679 F. Supp. 1435 | W.D. Mich. | 1988
OLD KENT BANK & TRUST COMPANY, Plaintiff,
v.
AMOCO PRODUCTION COMPANY, a Delaware corporation, and Gulf Oil Corporation, a Pennsylvania corporation, Defendants.
United States District Court, W.D. Michigan, S.D.
*1436 Dale W. Rhoades, Kurt D. Hassberger, Grand Rapids, Mich., for plaintiff.
George W. Loomis, Lansing, Mich., for defendants.
OPINION
HILLMAN, Chief Judge.
On December 20, 1984, plaintiff, Old Kent Bank & Trust Company ("Old Kent"), as trustee of the Atrium Trust, filed a five count complaint against defendants, AMOCO Production Company ("AMOCO") and Gulf Oil Corporation ("Gulf") claiming deficiencies in royalty payments respecting twenty seven oil and gas wells located in Kalkaska County. The twenty seven wells aggregate 3,060 acres. Plaintiff owns a one-sixteenth non-participating royalty in some 2,155 acres of the drilling units. Pursuant to three oil and gas leases and related conveyances, defendants have the right to obtain and sell the oil available through these twenty-seven wells.
At issue in this suit is the proper characterization of gas sales by defendants to Consumers Power Company ("CPCo") and Michigan Consolidated Gas Company ("MichCon") under the provisions of the gas lease contracts between plaintiff and defendants. Neither CPCo nor MichCon are parties to the suit. According to the leases, the method of determining the royalty amount owed varies depending on whether the gas sold by defendants to the common purchasers is sold on or off the leased premises. Currently before the court are two motions for partial summary judgment: defendants' (filed August 21, 1985) and plaintiff's (filed December 1, 1986). For the reasons discussed below, defendants' motion is denied and plaintiff's motion is granted.
I. Factual Background
The facts material to the pending motions, although somewhat complicated, are not in dispute. The oil and gas leases and conveyances pursuant to which Old Kent as trustee owns a one-sixteenth non-participating royalty in the twenty-seven wells at issue in this case were executed in 1964 and 1965.[1] Under sixteen long-term purchase contracts, defendants sell most, if not all, of the gas produced from these wells to CPCo and MichCon.[2]
Products produced from these wells can be divided into three general categories: "wet" gas consisting of "dry" natural gas and suspended liquid components; injected liquids; and liquids tanked and sold as condensate or crude oil. At this point in discovery, plaintiff does not dispute the appropriateness of the royalties paid on condensate and crude oil[3] or, it appears, injected liquids. The dispute focuses on royalties paid on the wet gas stream. These are products produced in gaseous form and transported by means of a gas pipeline from the well to one of two processing plants. It should be noted however, that plaintiff's contention respecting the alleged improper calculation of royalties on the sale of the wet gas stream must be examined in light of two different sales and processing arrangements. I describe these two systems below.
A. The CPCo/MichCon Scenario
CPCo and MichCon purchase gas extracted from twenty-one of the twenty-seven wells and a portion of the gas extracted from the twenty-second pursuant to fourteen contracts negotiated between 1971 and *1437 1983.[4] Defendants Amoco and Gulf meter the gas at the well to determine volume and test it for heating value in British termal units ("Btus"). They then deliver the gas to a "wetheader system" leased and operated by the common purchasers.[5] The wetheader system is a pipeline designed to transport wet gas.
The purchase contracts specify that title to the gas passes to the common purchasers when they take delivery and before the gas is injected into the wetheader system.[6] The purchase price paid is based either on a stated amount per thousand cubic feet of wet gas with a Btu adjustment or at a price per million British thermal units ("MMBtu"). Under the former system the gas is valued at an established price per volumetric unit. However, if the heating content of the gas varies from 1000 Btus per cubic foot, the unit sales price is adjusted proportionately. Under the latter system a volumetrically measured quantity of wet gas is multiplied by the measured heating content of the gas. The unit of measurement is an MMBtu of gas sold.[7] Both of these pricing methods take account of the Btu content of preprocessed wet gas which, whatever it may be, is generally too "rich" for resale by the common purchasers. Processing is required.
