.2d 321 (Tex.1943); Martin v. Glass, 571 F.Supp. 1406, 1415 *658(N.D.Tex.1983) (“Under the law of Texas, gas is ‘produced’ when it is severed from the land at the wellhead.”), aff'd 736 F.2d 1524 (5th Cir.1984); see also Merritt v. Southwestern Elec. Power Co., 499 So.2d 210 (La.Ct.App.1986) (under Louisiana’s reconstruction approach royalty payments are calculated by deducting costs incurred after gas reaches the wellhead). Conoco argues this interpretation best reflects the obligations of the parties.
In Kansas and Oklahoma a contrary rule has developed based on an operator’s implied duty to market gas produced under an oil and gas lease. Wood v. TXO Production Corp., 854 P.2d 880, 882 (Okla.1992) (“[T]he implied duty to market means a duty to get the product to the place of sale in marketable form.”); Gilmore v. Superior Oil Company, 192 Kan. 388, 388 P.2d 602, 606 (1964) (“Kansas has always recognized the duty of the lessee under an oil and gas lease not only to flnd if there is oil and gas but to use reasonable diligence in finding a market for the product.”).15 Wyoming has codified the marketability approach.16 The Federal government also requires that a lessee “place gas in marketable condition at no cost to the Federal Government....” 30 C.F.R. § 206.153© (1993).17
Arkansas and North Dakota have reached similar conclusions when considering lease royalty clauses which are silent as to allocation of post-production costs. A lease which provides for the lessor to receive “proceeds at the well for all gas” means gross proceeds when the lease is silent as to how post-production costs must be borne. Hanna Oil & Gas Co. v. Taylor, 297 Ark. 80, 759 S.W.2d 563, 565 (1988); see also West v. Alpar Resources, Inc., 298 N.W.2d 484, 491 (N.D.1980) (when the lease does not state otherwise lessors are entitled to royalty payments based on percentage of total proceeds received by the lessee, without deduction for costs).
The Garmans and Amici Curiae18 advance three separate theories to support their claim *659that post-production costs are the sole responsibility of the lessee. The Garmans rely on the implied covenant to market which they assert imposes all costs associated with producing a marketable product on the lessee. The National Association of Royalty Owners urges us to consider the typical oil and gas lease habendum clause19 which generally requires production of oil or gas in paying quantities in order to extend the lessee’s interest. Finally, a group of southwestern Colorado landowners argue production activities do not cease until the operator obtains a marketable product that can be delivered to a pipeline.20 While the parties have approached the question from slightly different angles, the common thread connecting these theories is the existence of an obligation upon the lessee, as the party charged with lease development, to complete all operations necessary to market the gas produced from the leasehold. This obligation is captured in what we have previously identified as the implied covenant to market.21
In Colorado we have recognized four implied covenants in oil and gas leases: to drill; to develop after discovery of oil and gas in paying quantities; to operate diligently and prudently; and to protect leased premises against drainage. Davis v. Cramer, 808 P.2d 358 (Colo.1991); Mountain States Oil v. Sandoval, 109 Colo. 401, 125 P.2d 964 (1942); see also Gillette v. Pepper Tank Co., 694 P.2d 369 (Colo.App.1984). “Embodied in the duty to operate diligently and prudently is the implied covenant to market.” Davis, 808 P.2d at 358. In Davis we explained the covenant obligates the lessee to engage in marketing efforts which “would be reasonably expected of all operators of ordinary prudence, having regard to the interests of both lessor and lessee.” Id. at 363 (quoting Gillette, 694 P.2d at 372).
