
    No. 70,990
    Martha Sternberger, individually and as representative of all gas royalty owners to whom defendants have made or should make payment of certain royalties and interest thereon, Appellees, v. Marathon Oil Company, Appellant.
    
    (894 P.2d 788)
    
      Opinion filed March 17, 1995.
    
      Evan J. Olson, of Hershberger, Patterson, Jones & Roth, L.C., of Wichita, argued the cause, and Marc P. Clements, of the same firm, and John Gunter, of Marathon Oil Company, of Oklahoma City, Oklahoma, were with him on the briefs for appellant.
    
      Robert W. Christensen, of Christensen, Johnston & Eisenhauer, of Medicine Lodge, argued the cause and was on the briefs for appellees.
    
      Richard C. Hite, of Kahrs, Nelson, Fanning, Hite & Kellogg, of Wichita, and David E. Pierce, of Shughart, Thompson & Kilroy, of Overland Park, were on the brief for amicus curiae The American Petroleum Institute.
    
      Alan C. Goering, of Goering & Slinkard, of Medicine Lodge, and Robin Stead and Donald F. Heath, Jr., of Robin Stead & Associates, P.C., of Norman, Oklahoma, were on the brief for amicus curiae National Association of Royalty Owners.
    
      Donald P. Schnacke, of Topeka, was on the brief for amicus curiae Kansas Independent Oil and Gas Association.
    
      Dale M. Stucky, Thomas D. Kitch, Gregory J. Stucky, and David G. Seely, of Fleeson, Gooing, Coulson & Kitch, L.L.C., of Wichita, and B.E. Nordling, Wayne Tate, and Erick Nordling, of Kramer, Nordling, Nordling & Tate, of Hugoton, were on the brief for amicus curiae Southwest Kansas Royalty Owners Association.
   The opinion of the court was delivered by

Abbott, J.:

This is a multistate oil and gas class action suit involving Kansas and non-Kansas plaintiffs who own royally and overriding royalty interests in oil and gas leases located in Kansas, Oklahoma, Texas, Louisiana, Utah, and Colorado. The Louisiana, Utah, and Colorado leases are no longer in the case and are not in issue on appeal. Defendant Marathon Oil Company’s predecessor in interest, TXO Production Corp. (TXO), deducted from the royalties “marketing costs” or “gathering line amortization expenses” to recover a portion of its expenses in constructing and maintaining gas gathering pipeline systems to transport gas from the lease to markets off the lease. The trial court held the deductions improper, and Marathon Oil Company appealed. Other issues include conflict of law issues, whether a class should have been certified, and the notices given to the class members.

The facts are not substantially disputed. Plaintiff Martha Stemberger owns a royally interest in an oil and gas lease in Barber County, Kansas. She is the named representative of a class of plaintiffs who own royalty and overriding royalty interests in oil and gas leases located in Kansas, Oklahoma, and Texas. The leases were owned and operated by TXO, which was merged into Marathon Oil Company (Marathon) on December 31, 1990. Plaintiffs and Marathon stipulated that the rights of all parties should be construed according to the language of the gas royalty clause in Stemberger’s lease, which provides in pertinent part that lessee agrees

"[t]o pay lessor for gas of whatsoever nature or kind produced and sold, or used off the premises, or used in the manufacture of any products therefrom, one-eighth (Vs), at the market price at the well, (but, as to gas sold by lessee, in no event more than one-eighth (Vs) of the proceeds received by lessee from such sales), for the gas sold, used off the premises, or in the manufacture of products therefrom, said payments to be made monthly.”

At issue in this appeal are 19 wells in Barber County, Kansas, involving 38 individual royalty interest owners, and numerous wells and royalty and overriding royalty interests in Oklahoma and Texas.

There was no market for gas at the wellhead, and TXO was unable to induce a gas purchaser to construct a pipeline to the well bore. Historically, about 85% of all gas purchasers paid the cost and built the lines necessary to gather and transport the gas to market. For the plaintiffs’ wells, TXO laid its own gas gathering pipeline system to transport gas from the wells to the market; otherwise, the wells would have remained nonproductive and the gas would not have been sold. For the Stemberger wells, the gas was transported from the wellhead through the gas gathering system laid by TXO to the Kansas Gas & Supply (KG&S) pipeline. TXO then paid a transportation fee to KG&S to transport die gas to the purchaser. The transportation fee TXO paid to KG&S was charged back to the royalty owners. That cost is not in dispute and is not an issue in this case.

TXO paid 100% of the cost of constructing the gas gathering pipeline system. The total cost for all wells on the Stemberger line (six wells) was calculated to be $127,995.88. TXO then deducted from Stemberger’s royalty payments 12 cents per thousand cubic feet (MCF) for 12 months as a “marketing cost” or “line amortization charge” to recover a proportionate cost of the pipeline. In determining that 12 cents per MCF for 12 or 13 months would yield the proper payback for the proportionate costs of constructing the pipeline (Vs of the cost of the pipeline), TXO considered the entire cost of the pipeline, including maintenance of the pipeline, costs of tracking the pipe from Oklahoma to the lease property, $400.00 per day for the TXO foreman or production superintendent to supervise the work, the costs of a survey, the costs of obtaining the necessary right-of-way, and other such expenses.

In exchange for laying the pipeline to connect the wells to the KG&S transmission system, TXO received from KG&S a 10 to 16 cent (12 cents on the average) discount on the transportation fee KG&S would have charged TXO for transportation from the Stemberger wells had KG&S laid the line. In other words, the 12 cent per MCF savings TXO received from KG&S was charged to the royalty interests in Kansas for one year. However, after the deductions were ceased in 12 months, the royalty owners realized a 12 cent per MCF discount because KG&S continued to charge TXO 12 cents per MCF less than it would have had KG&S laid the line.

Marathon has characterized the amortization charge as a user s fee or a gathering fee. Marathon currently owns the whole of the pipeline. TXO did not seek approval from Stemberger or other royalty or overriding royalty interests before laying the gathering system for the Stemberger or other wells, but TXO did obtain approval from other working interests before doing so.

TXO recovered 12% of its cost in constructing the line from Stemberger and other royalty interests connected with that line.

Stemberger filed suit against TXO in January 1991 to recover the gathering amortization deductions. Stemberger sought to represent a class of plaintiffs who owned royalty and overriding royalty interests in oil and gas leases owned and operated by TXO located in Kansas, Oklahoma, Texas, Louisiana, Colorado, and Utah and from whom TXO deducted “line amortization charges” similar to those it deducted from Stemberger s royalties. The line amortization charges deducted from other members of the plaintiff class differ from those deducted from Stemberger in that in some cases the deductions were designed to continue during the life of the well rather than to recoup the proportionate share of the pipeline expense in one year. Not all amortization charges were set at 12 cents per MCF; at least one well in Oklahoma was charged 17 cents per MCF, and a Texas well was charged 4 cents per MCF deducted over the life of the well. In some cases where the gathering pipeline was laid, TXO did not deduct a proportionate share of the expenses from the royalty and overriding royalty interests because the pipeline lateral was so short it did not justify the cost of setting up the accounting system. All gathering amortization deductions ceased in October 1990 when TXO was merged into Marathon because the Marathon accounting system was incapable of making the deductions.

Class representative Martha Stemberger filed this action against TXO in Barber County District Court on January 14, 1991. TXO removed the action to federal court, and the action was subsequently remanded back to the Barber County court. TXO was the original named party defendant, but Marathon was subsequently substituted as the named defendant as a result of the merger of TXO into Marathon.