In the purchase contracts defendants reserve the right to process the wet stream after delivery to achieve a gas compatible with CPCo's and MichCon's needs.[8] They also retain title to any component other than the residue gas required by the common purchasers subject to their extracting or arranging for the extraction of it.[9] CPCo and MichCon deliver the wet gas via their wetheader system to a processing plant in Kalkaska operated by various producers including defendants. After processing, CPCo and MichCon transport a less Btu-rich residue gas to their respective service areas.[10] Pursuant to the sales contract, defendants retain title to the remaining liquid hydrocarbons. Eventually defendants sell these hydrocarbons to third parties.[11]
The common purchasers are not compensated for shrinkage incurred in delivery through the wetheader to the processing plant. However, AMOCO and Gulf do compensate them for volume and Btu content lost in processing and for the value of the liquid hydrocarbons extracted from the wet gas stream.[12] The latter amount is computed according to a mathematical formula by which manufactured liquid hydrocarbons are converted from the liquid phase back to the gaseous phase and their heating value as gas determined on a per Btu basis. The price per Btu is the same as the price per Btu paid by the common purchaser under the contract when the gas is transferred into the wetheader.[13] AMOCO and Gulf calculate plaintiff's royalties on the basis of the amount received by them from CPCo and MichCon when the gas is transferred into the wetheader.[14] They do not include the amount received from the sale of the liquid hydrocarbons in that base amount. It is this omission that forms the basis of the plaintiff's claim. In other words, plaintiff argues that it should receive royalties on the amount realized by the defendants on the sale of the liquid hydrocarbons.
B. The MichCon Scenario
Pursuant to a 1970 contract with AMOCO and a 1970 contract with Gulf, MichCon purchases the balance of the gas extracted at the twenty-second well as well as that *1438 taken from the remaining five wells.[15] As with gas purchased pursuant to the fourteen contracts discussed above, title to the gas purchased by MichCon under these two contracts transfers when AMOCO and Shell deliver the gas to the common purchaser's wetheader system.[16] In these contracts, however, there is no Btu adjustment. Neither is the gas priced per MMBtu.[17] Furthermore, AMOCO and Gulf reserve the right to process the wet gas stream for recovery of natural gas liquids prior to, rather than after, purchase by and delivery to the common purchaser.[18] If AMOCO and Gulf actually undertook predelivery processing, title to the remaining liquid hydrocarbons would remain with defendants.[19] However, in the early 1970s, when these contracts were negotiated, AMOCO and Gulf did not operate the Kalkaska plant at which they process gas purchased pursuant to the CPCo/MichCon scenario.[20] Thus, an arrangement was arrived at whereby MichCon transports the unprocessed, wet gas through its wetheader system to a processing plant owned by Shell Oil Company.[21] Pursuant to the arrangement between MichCon and Shell, MichCon takes the processed residue gas and Shell retains and sells the remaining liquid hydrocarbons.[22] Under separate contracts between Shell and AMOCO and Shell and Gulf, Shell "reimburses" AMOCO and Gulf for the value of these hydrocarbons.[23] Under this scenario, AMOCO and Gulf calculate the amount on which plaintiff's royalties are based by adding the price received from Shell for the liquid hydrocarbons to the gross proceeds received from MichCon when the gas is transferred to the wetheader system.[24]
C. Contentions of the Parties
All of the oil and gas leases governing both the CPCo and MichCon fact situations contain the following provision governing lessor royalties:
3. LESSOR'S ROYALTY. Lessee covenants and agrees to pay Lessor as royalty on all oil, condensate, gas, asphalt and other minerals and substances, produced, saved and sold from the Premises one-eighth of the gross proceeds, less all severance and other applicable taxes, received from the sale thereof at the mouth of the well, or,
if not sold at the mouth of the well but sold or used off the Premises or for the manufacture of gasoline or any other product, then one-eighth of the amount realized at the mouth of the well from such sales, less all severance and other applicable taxes; except that the royalty on sulphur shall be 50 cents per long ton marketed; and except that no royalty shall be paid on gas or liquids when the Premises are being used for the withdrawal of storage gas or liquids as provided in Paragraph 9 hereof.