Conoco argues that the implied covenant to market exists separately from the allocation of marketing costs. We disagree. Implied lease covenants related to operations typically impose a duty on the oil and gas lessee. See, e.g., 5 Kuntz §§ 57.1 to 62.5.22 Accordingly, the lessee bears the costs of ensuring compliance with these promises. Cf. Warfield Natural Gas Co. v. Allen, 261 Ky. 840, 88 S.W.2d 989, 991 (1935) (the lessee has the exclusive right to produce gas and find a market, and pays the expenses of doing both as consideration for its seven-eighths of production). The purpose of an oil and gas lease could hardly be effected if the implied covenant to drill obligated the lessor to pay for his proportionate share of drilling costs. In our view the implied covenant to market obligates the lessee to incur those post-production costs necessary to place gas in a condition acceptable for market. Overriding royalty interest owners are not obligated to share in these costs.23
*660Allocating these costs to the lessee is also traceable to the basic difference between cost bearing interests and royalty and overriding-royalty interest owners. Normally, paying parties have the right to discuss proposed procedures and expenditures and ultimately have the right to disagree with the course of conduct selected by the operator. Under the terms of a standard operating agreement nonoperating working interest owners have the right to go “non-consent” on an operation and be subject to an agreed upon penalty. See A.A.P.L. Form 610-1989 Model Form Operating Agreement Art. Vl.b.ii. This right checks an operator’s unbridled ability to incur costs without full consideration of their economic effect. No such right exists for nonworking interest owners.
We find Conoco’s argument that industry practice allows proportionate allocation of post-production costs unpersuasive. Before one can be bound by industry custom “he must know of it or it must be so universal and well-established that he is presumed to have knowledge of its existence.” Pittman v. Larson Distrib. Co., 724 P.2d 1379, 1384-85 (Colo.App.1986). Further, the parties must have contracted with reference to the custom. Id. Custom and industry practice may be an appropriate consideration when Conoco deals with other oil exploration companies. Cf. Pletchas v. Von Poppenheim, 148 Colo. 127, 130, 365 P.2d 261, 263 (Colo.1961) (Parties engaged in same occupation are presumed to have knowledge of business usage). Often, however, executing an oil and gas lease, or assigning a federal lease won under the previously existing federal lottery system is the extent of a party’s contact with the oil industry. See Piney Woods County Life Sch. v. Shell Oil Co., 726 F.2d 225, 240 (5th Cir.1984) (“[Shell’s] allegation of ‘custom’ is self-serving. The payment of royalties is controlled by lessees, and lessors have no ready means of ascertaining current market value other than to take lessees’ word for it.”), aff'd in part on remand, 905 F.2d 840 (5th Cir.1990). Conoco cannot invoke industry custom to limit the rights of royalty and overriding royalty owners unsophisticated in the intricacies of mineral development.24 While we acknowledge that parties who reserve or create overriding royalty interests may be familiar with the oil and gas industry, no cogent argument exists to treat these nonworking interest owners differently from other royalty owners.25
We do not here impose an additional duty on the lessee or expand the duty previously recognized; the duty to market, always undertaken in good faith, may be limited when compliance would be uneconomical or unreasonable. Davis, 808 P.2d at 362; Davis v. Cramer, 837 P.2d 218, 222 (Colo.App.1992). The marketing obligation does not depend on whether production would be more economic if nonworking interest owners were obligated to share in these post-production costs.
C
Our answer is limited to those post-production costs required to transform raw gas into a marketable product.26 As we explained at the outset, many different types *661of expenses may be involved in the conversion process. Upon obtaining a marketable product, any additional costs incurred to enhance the value of the marketable gas, such as those costs conceded by the Garmans, may be charged against nonworking interest owners.27 To the extent that certain processing costs enhance the value of an already marketable product the burden should be placed upon the lessee to show such costs are reasonable, and that actual royalty revenues increase in proportion with the costs assessed against the nonworking interest.28 We are not, however, called upon today to consider the reasonableness of Conoco’s expenses incurred to process, transport or compress already marketable gas.
For the above reasons our answer to the certified question is that, absent an assignment provision to the contrary, overriding royalty interest owners are not obligated to bear any share of post-production expenses, such as compressing, transporting and processing, undertaken to transform raw gas produced at the surface into a marketable product.