The class was certified on January 22, 1993. The plaintiff class was defined as follows:

“Ail royalty owners and overriding royalty owners who owned property in Kansas, Oklahoma, [or] Texas . . . subject to oil and gas leases either owned and/or operated by TXO Production Corp. from which gas was produced and whose royalty or overriding royalty was subject to deductions by TXO for pipeline gathering amortization expenses which were referred to as ‘marketing costs.’ ”

The trial court divided the class into subclasses by state and then dismissed the claims arising from Colorado and Utah because the potential subclasses did not satisfy the numerosity requirement and because the amount of any claims from those states were cle minimis. The court held that the proposed class of plaintiffs was numerous and that actual joinder of all members was impracticable, that the claims of the named class representative, Sternberger, were typical of the claims of the other members of the class, and that the deductions provided common questions of law and fact which predominated over questions affecting only individual members of the class. The court later determined the statute of limitations had expired on any Louisiana claims, leaving the leases in Kansas, Oklahoma, and Texas at issue.

The trial court ordered that notice, by forms approved by the court, be mailed to class members on January 25, 1993, and published on February 1, 1993. The notice mailed to class members included a Request for Exclusion which class members were instructed to return to class counsel postmarked on or before February 10, 1993. Between 90 and 100 exclusion requests were received which were postmarked on or before February 10, 1993. These class members were permitted to opt out of the class. An additional seven members submitted exclusion requests postmarked after February 10, 1993, but before trial, which was February 25, 1993. The trial court did not permit these members to opt out of the class. The trial court’s failure to grant the late exclusion requests is an issue on appeal.

The trial court held that the deductions by TXO, now Marathon, for pipeline construction expenses were improper. Marathon appeals.

The parties stipulated to the judgment amount of $119,994.52, which is the amount of fees deducted excluding amounts attributable to class members who opted out on or before February 10,1993, and excluding claims for deductions which the trial court found were barred by the applicable statutes of limitations in Oklahoma, Texas, and Louisiana. The parties further stipulated to prejudgment interest on that amount of $50,346.63, for a total judgment against Marathon of $170,341.20. The calculation of the judgment amount and prejudgment interest are not issues on appeal.

This court permitted the filing of amici curiae briefs by the American Petroleum Institute, the Southwest Kansas Royalty Owners Association, the National Association of Royalty Owners, and the Kansas Independent Oil and Gas Association. They are of high quality (as are the parties’ briefs) and of much help to the court.

PIPELINE FROM WELL

At the outset it must be noted that Stemberger and Marathon disagree as to how this issue should be phrased. Marathon suggests the issue is merely whether the costs incurred to transport gas off the lease to a distant market may be deducted, whereas Stemberger argues the issue is whether Marathon may deduct its actual expenses incurred in constructing a gas pipeline from Stemberger’s wells to the transmission line of the gas purchaser.

The relevant portion of the lease provision governing in this action provides that Marathon will pay royalties of one-eighth (Vs) of the market price at the well for gas sold or used. The lease provision is silent as to deductions. Stemberger argues that the lease is ambiguous and therefore must be construed in her favor to preclude the deductions made by Marathon. By adopting Stemberger’s suggested findings of fact and conclusions of law, the district court agreed with Stemberger that the lease is ambiguous. Stemberger bases her assertion of an ambiguity on the fact that the lease is silent as to whether or not the lessee has the authority to deduct post-production expenses from royalty proceeds.

Stemberger correctly states that ambiguities in an oil and gas lease are to be construed in favor of the lessor. See Gilmore v. Superior Oil Co., 192 Kan. 388, Syl. ¶ 2, 388 P.2d 602 (1964). Here, however, the lease is not ambiguous. The lease’s silence on the issue of post-production deductions does not make the lease ambiguous. The lease clearly specifies that royalties are to be paid based on “market price at the well.”

The American Petroleum Institute (API) points out that there was no actual market at the well here, though the lease provided for royalties based on the market price at die well. API argues, “In the absence of an actual market at the well, the market price at the well must logically be determined by deducting from the market price at an available point of sale off the lease the expense of transporting the gas there.” Generally, Kansas law holds that transportation costs are borne proportionately by the lessor and the lessee where the royalty is to be determined at the well but no market exists at the well.

In Scott v. Steinberger, 113 Kan. 67, 213 Pac. 646 (1923), an oil and gas lease provided for the lessee to pay the lessor “free of cost in the pipe lines to which he may connect his wells one-eighth of all oil produced and saved on said premises, and shall pay the market price for same in cash if [lessor] shall so desire; and shall pay to [lessor] one-eighth of all gas produced and marketed.” Because there were no pipelines near the leased premises, the lessee constructed a pipeline at a cost of $61,680. The reasonable value of gas at tire field was found to be 8 cents per MCF, the reasonable cost of transporting gas was found to be 7 cents per MCF, and gas transported through the pipelines was sold for 15 cents per MCF. The dispute between the parties concerned whether the lessor was entitled to the value of the gas at the field or the price at which it was sold at the end of the pipeline. This court found the lease somewhat ambiguous regarding the point at which the price of the gas was to be fixed. This court determined the parties contemplated that the market price of the gas should be determined at the place where the wells were connected with the pipeline and not at some distant market where the gas might be sold. Thus, where the price of the gas was to be determined at the well, royalties were to be paid at a rate of 8 cents per MCF, the reasonable value of the gas at the field.

This court reached a similar result 10 years later in Voshell v. Indian Territory Illuminating Oil Co., 137 Kan. 160, 19 P.2d 456 (1933), in an oil and gas case where there was no market for the oil at the field. The lease provided that the lessor would receive “free of cost, in the pipe line to which he may connect his wells, the equal one-eighth part of all oil produced and saved from the leased premises.” 137 Kan. at 161. A market price posted in McPherson County was generally regarded as the market price for oil in that area, including for oil from lessor’s wells. Eventually, though, the market for oil in that area shrank and the lessee was unable to secure a buyer for its oil. The oil wells still had to be pumped, however, to prevent their destruction. Therefore, the lessee arranged to transport, at a price of 12.5 cents per barrel, the oil from lessor’s wells to a distant market at El Dorado. Royalties were calculated and paid based on the posted price in El Dorado less the transportation charges. The lessor argued that the market price should have been regarded as the posted price in the McPherson field. This court agreed that ordinarily those prices would be the same but stated, “[A] market price presupposes the existence of a market. But there was no market[;] nobody was paying the posted price’ except the limited few who were fortunate enough to have pipe-line connections in the field.” 137 Kan. at 164. Because there was no market in the Voshell field for the oil in which lessors were interested, the amount tendered by the lessee — the selling price at El Dorado less the cost of transportation — was approved by this court.

In 1943 this court again reached a similar conclusion. In Molter v. Lewis, 156 Kan. 544, 134 P.2d 404 (1943), the relevant lease provision required the lessee “[t]o deliver to the credit of lessor, free of cost, in the pipeline to which he may connect his wells, the equal one-eighth part of all oil produced and saved from the leased premises.” When the lease was executed, there was no pipeline connection to the leasehold, and the lessee was unable to obtain a pipeline connection to the leasehold. In order to obtain a market, it was necessary to transport the oil by truck. The lessee transported by truck all oil, including that belonging to the lessors, from the Greenwood County leasehold to a market at El Dorado or to other markets. The lessee then sought to recover from the lessors the reasonable charge for transporting the oil belonging to the lessors. Discussing Scott and Voshell as well as oil and gas treatises, the Molter court held:

“[I]t is the duty of the lessee, without cost to the lessor, to use all reasonable efforts to have pipe lines connected with producing wells which he drills on the lease. If after using such efforts he is unable to get a pipe line connected to the wells on the lease, and to prudently operate the lease transports the oil by (ruck from the wells on the lease to a pipe line, the lessor should pay the reasonable charges for the transportation by truck of his one-eighth share of the oil.” 156 Kan. 544, Syl.

