Court Opinion

ID: 9790620
Source: CourtListenerOpinion
Date Created: 2023-08-31 01:56:04.977098+00
Date Added: 2024-06-11T09:15:41.470801
License: Public Domain

The opinion of the court was delivered by
Fatzeb, J.:
This was an action to recover the landowners’ royalty from November 1, 1954, to April 30, 1955, under a producing oil and gas lease in the Hugoton Gas Field (field). The principal question presented is the amount to be paid to plaintiff lessors as royalty under the terms of the leases in effect between them and the defendant Hugoton Production Company (Hugoton) as lessee operator. A jury was waived and trial had by the court. Judgment was in favor of plaintiffs, and Hugoton has appealed from the order overruling its motion for a new trial. Plaintiffs have cross-appealed from adverse rulings and orders of the trial court.
The trial court made extensive findings of fact and conclusions of law, pertinent portions of which are summarized: Plaintiffs are the owners of 320 acres in the field in Grant County, Kansas. In 1941 Panhandle Eastern Pipe Line Company (Panhandle) acquired oil and gas leases covering a block of approximately 95,000 acres (block) in the field among which were two leases covering plaintiffs’ half section and later included in a 640-acre unitization agreement on which Hugoton now owns and operates one producing gas well. The royalty clause in each of the leases covering plaintiffs’ land read, in pertinent part, as follows:
“The lessee shall pay lessor, as royalty, one-eighth of the proceeds from the sale of the gas, as such, for gas from wells where gas only is found. . . .”
Pursuant to the two leases on plaintiffs’ land and the unitization agreement plaintiffs were entitled as royalty to one-sixteenth of the proceeds from the sale of gas produced from the well on the unit of which their leases were a part.
The discovery well in the field was drilled approximately 30 years ago and by continuous development the field was ascertained to be approximately 90 miles north and south and 60 miles east and west, *458containing roughly three million acres, with an estimated original gas reserve of thirteen trillion cubic feet. In October 1948 there were approximately 1100 producing natural gas wells and the prevailing price for the gas in the field was approximately five and one-half cents per M. c. f. based on 16.4 pounds p. s. i. a. In order that the gas might be profitably sold, it was necessary that it be transported from the wellheads to distant densely populated areas since the supply greatly exceeded the demand in the field.
In an effort to place its block of leases into production and to secure a higher price for the gas to be produced, Panhandle entered into negotiations with the Kansas Power and Light Company (power company) for the sale of gas, which resulted in the organization of Hugoton in September, 1948, for the purpose of acquiring and developing the block, and constructing necessary facilities to gather, transport, process and deliver gas to the power company.
Following Hugoton s incorporation, Panhandle assigned its undeveloped block of leases to Hugoton, which entered into a contract with the power company on October 18, 1948, to supply gas for a fifteen-year period, reserving its entire production from the block to fulfill minimum delivery commitments at a base price of $0.12 per M. c. f. for processed gas for resale, and at a base price of $0.15 a million b. t. u. for gas used by the power company to operate its power plants. Provision was made for price adjustments at five-year intervals, which resulted on November 1, 1954, in an increase of 3.65 cents per M. c. f., or a delivery price of 15.65 cents per M. c. f. for processed gas for resale, measured at 14.9 pounds. However, due to an unresolved dispute between the parties, the power company has paid Hugoton only 15.58 cents per M. c. f.
To obtain the production of gas and to comply with its contractual obligations, Hugoton promptly commenced development of the block and now has 152 producing gas wells. It constructed a gathering pipe-line system of steel pipe ranging from 4 to 24 inches in diameter having a total length of over 184 miles, which connected each gas well, including the plaintiffs’ well, so as to permit the natural gas produced to be metered at the wellhead and flow in a commingled mass to a point in the block for sale to the power company and delivery to its pipe line. Hugoton also constructed a gasoline plant for the extraction of liquid hydrocarbons and a dehydrating plant through which all the gas passed in a continuous and uninterrupted movement for delivery to the power company *459where liquid fuel by-products, viz., natural gasoline, butane and propane were extracted and processed by Hugoton after which the residue or “dry” gas was sold to the power company and delivered to its pipe line. The dehydration plant was operated on the outlet side of the gasoline plant and the power company paid Hugoton for dehydration of the gas at the rate of $.0015 cents per M. c. f. Hugoton sells all liquid fuel by-products to Warren Petroleum Company (Warren).