ERICKSON, J., specially concurs. VOLLACK, J., joins in the special concurrence.. Traditionally, the costs to transport gas to a distant market are shared by all benefitted parties. See Johnson v. Jernigan, 475 P.2d 396 (Okla.1970) (allocates long-distance transportation costs proportionately after the lessee has made the gas available for market); cf. Molter v. Lewis, 156 Kan. 544, 134 P.2d 404, 406 (1943) (explaining the lessee has a general duty to see that oil is marketed, but this does not mean that the lessee must pay the lessor's share of transportation charges from the well to some distant place).
. See J. Clayton La Grone, Calculating the Landowner's Royalty, 28 Rocky Mtn.Min.L.Inst. 803, 809 (1983) ("When the reservoir pressure is not sufficient to force natural gas produced from a well into a pipeline which is itself under pressure, it is necessary to increase the pressure of the gas after it comes to the surface in order for it to be marketable.”).
. In their brief, the Garmans contend compression, dehydration, and refrigeration are necessary in order to meet pipeline specifications. Whether these expenses are required to create a marketable product is a question of fact for the trial court. The Garmans’ argument illustrates the type of costs currently disputed, in addition to those examples provided by.the district court.
. Pursuant to C.A.R. 21.1 we "may answer a question of law certified [to this court if there are] ... questions of law of this State which may be determinative of the cause then pending before the certifying court.” We believe the Gar-mans’ request that we apply the law to the facts now before the federal district court exceeds the scope of the certified question.
. M.B. and B.K. Garman conveyed the Leases to Monarch Oil & Uranium Co. which in turn assigned them to Lee A. Adams, reserving a 4.00% overriding royalty interest. Adams entered into a series of option contracts with Conoco under which Conoco ultimately acquired its current working interest. The overriding royalty interest was eventually assigned into a royalty trust and the trust conveyed the interest to the current owners James P. Garman, Robert D. Garman and Mark Bruce Garman in equal shares of one and one-third percent on August 18, 1992.
. Conoco purchased the plant from Sun Oil Company and took over as operator in November, 1987.
. When production was first established M.B. Garman executed a Division Order which provided that "proceeds shall be calculated both as to price and quantity on the basis of and in the manner provided for” in a contract between Continental Oil Co. and Western Slope Gas Co. The terms of this contract are not part of the record. In 1982, Monarch and the Douglas Creek Royalty Trust, successors to M.B. Garman, executed an Oil and Gas Transfer Order prepared by Conoco which provided that:
settlement for gas sold shall be based on the net proceeds realized at the well by you [Cono-co] after deducting any costs incurred in compressing, treating, transporting and/or dehydrating the gas for delivery. If the gas is processed in or near the field where produced, settlement shall be based on the net proceeds realized at the well, as determined by the agreement between the producer and processor, or, in the absence of such an agreement, the same basis as settlement with other producers of gas of like kind and quality processed at the same plant, (emphasis supplied). In 1992, Conoco provided the Garmans, as
successors to Monarch and Douglas Creek Royalty Trust, with a Confirmation of Interest form which contained language substantially similar to the 1982 Transfer Order. Before signing the Confirmation of Interest form the Garmans deleted the language allowing deduction of compressing, treating, transporting and/or dehydrating the gas for delivery. We do not express any opinion on the validity or effect of the division orders executed by the Garmans’ predecessors.
.The Garmans conceded in their brief and at oral argument that the transportation costs associated with moving marketable gas from the tailgate of the processing plant where the gas enters the interstate pipeline to the point of sale are properly deductible. They also agreed that the *656costs incurred to process raw gas into its component parts after a marketable product has been obtained are generally deductible to the extent they are reasonable, provided such operations actually enhance the value of the product. Here, the Garmans assert the gathering costs to move the gas from the wellhead to the Plant, the compression costs once the gas has arrived at the Plant, and the dehydration costs incurred to meet the pipeline standards are all required to make gas from the Leases marketable.
. Because the District Court did not ask us to interpret the assignment from the Garmans’ predecessors to Lee A. Adams in which the overriding royalty interest was created we do not address this argument. We also leave to the trial court any dispute regarding the reasonableness of the charges assessed by Conoco for any processes the court finds to be the joint responsibility of both parties.