In so holding, this court quoted language from Mills and Willingham, Law of Oil and Gas § 130 (1926):

“ ‘[I]f the lessee constructs a pipe line or deals with another to do so, he is entitled to charge against the lessor his proportion of the reasonable rental value of such line. The lessor, however, is not liable for the cost of such line. Where the lessee undertakes to and does market his own oil or gas by pipe line or tank car it would seem that he would be bound to take the royally share along with his own, but is only liable for the reasonable value of the royalty share at the well.’ ” Molter, 156 Kan. at 548-49.

Scott, Voshell, and Molter are dispositive of the issue in this case. These cases clearly show that where royalties are based on market price “at the well,” or where the lessor receives his or her share of the oil or gas “at the well,” the lessor must bear a proportionate share of the expenses in transporting the gas or oil to a distant market. Authorities cited by Marathon also support this conclusion.

Marathon suggests that the majority rule is that the lessor’s royalty share is free of production costs but is subject to costs subsequent to production. Marathon cites several oil and gas commentators: 3 Williams & Meyers, Oil and Gas Law § 645.2, p. 598 (1994) (“A royalty or other nonoperating interest in production is usually subject to a proportionate share of the costs incurred subsequent to production where . . . the royalty ... is payable 'at the well’ ”); 5 Kuntz, Law of Oil and Gas § 60.1 (1991) (lessee has duty to deliver gas to market; if identified as a production cost, lessee bears the cost, and if identified as a marketing cost, the lessor shares in the cost proportionately). Marathon stresses that the leases at issue here provided for gas royalty to be paid based upon the market price at the well. Marathon reasons that ''[w]here, as here, there is no market on the lease, the parties clearly contemplated that royalty should bear a share of the cost to transport the gas to market.”

Marathon relies on Matzen v. Hugoton Production Co., 182 Kan. 456, 321 P.2d 576 (1958), and Ashland Oil & Refining Co. v. Staats, Inc., 271 F. Supp. 571 (D. Kan. 1967). In Matzen, the royalty clause provided for payment of “one-eighth of the proceeds from the sale of gas, as such, for gas from wells where gas only is found.” The supply greatly exceeded the demand in die field, and it was necessary that the gas be transported from the wellheads to a distant market. The lessee contracted with a purchaser to supply gas. The lessee constructed a gathering pipeline system, having a total length of over 184 miles, connecting each of its 152 producing gas wells. The gas was metered at the.wellhead and then moved through the pipeline in a commingled mass to a point where the sale and delivery into the purchaser’s pipeline occurred. The lessee also constructed a gasoline plant and a dehydrating plant and obtained a purchaser for some of the remaining gas. 182 Kan. at 458-59.

The parties in Matzen agreed that the royalty was to be determined at the wellhead rather than at the point of sale and that there was no market price at the wellhead. At issue was how to calculate the royalties. 182 Kan. at 459. The trial court determined that proceeds at the well were equal to gross proceeds from total sales less proper chargeable operating expenses incurred in procuring such proceeds (“proceeds-less-expenses” formula). Proper operating expenses included gathering, processing and dehydrating. 182 Kan. at 460. This court agreed:

“It was as much [lessee’s] duty to find a market on the leased premises without cost to the plaintiffs as it was to find and produce the gas [citation omitted], but that duty did not extend to providing a gathering system to transport and process the gas off the leases at a large capital outlay with attending financial hazards in order to obtain a market at which the gas might be sold. When plaintiff’s leases were executed it was the established custom and practice in the field to measure, determine the price, and pay royalty at the wellhead for gas produced. Pipeline facilities did not exist and there was no general market for gas in the area. Although the leases are silent as to where a market must be found, it is evident the parties anticipated, from the very nature and character of natural gas, that pipe-line transportation would be required in the event of production and they could not reasonably have contemplated that the lessee alone would bear the expense of providing such transportation to a point off tlie leases for sale and delivery to a purchaser for ultimate consumption. . . .
“The language ‘proceeds from the sale of the gas, as such,’ must be construed from the context of die leases and the custom and practice in the field at the time they were executed, and we think where, as here, the gas produced is transported by die lessee in its gathering system off the premises and processed and sold, its royalty obligation is determined by deducting from gross proceeds reasonable expenses relating directly to the costs and charges of gathering, processing and marketing the gas.” 182 Kan. at 462-63.

The lessee sought also to deduct federal and state income tax expenses as operating expenses. The trial court held that maintenance, depreciation, and ad valorem and other direct taxes were properly deductible from the gross proceeds to calculate royalties, but the court disallowed federal and state income taxes as deductions. This court agreed that federal and state income taxes were not proper deductions, stressing that the lessee’s own accounting system did not include income taxes as part of its operating expenses. 182 Kan. at 464-65.

In adopting the proceeds-less-expenses formula, the Matzencourt distinguished Scott, Voshell, and Molter because those cases involved lease provisions which provided for delivery of a specific portion of the oil or gas produced rather than for payment as royalty a portion of the proceeds from the sale of the gas. Matzen, 182 Kan. at 463. That distinction is not significant in the context of the case at bar. Scott, Voshell, Molter, and Matzen all stand for the proposition that reasonable transportation expenses are shared by the lessor and the lessee where royalties are paid (in oil or gas or in money) “at the well” but there is no market at the well.

In Ashland Oil, 271 F. Supp. 571, the lessee operated and maintained a 153-mile gathering system. The lessee obtained a purchaser for gas at a distant market; the purchaser paid a price at the place of sale, and the purchaser also paid to the lessee the costs of gathering and transporting the gas through lessee’s gathering system. The lessors sought royalties on the gathering and transportation charges recouped by the lessee. The court disagreed, stating, “We will not so enlarge the lessee’s duty to market production so as to require it to devote a long and costly gathering system to transport gas to the nearest commercial market.” Ashland Oil, 271 F. Supp. at 575. Following Scott, 113 Kan. 67, the court stated, “Likewise, in this case, we hold that the duty to market gas does not require Ashland to devote its pipeline, even though existing at the time part of the leases were executed, to gather and transport gas from lessors’ property to the purchaser’s pipeline.” Ashland Oil, 271 F. Supp. at 576. The court held that the gathering and transportation charges paid by the purchaser were not proceeds from the sale of gas; thus, royalties were not due on charges for the use of an extensive and valuable gathering system regardless of where the gas was delivered. 271 F. Supp. at 578. Royalties were paid on the sale of gas as metered at the well; any leakage during transportation was borne by the lessee and not the lessors. 271 F. Supp. at 577-78.

Stemberger attempts to distinguish Matzen and Ashland Oil from the case at bar. Stemberger points out that the parties in Matzen stipulated that the lessors must bear a portion of the gathering, processing, and marketing costs. See Matzen, 182 Kan. at 467 (Fatzer, J., concurring). Stemberger also reasons that the issue in Ashland Oil was whether the lessee must pay royalties on transportation charges recouped by the lessee; the issue was not whether the lessee could deduct transportation charges from the royalties.