On October 11, 1953, Hugoton entered into a contract with Columbian Carbon Company (Columbian) whereby it agreed to sell certain quantities of raw natural gas as might be available after its contractual obligations to the power company had been fulfilled. The price agreed upon was 13.4 cents per M. c. f. measured at 14.65 pounds, and delivery was to be made at a point distant from the wellheads, unprocessed. Except for such gas as was used in its plant operations, or unavoidably lost, the gas produced by Hugoton from the block was delivered to the power company as processed gas for resale; to Columbian as raw natural gas; or, to Warren in the form of liquid hydrocarbons.
Hugoton made royalty payments to plaintiffs at the rate of $0.11 per M. c. f. based upon the minimum wellhead price order of the State Corporation Commission effective January 1, 1954 (docket No. 44,079-C [C-3216]), which, under its authority to prevent waste and conserve natural gas, fixed a minimum wellhead price as a condition precedent for withdrawal of the gas from the field of not less than $0.11 per M. c. f. measured at 14.65 pounds, the validity of which was sustained by this court in Cities Service Gas Co. v. State Corporation Commission, 180 Kan. 454, 304 P. 2d 528, reversed 355 U. S. 391, 2 L. ed. 2d 355, 78 S. Ct. 381.
No dispute exists as to the amount of gas produced. Both parties here assert that Hugoton’s royalty obligation is to be determined at the wellhead rather than at the point of sale and delivery off the lease, and further, that there is no market price at the wellhead for the gas taken by Hugoton. Thus, a known amount of gas is produced and sold by Plugoton under contracts calling for a definite price; hence, there remains but one element necessary to determine proceeds at the wellhead, i. e., the price to be paid for the gas at that point. The amount due the plaintiffs as royalty is then only a matter of calculation.
The trial court found, among other things, that at the time the leases covering plaintiffs’ land were executed it was the established *460practice and custom in the gas production industry to measure, determine the price, and pay gas royalty at the wellhead on all gas produced in the field upon a pressure basis of 16.4 pounds, which was later changed by the State Corporation Commission to a pressure basis of 14.65 pounds, and concluded that to determine proceeds at the wellhead per M. c. f. it was necessary to subtract from gross proceeds derived from Hugoton s total sales proper chargeable operating expenses incurred in procuring such proceeds, including gathering, processing and dehydrating, and divide the net proceeds by total volume of gas produced (M. c. f.) — the quotient being the wellhead price per M. c. f. of gas produced. The method used by the trial court is referred to by the parties as the “proceeds-less-expenses” formula, and in applying it the trial court used Hugoton’s accounting period for the calendar year 1955 since its operations were carried out on an annual basis, which included high, medium and low production periods during each year. By this formula it determined “proceeds at the wellhead per M. c. f.” of $0.1530, which figure was immediately followed by an item entitled “fair proprietary rate to Def. on royalty gas” of $0,003, and immediately thereafter was an item entitled “fair value of gas” of $0.15. The latter figure was used by the trial court as wellhead proceeds per M. c. f. to determine royalty payments to plaintiffs for gas produced from their land.
At a pretrial conference and during the trial Hugoton offered to confess judgment on the basis of a proceeds rate at the wellhead of 12.8392 cents per M. c. f. Both parties concede the difference between the proceeds rate upon which Hugoton offered to confess judgment and that found by the trial court of $0.15 per M. c. f. lies in the trial court’s failure to consider any part of Hugoton’s federal and state income tax expenses in determining total operating expenses to be deducted from gross proceeds. That is the principal point in controversy, and Hugoton specifies that the trial court erred in determining costs and charges incurred in its operation for 1955 with respect to its function of gathering, processing and marketing the gas, by refusing to allow as a charge and expense any part of its federal and state income taxes incurred as a result of its operation.
In addition to Hugoton’s specification of error, the parties are disagreed as to the method by which Hugoton’s royalty obligation under the terms of the lease should be determined.