. The right to royalty payments is characterized as an attribute of the mineral estate. Richard W. Hemingway, Law of Oil and Gas § 2.5 (3d ed. 1991). The landowner's reserved royalty interest is "the right to a fractional portion of the minerals as compensation, where the land is developed by one other than the owner of the mineral estate.” Id.; see also 8 Howard R. Williams & Charles J. Meyers, Oil and Gas Law 1087 (1993) (hereinafter Williams & Meyers).
.This question affects an overriding royalty created by assignment of a federal oil and gas lease. While the federal government provides specific instructions regarding the calculation of gas royalties due under federal oil and gas leases, see, e.g., 30 U.S.C. § 226 (1986 & Supp.1994); 30 C.F.R. § 206.152 to .250 (1993); see also Mesa Operating Ltd. Partnership v. Department of Interior, 931 F.2d 318 (5th Cir.1991), cert. denied - U.S. -, 112 S.Ct. 934, 117 L.Ed.2d 106 (1992), it does not dictate the calculation of payments due for overriding royalty interests that burden federal leases. This court has held that state law generally governs private parties’ dealings which affect federal oil and gas leases. Hagood, 182 Colo. at 342, 513 P.2d at 214 (explaining an overriding royalty can be "characterized as an interest in real estate” and finding no exception to this rule exists when the overriding royalty is created under an oil and gas lease granted pursuant to the Federal Mineral Leasing Act). We therefore decide the rights and obligations of an overriding royalty interest owner with reference to state law.
. While specific lease language is often determinative of cost allocation, see Martin v. Glass, 571 F.Supp. 1406, 1411 (N.D.Tex.1983) ("'net proceeds' clearly suggests that certain costs are deductible ... defined as the sum remaining from gross proceeds of sale after payment of expenses;”), royalty clauses and overriding royalty reservations are often silent regarding allocation of these costs. Gas royalty clauses which provide for the payment of a royalty in money (rather than "in kind”) typically require either payment of proceeds from the sale of the gas, or payment of the market value of the gas where it is produced. See 3 Eugene Kuntz, A Treatise on the Law of Oil and Gas, § 40.4 (1989 & 1994 Supp.) (hereinafter Kuntz); 3 Williams & Meyers § 643.2. This distinction does not answer the certified question, as Kuntz explains:
Except in the case of a fixed gas royalty, the difficulty with respect to the additional costs of preparing the gas for market arises regardless of the type of royalty clause involved. If the royalty clause is the common type which provides for a payment of money to the lessor as a royalty on gas produced the question arises in determining the value of the gas. If the royalty clause is of the uncommon type which provides for the delivery of royalty gas in kind, then the question arises in determining what is required of the lessee in preparing the gas for delivery. 3 Kuntz § 40.5.
. Operators must comply with the rules and regulations of the Oil and Gas Conservation Commission. See § 34-60-101 to -126, 14 C.R.S. (1984 & 1994 Supp.). While these regulations impose certain limits on an operator's discretion, the Conservation Act does not modify the relationship between working and nonworking interest owners.
.Until relatively recently gas was often an unwanted by-product of oil production and was vented or flared without compensation to royalty or overriding royalty interest owners. See 3 Kuntz §§ 40.1 — .4. After limited markets developed for gas, royalties on production were often calculated at a fixed rate for each producing gas well. Id. § 40.2. Kuntz explained the development of gas marketing:
As the natural gas industry developed and natural gas pipelines were extended over the country creating and expanding the market for gas, the value of gas increased. It also became apparent that the ultimate value of gas and the value of the right to extract and sell gas could not be foreseen or determined at any given time of leasing. Accordingly, instead of merely increasing the amount of the fixed periodic payment to be made as the gas royalty, the parties to oil and gas leases changed their practices and began to provide for a royalty on gas which is measured either by volume or by the value of the gas produced.