Stemberger cites Gilmore v. Superior Oil Co., 192 Kan. 388, 388 P.2d 602 (1964), Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964), and Sterling v. Marathon Oil Co., 223 Kan. 686, 576 P.2d 635 (1978). In Gilmore, the royalty clause provided for the lessee to pay the lessor

“ ‘for gas produced from any oil well and used by the lessee for the manufacture of gasoline or any other product as royalty Vs of the market value of such gas at the mouth of the well; if said gas is sold by the lessee, then as royalty Vs of the proceeds of the sale thereof at the mouth of the well. The lessee shall pay lessor as royalty Vs of the proceeds from the sale of gas as such at the mouth of the well where gas only is found ....”’ 192 Kan. at 391.

There was no market for the gas at the mouth of the well, and gas was being vented and wasted. To make the gas marketable, die lessee installed a large compressor station on the leased premises (rather than small compressors at the mouth of each well). The lessee then sought to have the lessors contribute to the cost of taking the gas from the mouth of the well to the compressor and making it marketable. This court recognized the lessee’s duty to make the gas marketable and found that compression was necessary to make the gas marketable. This court held under the facts that “the lessee . . . has the duty of making the gas marketable and cannot recover from the lessors for the expense of installing a compressing station used to compress all gas produced on the leases because such installation was a necessary expense in the process of making such gas marketable.” 192 Kan. 388, Syl. ¶ 3. We pointed out that the gas was put into pipelines already existing on the leases and therefore the lessee was not put to any great expense in building miles of pipelines for that purpose. 192 Kan. at 393.

In Schupbach, 193 Kan. 401, a similar result was reached where the compression took place off, rather than on, the leased premises. The lessee sought to deduct a one-eighth share of its compression costs to market gas where the royalty clause provided for payment to the lessor of “Vsth of the proceeds of the sale thereof at the mouth of the well.” 193 Kan. at 402. The lessors signed a division order providing for payment of one-eighth of the market price paid by the purchaser for oil, free of cost to the lessors, except that if transportation by truck was necessary, the lessee could deduct from the price die transportation charges. The lessors refused to sign a division order concerning the sale of gas, where the lessee sought to deduct a proportionate share of die actual cost and expense of gathering, processing, and compressing the gas. Relying on Gilmore, this court held that the lessee was not entided to deduct reasonable costs of compression from gross proceeds in computing gas royalties. 193 Kan. at 406.

Finally, Stemberger cites Sterling, 223 Kan. 686. There, this court refused to permit the lessee to set off one-eighth of its expenses and attorney fees incurred in obtaining increased gas prices and its administrative costs incurred in handling “suspense royalties.” This court stated, “Historically, the landowners’ share of the oil and gas royalty is free and clear of all costs of administration, production, marketing, etc.” 223 Kan. at 688.

Stemberger likens the capital expenditure of building this pipeline to the expenses of drilling and equipping a well and argues that such expenses must be borne solely by the lessee. She cites Pray v. Premier Petroleum, Inc., 233 Kan. 351, 662 P.2d 255 (1983). In Pray, 233 Kan. 351, Syl. ¶ 6, this court did state that “[cjapital expenditures for building a pipeline to transport gas to the nearest market fall in the same category as costs of drilling and equipping a well.” That statement was in the context of determining what expenses should be taken into consideration in determining whether a gas well will produce in paying quantities under an oil and gas lease’s shut-in royalty clause; the statement had nothing to do with determining whether the lessee bears those expenses alone or in conjunction with the lessor. While adopting a different standard for paying royalties than for determining if production is in paying quantities may seem like allowing the producer to have its cake and eat it too, it has a valid public purpose of encouraging maximum use of the oil and gas by keeping low-producing and stripper wells producing.

Stemberger also points out that the Pray court noted testimony that “85% of the time the purchaser of the gas brings the transportation line to the well.” 233 Kan. at 356. Amicus Kansas Independent Oil and Gas Association (KIOGA), representing the smaller producers, suggests that this is no longer true and that therefore gas producers must lay and maintain gathering and transportation lines, an expensive proposition for the smaller producers. If the purchaser does generally bring the transportation line to the well, that fact perhaps strengthens Marathon’s position rather than Stemberger’s. If the purchaser brings the transportation line to the well, the purchaser will pay the market price at the well. This price will reflect the expense incurred by the purchaser in bringing the pipeline to the well and will be less than the purchaser would have paid had it not had the expense of bringing the line to the well. The price will also include a risk factor and a return on investment, neither of which is involved in this case.

The trial court, in addition to adopting the argument and authorities cited by Stemberger, noted that a transportation pipeline or purchaser may offer the operator the option of paying a higher price if the operator constructs a pipeline to deliver the gas and a lower price if the purchaser must construct the pipeline to receive the gas produced at the wellhead. The court expressed concern that the operator of the well (lessee) alone determines whether the economics justify capital expenditures in constructing a pipeline to transport the gas from the wellhead to the purchaser; the lessors have no voice in the decision. This certainly is a possibility. However, there is no suggestion that Marathon s decision to construct the pipeline here was not financially justified and to the lessor s benefit.

Amicus curiae Southwest Kansas Royalty Owners Association (SKROA), in supporting Stemberger s position that Marathon is not entitled to these deductions, adds an interesting argument not set forth by Stemberger. SKROA stresses the distinction between gathering and transportation, as does amicus curiae National Association of Royalty Owners (NARO). Pointing out that Marathon characterized its deductions as “gathering line amortization expenses,” SKROA argues that the costs deducted by Marathon were gathering expenses rather than transportation expenses. Marathon disputes that there is a distinction between gathering and transportation expenses.

SKROA relies on Gilmore, 192 Kan. 388, and Schupbach, 193 Kan. 401, to argue that costs of preparing gas for market are not deductible. As discussed above, Gilmore and Schupbach held that cost of compression which occurs away from the mouth of the well are not deductible even where, as SKROA stresses, the royalty is to be paid based on market price at the mouth of the well.

The lessee has the duty to produce a marketable product, and the lessee alone bears the expense in making the product marketable. Contrary to SKROA’s argument, however, there is no evidence in this case that the gas produced by Marathon was not marketable at the mouth of the well other than the lack of a purchaser at that location. There is no evidence that Marathon engaged in any activity designed to enhance the product, such as compression, processing, or dehydration. There is no evidence that Marathon attempted to deduct any expenses in making the gas marketable other than those of constructing a pipeline to transport the gas to the purchaser or to a transmission pipeline. Therefore, the deductions made by Marathon are properly characterized as “transportation” rather than “gathering” or other production costs.

We are also directed to Garman v. Conoco, Inc., 886 P.2d 652 (Colo. 1994). That case involves a certified federal question. In it, the Colorado Supreme Court held as we believe the law in Kansas to be: Once a marketable product is obtained, reasonable costs incurred to transport or enhance the value of the marketable gas may be charged against nonworking interest owners. The lessee has the burden of proving the reasonableness of the costs. Absent a contract providing to the contrary, a nonworking interest owner is not obligated to bear any share of production expense, such as compressing, transporting, and processing, undertaken to transform gas into a marketable product. In the case before us, the gas is marketable at the well. The problem is there is no market at the well, and in that instance we hold the lessor must bear a proportionate share of the reasonable cost of transporting the marketable gas to its point of sale.

The parties stipulated that the rights of the plaintiff class would be determined based on the language of the royalty clause in the Sternberger lease. That lease provided for royalties based on “market price at the well.” However, there was no market at the well. In order to obtain a market, Marathon constructed a pipeline from the wellhead to the purchaser — or for Stemberger’s and other wells, from the wellhead to a transmission line — in order to transport the gas to a distant market. Under Kansas authority, Sternberger and other members of the plaintiff class are responsible for their proportionate share of the reasonable expenses in transporting the gas from her wellhead to market, and Marathon may properly deduct reasonable transportation expenses from the royalties. We stress that the transportation expenses must be reasonable.