*461Plaintiffs pleaded they were entitled to recover as royalty one-sixteenth of the proceeds from the sale of gas by reason of the production and sale by Hugoton, but they contended in the court below they were entitled to prove fair value of the gas at the wellhead by any competent evidence, and undertook to prove that value by three different methods. They argue here that in cases like the present, where there are no sales at the wellhead and thus no proceeds at that point, courts generally have applied the one-eighth royalty to market value at the wellhead if there is a market value at that point, or fair value where there is no market value, which, they assert, is a question of fact to be established by any evidence having probative value on the subject, including opinion evidence and evidence of proceeds less reasonable expense of transportation and processing, and cite Scott v. Steinberger, 113 Kan. 67, 213 Pac. 646; Cimarron Utilities Co. v. Safranko, 187 Okla. 86, 101 P. 2d 258; Kretni Development Co. v. Consolidated Oil Corp., 74 F. 2d 497, and Sartor v. Arkansas Gas Corp., 321 U. S. 620, 88 L. Ed. 967, 64 S. Ct. 724. They contend any errors the trial court may have committed in computing proceeds-less-expenses, whether in favor of Hugoton or of plaintiffs, will not affect the result nor justify reversal upon either the appeal or the cross-appeal since Hugoton’s income tax expenses are not competent evidence in any event to prove fair value of the gas at the wellhead.
Hugoton contends the “proceeds-less-expenses” formula is the exclusive means by which plaintiffs’ royalty can be ascertained and that where, as here, a gas lease provides for royalty based on “proceeds” and the natural gas produced is sold off the lease, the proceeds by which the lessee’s royalty obligation is to be measured are ascertained by deducting from gross proceeds the expenses incurred in bringing the gas to, and preparing it for, the market, and rely upon Scott v. Steinberger, supra; Voshell v. Indian Territory Illuminating Oil Co., 137 Kan. 160, 19 P. 2d 456; Molter v. Lewis, 156 Kan. 544, 134 P. 2d 404; Warfield Natural Gas Co. v. Allen, 261 Ky. 840, 88 S. W. 2d 989; Wall v. United Gas Public Service Co., 178 La. 907, 152 So. 561, and Reed v. Hackworth (Ky., 1956), 287 S. W. 2d 912.
Hugoton further contends that although plaintiffs’ leases in no way obligated it to invest in or assume the operations of its system, plaintiffs’ profit from the price and long-term market advantages is a direct consequence of its investment in and operation of its *462system; that those operations produced net proceeds at the well materially higher than would have been produced without gathering and processing; that plaintiffs must bear their share of all expenses resulting from the operation of its integrated gathering and processing system, and that income taxes are an ordinary and necessary expense of those operations and an expense which must be considered in determining the royalty rate at plaintiffs’ well. In support of this contention Hugoton cites Homes v. James Buckley & Co., 165 La. 874, 116 So. 218; Neeson v. Sangamon Mining Co., 316 Ill. 397, 147 N. E. 369; Fleischer v. Pelton Steel Co., 183 Wis. 451, 198 N. W. 444; Saulsbury Oil Co. v. Phillips Petroleum Co., 142 F. 2d 27, certiorari denied 323 U. S. 727, 89 L. Ed. 584, 65 S. Ct. 62; International Hotel Co. v. Libbey, 158 F. 2d 717, and Allis-Chalmers Mfg. Co. v. United States, 165 F. 2d 495.
Plaintiffs’ leases entitled them as royalty to “one-eighth (one-sixteenth under the unitization agreement) of the proceeds from the sale of the gas, as such,” produced under the leases, and Hugoton had the exclusive right to produce and market the gas. It was as much Hugoton’s duty to find a market on the leased premises without cost to the plaintiffs as it was to find and produce the gas (Howerton v. Gas Co., 81 Kan. 553, 106 Pac. 47; Collins v. Oil & Gas Co., 85 Kan. 483, 118 Pac. 54), 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 plaintiffs’ 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 the leases for sale and delivery to a purchaser for ultimate consumption. Sale of gas at the wellhead was not made a condition of proceeds and payment of royalty; on the contrary, Hugoton’s royalty obligation was fixed wherever the sale of the gas occurred and regardless of its character, viz. natural, processed or liquid hydro*463carbons; all produced aggregate proceeds in which the plaintiffs were entitled to participate.
The language “proceeds from the sale of the gas, as such,” must be construed from the context of the 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 the 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. Thus, proceeds from the sale of gas, wherever and however ultimately sold, is the measure of plaintiffs’ royalty, less reasonable expenses incurred in its gathering, transporting, processing and marketing.