This evolution foreshadowed the type of dispute regarding calculation of gas royalties typified by the current case prompting the certified question now before this court. Even the commentators disagree regarding allocation of these costs. Compare 3 Williams & Meyers § 645.2 ("A royalty or other nonoperating interest in production is usually subject to a proportionate share of the costs incurred subsequent to production where, as is usually the case, the royalty or nonoperating interest is payable 'at the well’ ”) with 3 Kuntz § 40.5 ("It is submitted that .the acts which constitute production have not ceased until a marketable product has been obtained.”).
. Conoco cites Matzen v. Hugoton Production Co., 182 Kan. 456, 321 P.2d 576 (Kan.1958), also decided by the Kansas Supreme Court, to sup- ' port the proposition that marketing costs should be borne by all parties benefitted by marketing efforts. In Gilmore the court distinguished Mat-zen explaining the cost allocation was based on the lessors’ stipulation that the royalty was to be determined at the wellhead. Gilmore, 388 P.2d at 605 ("that [Matzen] case is not applicable here for the very cogent reason the parties there had stipulated in court that the lessee could and had properly deducted costs of a large gathering system to transport the gas from the leased property to a far distant pipeline.").
.Wyo.Stat. § 30-5-304(a)(vi) (1994 Supp.) provides in pertinent part:
"Costs of production: means all costs incurred for exploration, [and] development! ] ... operations including, but not limited to ... gathering, compressing, ... dehydrating, separating .. or transporting ... the gas into the market pipeline. "Costs of production” does not include the reasonable and actual direct costs associated with transporting ... the gas from the point of entry into the market pipeline or the processing of gas in a processing plant.”
Nev.Rev.Stat.Ann. § 522.115 1(b) (Michie 1993 Supp.) provides that the "lessor’s interest, the mineral owner's royalty interest and the overriding royalty interest must not be decreased by the costs of production.” Costs of production are defined in 522.115 3 as:
all costs incurred for the exploration and development of, primary or enhanced recovery of oil or gas from, and operations associated with the abandonment of, an oil or gas well, including costs associated with the:
(a) Acquisition of an oil and gas lease;
(b) Drilling and completion of a well;
(c) Pumping or lifting, recycling, gathering, compressing, pressurizing, heater treating dehydrating, separating and storing of oil or gas; and
(d) Transporting of oil to storage tanks, or gas into the pipeline for delivery.
The term does not include the reasonable and actual direct costs associated with transporting oil from storage tanks to the market, gas from the point of entry into the pipeline to the market or the processing of gas in a processing plant.
. The Garmans argue that the federal government’s marketability rule should apply to their overriding royalty interest because the Leases were issued by the federal government. We do not endorse this position but rather cite the federal government’s practice to illustrate the marketability approach.
. Amicus curiae briefs in support of petitioners were submitted by the National Association of Royalty Owners and Richard Parry, Linda Parry, Petrogulf Corporation, Douglas Cameron McCleod, Evelyn L. Payne, David G. Groblebe, Elizabeth A. Groblebe, RDG, Inc., and Harry E. Fassett, Lavaun Wilde, Jack W. Fassett, as Trustees of the Fassett Family Trust (Parry Brief).
. The habendum clause in a deed or lease sets forth the duration of the grantee’s or lessee’s interest in the premises. 8 Williams & Meyers at 554.
. Thus, they argue the certified question improperly labels these costs as post-production when in effect all of the costs must be incurred before production is established. See also 3 Kuntz § 40.5 explaining when "marketing is regarded as an indispensable element of production, the marketing of gas is a special limitation and a failure to market gas after the primary term will result in an automatic termination of the lease.”
. In Colorado we have characterized the duty to market as a covenant contained in every oil and gas lease. See Davis v. Cramer, 808 P.2d 358, 361 (Colo.1991). Generally, a covenant "operates as a condition, with the result that the court may cancel the lease for a failure on the part of the lessee to comply with such covenant or condition.” 3 Kuntz § 40.5.