CONFLICT OF LAWS

The district court created subclasses in this case out of concern for the conflict of law issue because the claims of nonresidents arose in states other than Kansas. The district court substantially adopted the analysis set forth in Stemberger’s proposed findings of fact and conclusions of law. Stemberger argued that Oklahoma law denied any deductions in the absence of an agreement between the parties. Stemberger also argued that Texas law is conflicting and confusing and therefore the law of Kansas should apply. By adopting Stemberger’s analysis, the district court agreed and applied what it perceived to be Oklahoma law to the claims arising in Oklahoma and Kansas law to the claims arising in Texas.

Marathon argues that in a multistate class action where oil and gas leases are located in states other than Kansas, application of Kansas law is arbitrary and unfair, in violation of constitutional limits.

In Phillips Petroleum Co. v. Shutts, 472 U.S. 797, 86 L. Ed. 2d 628, 105 S. Ct. 2965 (1985), the United States Supreme Court was faced with a multistate oil and gas class action not entirely dissimilar to the case at bar, though the substantive issue was different. In that case, 99% of the claims arose from oil and gas leases not located in Kansas, and 97% of the plaintiff class members had no contacts with Kansas other than as members of the plaintiff class in an action being adjudicated in Kansas. 472 U.S. at 815. The district court applied Kansas law to all of the claims, and this court affirmed. Shutts v. Phillips Petroleum Co., 235 Kan. 195, 679 P.2d 1159 (1984). This court stated that the law of the fomm applies unless it is expressly shown that a different law governs and that in a nationwide class action where procedural due process guarantees are satisfied, the law of the fomm should be applied absent compelling reasons for applying a different law; this court found no such compelling reasons. 235 Kan. at 221-22. In reversing, the United States Supreme Court stated: “We must first determine whether Kansas law conflicts in any material way with any other law which could apply. There can be no injury in applying Kansas law if it is not in conflict with that of any other jurisdiction connected to this suit.” 472 U.S. at 816. The Court noted that there may be some differences between Kansas law and the law of other jurisdictions connected to the suit. Pointing out that the parties had no idea that Kansas law would control at the time the leases outside Kansas were executed, the Court concluded:

“Kansas must have a ‘significant contact or significant aggregation of contacts’ to the claims asserted by each member of the plaintiff class, contacts ‘creating state interests,’ in order to ensure that die choice of Kansas law is not arbitrary or unfair. [Citation omitted.] Given Kansas’ lack of ‘interest’ in claims unrelated to that State, and the substantive conflict with jurisdictions such as Texas, we conclude tiiat application of Kansas law to every claim in this case is sufficientiy arbitrary and unfair as to exceed constitutional limits.” 472 U.S. at 821-22.

The Supreme Court then remanded the case to this court for a determination as to which law to apply to the claims.

On remand, the district court found that the laws of other states did not conflict with the laws of Kansas on the relevant issues. Shutts v. Phillips Petroleum Co., 240 Kan. 764, 768, 732 P.2d 1286 (1987), cert denied 487 U.S. 1223 (1988). Following an exhaustive discussion about the law of the five jurisdictions other than Kansas, where 99% of the leases at issue were located (Texas, Oklahoma, Louisiana, New Mexico, and Wyoming), this court found that all but Wyoming had law consistent with Kansas law; Wyoming had no law on the issue. 240 Kan. at 798. This court affirmed the judgment of the district court in general. However, this court found that application of the Kansas post-judgment interest rate to the claims arising in Texas, Oklahoma, Louisiana, New Mexico, and Wyoming was improper; the statutoiy post-judgment interest rate of each state must be applied. 240 Kan. at 801. Moreover, the substantive law of Kansas as well as the Kansas statutory post-judgment interest rate was applied to all claims not arising in the five states discussed above because the lessee failed to argue the law of those states conflicted with Kansas law. 240 Kan. at 798, 802.

In Sun Oil Co. v. Wortman, 486 U.S. 717, 100 L. Ed. 2d 743, 108 S. Ct. 2117 (1988), the United States Supreme Court again addressed the question of choice of law in multistate oil and gas class actions. The issue was similar to that which was decided in Shutts, and the lessee (Sun Oil) argued that this court in Shutts, 240 Kan. 764, misconstrued the law of Texas, Oklahoma, and Louisiana. The United States Supreme Court stated:

“To constitute a violation of the Full Faith and Credit Clause or the Due Process Clause, it is not enough that a state court misconstrue the law of another State. Rather, our cases make plain that die misconstruction must contradict law of the other State that is clearly established and that has been brought to the court’s attention.” 486 U.S. at 730-31.

The Court then concluded that the lessee had not brought to this court’s attention any clearly established law of the other states which contradicted our construction of the law of the other states.

Marathon argues here that the district court misconstrued the clearly established law of Oklahoma and Texas. Marathon suggests that both Oklahoma and Texas permit the lessee producing gas to deduct the costs incurred in transporting the gas to a market off the lease, though Marathon admits that the specific type of cost may not have been at issue. Marathon reasons that application of Kansas law was arbitrary and unfair.

We will examine Oklahoma and Texas law separately in light of our holding that Kansas permits deduction of reasonable transportation expenses where the royalty is payable at the market price at the well but there is no market at the well.

OKLAHOMA

Marathon relies primarily on Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970), in arguing that Oklahoma law permits a lessee to deduct from royalties a proportionate share of costs associated with marketing and transportation. The royalty provision at issue provided for a royalty of “one-eight (Vs) of the gross proceeds at the prevailing market rate for all gas sold off the premises.” 475 P.2d at 397. There was no market at the wellhead, and the gas was transported for sale at a place 10 miles away from the lease property. The court construed the phrase “gross proceeds at the prevailing market rate” to mean the market rate at the wellhead or in the field and not at the purchaser’s location, which may be some distance away from the leased premises. 475 P.2d at 398. The court concluded:

“Under the lease the lessor is only entitled to a certain- percentage of the gross proceeds of the prevailing market rate. As the prevailing market rate is determined at the wellhead or in the field so must the term ‘gross proceeds’ be interpreted. ‘Gross proceeds’ has reference to the value of the gas on the lease property without deducting any of the expenses involved in developing and marketing the diy gas to this point of delivery. When the lessee has made the gas available for market then his sole financial obligation ceases, and any further expenses beyond die lease property must be borne proportionately by the lessor and lessee.’’ 475 P.2d at 399.

Thus, the lessee was entitled to deduct from the royalties a transportation cost of 2 cents per MCF to transport the gas 10 miles by a pipeline operated by the lessee.