The Kansas authorities (Scott v. Steinberger, supra; Voshell v. Indian Territory Illuminating Oil Co., supra; Molter v. Lewis, supra) cited by both parties do not sustain either of their contentions, since the royalty provisions there involved provided for delivery of a specified portion of the oil or gas produced. Here, we are concerned with leases which provide for payment as royalty of a stipulated percentage of the proceeds derived from the sale of the gas. Indeed, in Molter v. Lewis, supra, in referring to Scott v. Steinberger, supra, the court said:
“The Scott case has been followed in: Kretni Development Co. v. Consolidated Oil Corp, 74 F. 2d 497, 500; Wall v. United Gas Public Service Co., 178 La. 908, 152 So. 561, and accords with the holding in Rains v. Kentucky Oil Co., 200 Ky. 480, 255 S. W. 121. It was distinguished in Ladd v. Upham, 58 S. W., 2d 1037, affirmed on appeal, 128 Tex. 14, 95 S. W. 2d 365, where the lease provided the lessor should have a fractional share 'of the proceeds from the sale of gas’ from the leased premises.
“See, also, United States v. Stanolind Crude Oil Purchasing Co., 113 F. 2d 194, where is pointed out (p. 198) the distinction between a lease by which the lessor has as his own property a fractional share of the oil produced, and those leases by which the lessor receives a stated share of the proceeds’ of all oil produced.” (l. c. 546, 547.)
The authorities from other jurisdictions cited by plaintiffs are equally distinguishable. In Cimarron Utilities Co. v. Safranko, supra, the royalty clause was for “one-eighth at the market price for gas used off the premises.” In Sartor v. Arkansas Gas Corp., supra, it was for “one-eighth of the value of such gas calculated at the rate of market price.” The royalty clause in Kretni Development Co. v. Consolidated Oil Corp., supra, was similar to the clause here involved. Plaintiffs’ argument based on that case is that the *464opinion uses the terms “proceeds,” “fair market value” and “market value” interchangeably. The court there was not concerned with the distinction between those terms because their meanings were not pertinent to the controversy. The issue there was the point at which the royalty was to be determined. None of those cases clearly support plaintiffs’ contention.
In Phillips Petroleum Co. v. Johnson, 155 F. 2d 185, the royalty clause reads:
“ ‘. . . If any well on said premises shall produce natural gas in paying quantities, and such natural gas is used off the premises or marketed by lessee, then lessor shall be paid at the rate of one-eighth of the net proceeds derived from sale of gas at the mouth of the well.’ ”
In making a distinction between “proceeds” and “value,” the opinion indicates why and when these tests should be applied. The court further stated:
“The law often resorts to ‘fair value’ or ‘fair market value,’ when ‘market price’ is stipulated and there is no market, or when ‘proceeds’ are stipulated and there is no sale. This is because the contract evidently intends payment shall be made, and value is the nearest approach possible under the circumstances to the measure of payment contracted for. In so far as this gas was ‘used’ there can be no ‘net proceeds derived at the mouth of the well’ and fair value must be resorted to. In so far as the gas was marketed’ we think the stipulation for a share of the ‘net proceeds derived’ ought to be enforced, effect being given to the words ‘net at the mouth of the well’ by allowing as expense the cost of transporting, separating, and marketing. This lessor did not consent to be left to the uncertainties of ‘fair value,’ or even ‘market price’, as to the gas but was willing to take one-eighth of what the lessee sold it for, relying on tile lessee’s self-interest to secure a good sale. . . .” (pp. 188, 198.)
Having determined that plaintiffs’ royalty is to be measured by proceeds from the sale of gas less reasonable expenses of transporting and preparing it for market, is Hugoton’s income tax an expense to be deducted from gross proceeds? The trial court included maintenance, depreciation, and ad valorem and other direct taxes as deductible expenses, but disallowed Hugoton’s federal and state income tax expense in its entirety.
Hugoton’s expert evidence was that income tax constitutes an ordinary and necessary expense of doing business and an expense of Hugoton’s business operation which should be deducted in determining proceeds from gas sales. However, it was established that for its own internal cost accounting purposes, to ascertain net profits from its gasoline processing and dehydration operation, Hugoton allocated the expense of all taxes, except income tax. Plaintiffs’ ex*465pert evidence established that from an accounting standpoint, income tax is a sharing of profits, not a cost; that in cost accounting, income tax is never used as a factor in determining cost of operation, cost of sales nor of any other item. The trial court found against Hugoton and that finding, upon conflicting evidence, is not reviewable by this court (In re Estate of Osborn, 179 Kan. 365, 295 P. 2d 615; Dryden v. Rogers, 181 Kan. 154, 309 P. 2d 409).