. Compare the duties of operation typically imposed on the lessee with lessor’s duties which relate to delivery of title and noninterference with the lessee’s operations. 3 Kuntz §§ 56.1— .3.
. Some question exists whether the implied covenants under an oil and gas lease extend to overriding royalty owners. See 2 Williams & Meyers § 420. However, the rationale for application of the covenants to protect the lessor similarly extends to the interest of an overriding royalty owner. Id. at § 420.1. See also Bolton v. Coats, 533 S.W.2d 914, 916 (Tex.1975) (implied covenant to protect against drainage extended to overriding royalty owners). The commentators note an alternative covenant based on the duty of fair dealing, which applies to every contract, also extends to the relationship owed by the operator to nonworking interest owners. Id. § 420.2. Imposition of a duly of fair dealing does not contradict Degenhart v. Gold King Petroleum Corp., 851 P.2d 304 (Colo.App.1993) in which the *660court of appeals correctly explained the reservation of an overriding royalty interest does riot create a confidential or fiduciary relationship. Id. at 306.
. Indeed, the lack of a standard procedure in allocation of these costs was evident from Cono-co’s oral argument where counsel explained litigation to establish allocation of post-production costs has produced a morass of results.
. Amicus Curiae Rocky Mountain Oil and Gas Association (RMOGA) urged us to distinguish royalty owners from overriding royalty interest owners. RMOGA argued overriding interest owners' familiarity with the industry justifies imposing upon them post-production costs. We cannot reconcile this argument with the decision by such knowledgeable parties to retain only an expense-free nonworking interest. If an overriding royalty owner familiar with the industry wanted to share in the risk and cost of exploration the retention of a working interest would achieve the desired result. Here, the reservation of an overriding royalty interest evidences the choice not to be burdened with costs of production and marketing.
.Marketable means "fit to be offered for sale in a market; being such as may be justly and lawfully bought or sold ... wanted by purchasers.” Webster's 3rd New International Dictionary at 1383 (1986). Williams and Meyers define marketable condition as gas "sufficiently free from impurities that it will be taken by a purchaser.” 8 Williams & Meyers at 692. At oral argument counsel for the Garmans characterized market*661ing costs as those costs incurred to place the gas in a condition which meets pipeline standards. When the federal government has, considered these processes it has distinguished between "operations that condition a product for market, for which a lessee is not entitled to an allowance, and those that transform it. If transformation is involved, a manufacturing allowance is appropriate.” See Exxon Corp., 98 I.D. 110, 127, 118 I.B.L.A. 221 (1991).
. Kuntz explains "[m]uch difficulty can be avoided if it is recognized that there is a distinction between acts which constitute production and acts which constitute processing or refining ... [affter a marketable product has been obtained, then further costs in improving or transporting such product should be shared by the lessor and lessee....” 3 Kuntz § 40.5. (emphasis supplied).
. Some difficulty may arise in computing post-production marketing costs if the operations necessary to prepare the product for market, and operations to enhance the value of a marketable product, occur at the same facility. When the same company both extracts and processes the gas all operating costs must be closely scrutinized. See Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex.Civ.App.—El Paso 1979):
The greatest possible leeway should be indulged the lessee in his decisions about marketing gas, assuming no conflict of interest between lessor and- lessee. Ordinarily the interests of the lessor and lessee will coincide; the lessee will have everything to gain and nothing to lose by selling the product. Where the interests of the two diverge and the lessee lacks incentive to market gas, closer supervision of his business judgment will be necessary. Id. at 286 (quoting Williams and Meyers § 856.3).
Such a determination is a question of fact to be decided based on competent evidence in the record. See Davis v. Cramer, 837 P.2d 218, 222 (Colo.App.1992) (explaining the question whether the lessee was diligent in its marketing efforts is "based upon equitable considerations regarding the particular facts of the case.”). The Federal Regulations are instructive on this point. 30 C.F.R. § 206.159(b) (1993) allows a processing deduction for "reasonable actual costs” incurred when a lessee has a "non-arm’s-length processing contract or has no contract.”