Wood v. TXO Production Corp., 854 P.2d 880 (Okla. 1992) (as corrected on limited grant of rehearing May 24, 1993), relied on by Stemberger (and the district court), is not to the contrary. The Wood court answered a certified question: “Is an oil and gas lessee/operator who is obligated to pay the lessor <3/i6 at the market price at the well for gas sold’, entitled to deduct the cost of gas compression from the lessor’s royally interest?” TXO contracted with purchasers to deliver gas into the purchasers’ lines at a certain pressure. The wells operated by TXO initially produced gas at a sufficient pressure, but eventually the pressure dropped, and TXO built compressors on the leased premises to reach the requisite pressure. TXO sought to deduct the lessors’ proportionate share of the compression costs. The court acknowledged that Johnson requires that “the lessor must bear its proportionate share of transportation costs where the point of sale was off the leased premises.” Wood, 854 P.2d at 881. However, the Wood court noted that it had never held that the lessor is required to bear any transportation costs where the place of sale is on the leased premises. “In our view, the gas is ‘sold’ when it enters the purchaser’s line. Here that line is on the leased premises and there is no ‘transportation’ cost.” 854 P.2d at 881. Citing Schupbach and Gilmore, the court recognized that Kansas law requires the lessee to bear compression costs where compression is required in order to market the gas. Choosing to follow Kansas law, the Wood court found compression costs not deductible where the gas enters the purchasers’ lines on the leased premises. The court stated:

“One of the risks borne by the lessee in exploring for gas is that the gas will be low pressure. In our view, the implied duty to market means a duty to get the product to tire place of sale in a marketable form. Here the compressors and the connections to the gas purchasers’ pipelines are on the leased premises. There is no sale at a distant market and no necessity of transporting die product to the place of sale as there was in Johnson v. Jernigan." 854 P.2d at 882.

Stemberger points to the following language in Wood to assert that Wood dilutes the strength of Johnson:

“Some authorities believe that marketing expenses should be included as lessee’s operating costs because, without marketing, there is no production in paying quantities. Other authorities argue that the lessee has fulfilled his duty by obtaining gas capable of producing in paying quantities, and that the lessee should not have to bear alone the costs of ‘enhancing’ the product obtained, and the analysis centers on determining when a marketable product has been obtained. The authorities holding the second view make a distinction between production and ‘post production’ costs, holding that the lessor must bear its proportionate share of ‘post production’ costs. We reject this analysis in Oklahoma. We have said only that die lessor must bear its proportionate share of transportation costs where the point of sale was off the leased premises. Johnson v. Jernigan, 475 P.2d 396 (Okla. 1970).” Wood, 854 P.2d at 881.

Wood did not explicitly or implicitly overrule Johnson. Wood merely distinguished Johnson. The deductions involved in each case were of a different nature. Wood involved compression costs while Johnson involved transportation costs. The Wood court noted that it was not faced with a sale at a distant market or the necessity of transporting the product to the place of sale; rather, the sale in Wood occurred on the leased premises. The Wood court’s reliance on Kansas law is significant. Kansas permits deductions for transportation costs where there is no market at the well, but Kansas does not permit deductions for compression costs. Therefore, Wood does not destroy the weight of the Johnson holding that transportation expenses are deductible where there is no market on the leased premises.

Marathon dutifully points out the Oklahoma Supreme Court’s recent decision in TXO Production Corp. v. State of Oklahoma, ex rel., Commissioners of the Land Office, 65 Okla. Bar Journal No. 46, 3972 (No. 78,205, filed November 23, 1994, petition for rehearing filed January 9, 1995, not yet acted on), filed after the parties briefed the issues in the case at bar. The royalty clause in the lease at issue provided for the lessee, TXO, to deliver to the lessor, Commissioners, “without cost into pipelines, a royalty of one-eighth (Vs) part of the oil or gas produced from the leased premises ... or in lieu thereof, pay to the lessor the market value thereof, as the Commissioners may elect.” Slip op. at 4. The Commissioners elected to receive royalties under the market value alternative. TXO deducted “post-production costs” from the royalties, including costs for compression, dehydration, and gathering. The Oklahoma court held that the “without cost into pipelines” language applies to the cash royalty, as well as the royalty in kind, and thus “TXO may not deduct any costs for the royalty payment which results from processes necessary to get the product into pipelines” under the lease provision. Slip op. at 4-5.

The Commissioners court explained its holding in Wood and reconciled Wood with its decision in Johnson. The court reaffirmed the Johnson holding that the lessor shares in the costs of transportation where the point of sale occurs off the leased premises. Because the sale in Wood occurred on the lease site at the mouth of the well, there were no transportation expenses at issue in Wood. Rather, at issue were compression costs. The Wood court held that compression was not analogous to transporting and compression costs were therefore not deductible where compression was necessaiy to make the product marketable. Slip op. at 6-7. The Commissioners court also pointed to its concern expressed in Wood that the royalty owners have no input in cost-bearing decisions made by the lessee and that if a lessee wants the royalty owners to share in compression costs, the lessee can include such a provision in the oil and gas lease. Slip op. at 7.

Relying on Wood, the Commissioners court held that dehydration is necessaiy in order to make the product marketable and that gathering also occurs before the product is placed in the purchasers pipeline; therefore, these expenses, like compression, are not deductible. Slip op. at 8. In so holding, the Oklahoma Supreme Court expressly rejected Louisiana law (Merritt v. Southwestern Elec. Power Co., 499 So. 2d 210 [La. App. 1986],) which held the determination of market value included the subtraction of “costs of taking gas from the wellhead to the point of sale.” Slip op. at 9.

A petition for rehearing has been filed in the Commissioners case, but it has not yet been acted on by the court.

The judgment of the Oklahoma Supreme Court in Commissioners, if it becomes final, clearly holds that costs for compression, dehydration, and gathering are not deductible in the absence of an agreement between the parties. The Woodcourt followed Kansas law concerning the deductibility of compression expenses. Commissioners extends the Wood holding to dehydration and gathering expenses. However, both Wood and Commissioners leave intact the court’s earlier decision in Johnson holding that transportation costs are deductible where sale occurs off the leased premises. The lease in the Oklahoma Supreme Court case involved wording not present in our case. The lease obligates the lessee to deliver lessor’s Vs interest “without cost into pipeline.” It appears the Oklahoma Supreme Court made a distinction between a gathering system and the pipeline the gathering system tapped into.

Oklahoma law on the deductions at issue here appears to follow Kansas law: Compression and other expenses necessary to make the product marketable are not deductible, but transportation costs are deductible where the sale occurs off the lease premises. The district court, by adopting Stemberger’s proposed findings of fact and conclusions of law, attempted to follow Oklahoma law but misconstrued it. Oklahoma law does permit deductions for transportation expenses where there is no market at the well and the gas must be transported to a distant market. Johnson, 475 P.2d 396.

TEXAS

Marathon argues that in Texas, post-production expenses are borne proportionately between the lessee and the lessor. Marathon relies primarily on Parker v. TXO Production Corp., 716 S.W.2d 644 (Tex. App. 1986), and Martin v. Glass, 571 F. Supp. 1406 (N.D. Tex. 1983), aff’d 736 F.2d 1524 (5th Cir. 1984). The Parker court distinguished between the deductibility of production and post-production costs. Texas Oil and Gas Corporation (Texas) sold gas it produced under a lease to its wholly owned subsidiary, Delhi Gas Pipeline Corporation (Delhi). Delhi constructed a pipeline to carry the gas to market. Texas eventually conveyed its interest as operator of the wells to TXO, another of its wholly owned subsidiaries. Delhi installed compressors to better deliver the gas from the wells into Delhi’s pipeline system, and Delhi reduced the amount paid to TXO for the gas by 5% for a compression charge. TXO in turn paid royalties on only the reduced price it received from Delhi for the gas. Parker, 716 S.W.2d at 645-46. The court found the sale of gas by Texas to its subsidiary to be suspect but then held that there was no breach of the implied covenant to market. 716 S.W.2d at 646.

However, TXO also compressed the gas at the well site independent of the compression done by Delhi, and the court found that TXO’s compression was a production cost rather than a post-production cost. The court stated:

“Production costs are the expenses incurred in exploring for mineral substances and in bringing them to the surface. Absent an express term to the contrary in the lease, these costs are not chargeable to the non-operating royalty interest. Costs incurred after production of the gas or minerals are normally proportionately borne by both the operator and the royalty interest owners. [Citation omitted.] These ‘subsequent to production’ costs include the expenses of compressing gas to make it deliverable into a purchaser’s pipeline.” 716 S.W.2d at 648.