Generally speaking, income tax may properly be treated as an expense or cost in financial statements of companies that make a showing of current tax payment or accrual in their financial statements, but we are not concerned with items of expense which Hugoton may or may not include in its annual financial statements to its stockholders, nor of profits upon which it is required to pay federal and state income taxes. Our task is to ascertain costs and expenses properly deductible from proceeds to determine the amount due plaintiffs as royalty, which, we think, are those relating directly to the function of gathering, processing and marketing the gas produced. We search for proceeds at the wellhead — not for Hugoton’s financial status nor for profits to be shared. Whether Hugoton’s income tax is large or small, it is levied upon net profits, and has no relation to actual costs and expenses of gathering and preparing the gas for market. We need look only to Hugoton’s own records and accounting practices to convince us of the soundness of this view. What could be more significant than Hugoton’s own cost accounting records, where, in determining gathering, processing and marketing costs, it allocated to that operation all proper expenses and taxes, except income taxes! It may not exclude income tax expense for its own convenience in determining net revenue from its gathering and processing operation and then charge the plaintiffs with that expense in determining proceeds at the wellhead.
We think it unnecessary to review each of the cases cited by Hugoton. Suffice it to say they have been studied, and we are of the opinion they do not control the question presented. The only case relied upon by Hugoton even remotely involving the petroleum industry is Saulsbury Oil Co. v. Phillips Petroleum Co., supra. That case did not involve any question with respect to proceeds at the wellhead from the sale of gas nor did it involve an oil and gas lease. The opinion construed a gas purchase contract for the sale of casinghead gas. While the court permitted the buyer in accounting to the seller for a certain percentage of net proceeds, defined in the contract as gross proceeds less any cost of boosting and transporting *466necessary to market gas, to deduct federal income taxes as costs in determining net proceeds, the authorities relied upon in the opinion were utility rate cases where it was held that in determining a fair return to the utility, federal income taxes were a burden on the return and were properly considered costs, since the stockholders who were entitled to a fair return on their investment received only what was left after payment of taxes. The court apparently overlooked the fact that utility rate cases are in a category by themselves and that income taxes must be taken into account to determine rate of return to stockholders (Barnes, Economics of Public Utility Regulation [F. S. Crofts & Co. 1942] p. 622; Power Comm’n v. Hope Gas Co., 320 U. S. 591, 88 L. Ed. 333, 64 S. Ct. 281; Galveston Elec. Co. v. Galveston, 258 U. S. 388, 66 L. Ed. 678, 42 S. Ct. 351.)
Since proceeds, not net profits, are what is sought, we are of the opinion that the trial court did not err in excluding in its entirety Hugoton s 1955 income tax as an item of deductible expense in determining proceeds per M. c. f. at the wellhead.
Coming now to the cross-appeal, plaintiffs contend the trial court erred in applying the “proceeds-less-expenses” formula to Hugoton s accounting period for the calendar year 1955 instead of to its monthly accounts for the period involved. Re that as it may, Hugo-ton’s operations under the leases are carried out on an annual basis and offer, as the trial court found, the only proper accounting experience for the determination of royalty to be paid during the period involved, and it would seem impracticable under the circumstances presented and for the purposes of this action to require Hugoton to account on a monthly basis. While we do not give general approval to the use of an accounting period of one year to determine royalty under plaintiff’s leases, we cannot say in the instant case the trial court used a period which was unreasonable so as to constitute an abuse of discretion.
Plaintiffs argue that the trial court erred in allowing Hugoton a “proprietary return” of $90,638, or $0,003 per M. c. f. on the enhanced value of gas which arose by virtue of its gathering and processing operation, and that such return is a profit and not an expense.
At the outset, it is noted the trial court’s figure of $90,638 is the value of the fuel used and the gas shrinkage in the processing operation, which it disallowed as an expense. The trial court found that had Hugoton purchased from another company the equivalent of the gas used or lost, the value would be properly deductible as an *467expense of processing, however, it concluded that since Hugoton used its own gas, which, had it not done so, would have been available for sale to produce proceeds, the value was not properly chargeable as an expense, but that Hugoton was entitled to a fair proprietary return on the enhanced value of the royalty gas. Whether Hugoton chose to. use its own gas or go upon the market and purchase the equivalent from another company makes no difference — the result is the same. Whatever it was called, the return allowed by the trial court was apparently based on an expense of operating the processing plant, and as such, was properly allowed under the formula.
Other contentions made by the plaintiffs have been examined, but in view of the conclusions heretofore announced, it is unnecessary to discuss them.
We have thoroughly reviewed the record as presented to us, and in view of the contentions of the parties we conclude no error has been affirmatively made to appear, which would require a reversal.
The judgment is affirmed.