TXO’s compression at the well site was done to increase production from the wells rather than only to enable the gas to be delivered into Delhi’s pipeline system. The compression by TXO, therefore, was held to be a production cost rather than a post-production cost, and TXO’s compression expense was not to be shared by the lessor. 716 S.W.2d at 648.

The Parker court discussed Martin v. Glass, 571 F. Supp. 1406. In Martin, the lessee installed a compressor to move gas from a producing well to a nearby gathering line for marketing because the wellhead pressure was insufficient to cause the gas to flow to the gathering line. The lessee then deducted reasonable compression charges from the royalties. 571 F. Supp. at 1409. The court held that the compression charges were properly deductible from the nonoperating royalty and overriding royalty interests. Various royalty clauses were involved, but the court held that under each clause the price was to be fixed at the wellhead. The court stated:

“Under the law of Texas, gas is ‘produced’ when it is severed from the land at tire wellhead. [Citation omitted.] The facts established that ‘production’ of gas had been obtained from two wells on the Glass-Martin lease. (There was sufficient pressure to bring die gas to the wellhead or mouth of die well.) There was no evidence introduced to the contrary. In fact the parties stipulated that ‘at all times material to the suit, the Defendant [lessee] has had two productive gas wells, on die Glass-Martin lease.’ [Citation omitted.] Therefore, tiiis is sufficient to hold die nonoperating interests liable for their proportionate share of compression costs, as such costs were incurred subsequent to production.
“The parties stipulated that there was insufficient pressure at the wellhead to enable the gas to enter the purchaser’s gadiering line without compression. The gas was useless and had no market value at the wellhead unless, and until, it could be moved into die gathering line. Accordingly, diere was no market for the gas ‘at the well.’ In order to market the gas, it first had to be compressed. . . . There existed no purchaser, or market, for the gas as it existed in die wellhead because of its low pressure. Thus, .compression being required to market die gas, said charges were post-production costs and as such were properly deductible from nonoperating interests.” 571 F. Supp. at 1415-16.

In holding that the compression costs charged by TXO were not deductible (though those charged by Delhi were deductible), the Parker court distinguished Martin:

“Whereas the operator’s compression in Martin was necessary to deliver die gas into the purchaser’s gathering line, and not to actually bring die gas to the moutii of the well, a different situation existed in the case at bar. . . . [T]he reason for TXO’s installing the compressors was to increase production from the wells. TXO point to no evidence in die record to sustain the trial court’s finding that TXO compressed the gas only in order to enable it to be delivered into Delhi’s pipeline system; apparentiy, that was die purpose of Delhi’s five percent compression charge.” Parker, 716 S.W.2d at 648.

Based on Martin and Parker, the law in Texas is well established: Post-production expenses are borne proportionately by the lessor and the lessee, while the lessee alone bears the costs of production. If anything, the deductions allowable in Texas are broader than those allowable in Kansas, as Kansas does not permit deductions for compression costs. Under the analysis of Parker, the costs of transporting a marketable product to a distant market are post-production expenses. Therefore, transportation costs are deductible from royalties under Texas law.

REASONABLENESS OF DEDUCTIONS

In light of the district court’s finding that the deductions here were improper, the district court made no finding as to whether the deductions were reasonable. However, the district court expressed concern that “[t]he defendant’s position that it owns the improvements and may use them for its other business purposes (transporting gas from other leases) without compensating the royalty owner further complicates the situation.”

Marathon argues that its deductions were reasonable. Marathon points out that it recovered less than the lessors’ proportionate share of the costs and expenses even though the lessors benefitted from a reduced transportation fee and a higher purchase price. Marathon stresses that the district court implied that the deductions were reasonable when it indicated that it was not implying that Marathon was “guilty of improper financial creativity.”

Stemberger, conversely, reasons that Marathon’s deductions were not reasonable because they included such things as abstracting expenses, legal expenses, trucking expenses for transporting pipe to the location, meals for the supervisor, grass seed used to reseed the rights-of-way, etc. Most of these, if not all, would appear to be legitimate expenses in building a pipeline.

Transportation expenses may properly be deducted from royalties where royalties are payable based on market price at the well and where there is no market at the well and transportation to a distant market is necessary. However, the deductions must be reasonable. In Scott v. Steinberger, 113 Kan. at 68, this court noted the expenses associated with the pipeline constructed by the lessee: Construction cost was $61,680, rental value was $15,000 per year, operating expenses were $10,800 per year, and taxes on the pipelines were $5,100 per year. The district court found that the reasonable transportation charge was 7 cents per MCF. However, there is no discussion as to how that figure was calculated or whether it factored in the capital expenses of constructing the line. In Matzen v. Hugoton Production Co., 182 Kan. 456, 464-65, 321 P.2d 576 (1958), this court held that where expenses incurred in transportation and preparing gas for market were deductible from proceeds from the sale of gas, maintenance, depreciation, and ad valorem and other direct taxes were deductible but federal and state income tax expenses were not.

This case turns on the fact that the royalty was to be paid based on “market price at the well” and the gas was marketable at the well, but there was no market at the well. The parties in this case dispute Marathon’s deduction of transportation expenses, but there has been no evidence or finding as to what the market price at the well was. Because sale occurred away from the well or the lease premises, we assume that royalties were paid based on the market price at a distant market rather than market price at the well. Amicus API seems to recognize this. API suggests that this court should remand the case to the district court “to determine the ‘market price at the well’ by determining the reasonable cost to transport the gas from the wellhead to a point where it could be sold off the lease under circumstances where no market existed at the well and the lessee had to build its own connecting pipeline.”

Marathon disagrees with API and argues that remand is not appropriate because the parties have not requested it and because the only evidence presented was that the amount deducted was reasonable. Marathon also stresses that plaintiffs have not disputed the price actually received for the gas at the market off the lease.

The trial court has not ruled on the reasonableness of the method used by Marathon’s predecessor to calculate these deductions. We remand this issue to the trial court for that determination.

CERTIFYING THE CLASS

K.S.A. 60-223(a) permits an action to be maintained as a class action

“only if (1) the class is so numerous that joinder of all members is impracticable, (2) there are questions of law or fact common to the class, (3) the claims or defenses of the representative parties are typical of the claims or defenses of the class, and (4) the representative parties will fairly and adequately protect the interests of the class.”

K.S.A. 60-223(c)(3)(B) permits the trial court to divide the class into subclasses, with each subclass treated as a class.

The trial court certified this action as a class action and created subclasses by state. The court held that the numerosity requirements were satisfied for claims arising in Kansas, Oklahoma, Texas, and Louisiana, but not for claims arising in Colorado and Utah. The claims arising in Kansas involve 19 wells and 38 royalty owners. Evidence at trial revealed that the Oklahoma claims involve 16 wells and at least 69 royalty and overriding royalty owners, the Texas claims involve 29 wells and at least 80 royalty and overriding royalty owners, the Louisiana claims involve 1 well and at least 55 royalty and overriding royalty owners, the Colorado claims involve 2 wells and no more than 21 royalty and overriding royalty owners, and the Utah claims involve 2 wells and no more than 18 royalty and overriding royalty owners.

Marathon argues that the district court improperly certified this action as a class action because the plaintiff failed to satisfy her burden to show numerosity and that joinder of all interest owners was impracticable. Because the claims arising, in Kansas, the named class representative’s state, involve only 38 royalty interest owners, Marathon reasons that joinder of all owners was not impracticable. Marathon concludes that as the action was not properly maintainable as a clsss action in Kansas, the district court could not certify a subclass for any other jurisdiction. Marathon does not argue that the other prerequisites to class certification were not satisfied here.

Marathon cites Schupbach v. Continental Oil Co., 193 Kan. 401, 394 P.2d 1 (1964). In challenging deductions made to his royalties on an oil and gas lease, the plaintiff sought to maintain the action as a class action and alleged that there were 23 other royalty owners under the lease at issue. The trial court refused to permit the action to proceed as a class action, and this court held there was no error. 193 Kan. at 406-07.

Here, the district court did not err here in permitting Stemberger to maintain this action as a class action. The plaintiff class includes at least 242 members in 4 states. This satisfies the numerosity and impracticability of joinder requirements of K.S.A. 60-223(a). Moreover, the fact that the district court created subclasses does not destroy the numerosity finding here. Aside from claims arising in Colorado and Utah, which were dismissed for lack of numerosity, claims arising in Kansas have the fewest number of royalty owners: 38. This number is sufficient to show numerosity and impracticability of joinder. There is no set number of class members which must be shown to warrant maintaining the action as a class action. Joinder of all parties need not be impossible, just impracticable. See Newman v. Tualatin Development Co. Inc., 287 Or. 47, 597 P.2d 800 (1979). Assuming all Kansas plaintiffs were joined, there would be 38 separate plaintiffs and potentially as many attorneys involved in the case. This would not lend itself to efficient judicial administration. The trial court did not abuse its discretion in certifying this action as a class action and in creating subclasses.

NOTICE AND OPPORTUNITY TO OPT OUT

The district court conditionally certified the class on February 5, 1992. Following a hearing on November 25, 1992, and by journal entry filed January 22, 1993, the district court certified the class and created subclasses for the various states.

On December 17, 1992, plaintiff Stemberger filed a motion for an order concerning notice to the class members of the class action suit. Plaintiff submitted a proposed form of notice for approval by the court. Marathon responded with its own proposed form of notice. Marathon asked the court to require that notice be mailed no later than January 25, 1993, and that notice be published no later than February 1, 1993. Marathon s proposed form of notice to be mailed to class members included a request for exclusion form and stated that the form must be returned to plaintiff’s counsel postmarked on or before February 10, 1993. The trial court adopted Marathon’s proposed form, including the requirement that any exclusion request be postmarked on or before February 10, 1993.

Plaintiff’s counsel received between 90 and 100 exclusion requests which were postmarked on or before February 10, 1993. Plaintiff’s counsel received an additional seven exclusion requests which were postmarked after February 10, 1993, but before the date of trial. The claims attributable to these seven class members range from 8 cents to $685.18 and total $1,667.57. At trial, Marathon asked the court to exclude those members of the class who requested exclusion after February 10 but before trial. In its journal entry deciding the merits of plaintiffs’ action, the trial court excluded only those class members who strictly complied with the exclusion provisions.

Marathon argues that the class was not given reasonable notice of the action and opportunity to opt out. Marathon points out that Stemberger initiated this action in January 1991, but Stemberger did not seek an order concerning notice to the class until December 17, 1992. Notice was ultimately mailed on January 25, 1993, and trial was on February 25, 1993. Marathon reasons that the short period of notice here did not satisfy minimal due process requirements and was not reasonable. Marathon makes no argument that the content of the notice was inadequate or that the notice was unreasonable in any way except for the timing.

In Wortman v. Sun Oil Co., 241 Kan. 226, 755 P.2d 488 (1987), aff’d 486 U.S. 717, 100 L. Ed. 2d 243, 108 S. Ct. 2117 (1988), this court stated that minimal due process requirements must be satisfied before a district court may assert jurisdiction over a nonresident class member. The nonresident class member must be given notice and an opportunity to remove himself or herself from the class by returning an exclusion request form to the court. 241 Kan. at 230. See Phillips Petroleum Co. v. Shutts, 472 U.S. 797, 811-12, 86 L. Ed. 2d 628, 105 S. Ct. 2965 (1985). These requirements mirror the statutory requirements in Kansas. K.S.A. 60-223(c)(2) provides that in a class action of this nature,

“the court shall exclude those members who, by a date to be specified, request exclusion, unless the court finds that their inclusion is essential to the fair and efficient adjudication of the controversy and states its reasons therefor. To afford members of the class an opportunity to request exclusion, the court shall direct that reasonable notice be given to the class . . . .”

Additionally, in Wortman, 241 Kan. at 230, this court stated: “Notice to class members must be sent long before the merits of the case are adjudicated. 7B Wright, Miller & Kane, Federal Practice and Procedure: Civil 2d § 1788 (1986).”

Here, notice was mailed to class members only one month before trial. Plaintiff concedes that “perhaps additional notice might have been desirable.” However, plaintiff insists that additional notice was not required and that the notice provided was not unreasonable.

K.S.A. 60-223(c)(2) requires that “reasonable notice” be given to class members. The Wortman court stated that notice must be sent “long” before the merits of the action are adjudicated. It would seem that “minimal due process requirements” contemplate that notice should usually be given more than one month before trial. Potential class members should have the opportunity to consult with counsel before deciding whether or not to opt out of the class, and giving notice only one month before trial and requiring exclusion requests to be postmarked no more than 16 days after the notice is mailed generally does not give the potential class members such an opportunity.

It is noteworthy that only seven members of the class in this action filed untimely exclusion requests, and all seven requested exclusion prior to the date of trial. All seven had small claims. Marathon submitted no evidence that other class members attempted to opt out of the class after trial or would have requested exclusion had the notice given them more time. Although this court does not condone the giving of notice of a class action to potential class members only one month before trial, we cannot say that the notice in this case violated minimal due process requirements.

FAILURE TO EXCLUDE

K.S.A. 60-223(c)(2) requires that class members request exclusion by a date specified by the court before the court must exclude them from the class. Specifying a deadline for exclusion requests lies within the trial court’s discretion. The date specified by the district court in this case was February 10, 1993. Marathon does not argue that the district court abused its discretion in setting this date.

Marathon does argue that the trial court abused its discretion in failing to exclude class members who requested exclusion after February 10, 1993, but before the date of trial. The deadline for exclusion set by the court was only 16 days after notice was mailed to potential class members. The seven class members Marathon seeks to exclude from the class requested exclusion prior to the date of trial. Had the trial court permitted exclusion of these members, there would have been no question of abuse of discretion.

The trial court’s failure to exclude these seven class members does not automatically constitute an abuse of discretion. Marathon itself suggested the deadline of February 10, 1993, for exclusion requests in its proposed form of notice to class members. The notice given to the class members clearly specified the deadline for exclusion requests. Between 90 and 100 exclusion requests were timely submitted. Marathon has made no showing as to why these seven exclusion requests were untimely, e.g., the requests were not timely submitted because the class members received the notice only after the deadline had expired. K.S.A. 60-223(c)(2) mandates exclusion of only those class members who request exclusion by the date specified by the court. Exclusion of other members, therefore, lies within the trial court’s discretion. Marathon has not shown that the trial court’s failure to exclude members who untimely requested exclusion constituted an abuse of discretion.

The trial court is affirmed in part and reversed in part, and the case is remanded for a determination of whether the lessee’s method of calculating a share of the cost of the pipeline was reasonable and whether the items included in the calculation were reasonable and necessary.

Holmes, C. J., not participating.

Edward Larson, Judge, assigned.  