Plaintiff currently receives royalties calculated under the first half of this provision. Characterizing the gas they deliver to MichCon and CPCo as having been "sold at the mouth of the well," AMOCO and Gulf calculate plaintiff's royalties on the basis of the gross proceeds received from MichCon and CPCo. However, plaintiff contends that royalties in both the CPCo/MichCon and MichCon scenarios should be calculated pursuant to the latter half of the provision. In other words, plaintiff argues that the wet gas stream at issue in each contract is sold "off the premises" thus requiring a royalty payment of *1439 one-eighth of the "amount realized at the mouth of the well" as distinguished from the "gross proceeds" received from the common purchasers.
According to plaintiff, the amount realized at the mouth of the well should be determined by the application of a "proceeds less-expenses" calculation. Under this approach royalties would be calculated by combining the total amount received by the defendants for the residue gas plus the total amount received by the defendants for the hydrocarbon liquid produced and sold after processing of the wet gas stream, reduced by reasonable processing costs. Thus, with respect to the CPCo scenario, plaintiffs argue that defendants should add the amount received from CPCo and MichCon minus the rebate after processing, to the amount received on the sale of the liquid hydrocarbons and from that amount subtract the costs of processing.
With respect to the MichCon scenario, plaintiff's allegations are less than clear particularly as argued in the brief filed December 1, 1985. As far as I am able to determine, plaintiff essentially argues that defendants, although they refuse to admit it, correctly include the proceeds from the sale of both the residue gas and the liquid hydrocarbons to arrive at the base figure on which royalties are to be calculated under the "off the premises" clause. Plaintiff's complaint against defendant appears to come down to an assertion that defendants accept too small an amount from Shell for the liquid hydrocarbons and consequently violate their implied duty to market pursuant to Greenshields v. Warren Petroleum Corp., 248 F.2d 61 (10th Cir.), cert. denied, 355 U.S. 907, 78 S. Ct. 334, 2 L. Ed. 2d 262 (1957) and Amoco Production Co. v. First Baptist Church of Pyote, 579 S.W.2d 280 (Tex.App.Ct.1979), writ ref'd n.r.e., 611 S.W.2d 610 (Tex.1980). Plaintiff's reasoning rests largely on the fact that the contracts between Shell and AMOCO and Shell and Gulf have not been renegotiated since they were first executed in 1974. Plaintiff argues that this is indicative of the failure of AMOCO and Gulf to enter into good faith, arms length negotiations with Shell for the value of the processed liquid hydrocarbons. There remains a question of fact in this regard. However, it is not material to determining whether AMOCO and Gulf sell the gas they produce on or off the premises.
In contrast, the defendants contend that under the CPCo/MichCon scenario, the entire wet gas stream is sold to CPCo and MichCon "at the well." Thus, defendants argue, royalties are properly calculated on the amount received from the common purchasers when the gas is transferred into the wet header system. In the alternative, they argue that even if the gas is characterized as having been sold off the premises, the royalties were correctly calculated because the phrase "amount realized at the mouth of the well" is defined as market value, and the amount for which AMOCO and Gulf bargained and received from the common purchasers reflects the market value of the gas at the mouth of the well.
With respect to the MichCon scenario, defendants argue that those sales were also at the mouth of the well and thus were subject to the clause requiring royalty payments on gross proceeds. Defendants further argue that in adding the amount received from Shell for the sale of the liquid hydrocarbons to the total on which royalties are calculated, they are not admitting that sale of the gas stream was off the premises. Rather, they are simply taking account of the fact that these particular sales to MichCon did not involve a Btu adjustment.
The question before the court, with respect to both scenarios, is whether under the undisputed facts, the sales by AMOCO and Gulf to MichCon and CPCo amounted to sales on or off the premises.
II. Standard of Review
On a motion for summary judgment under Federal Rule of Civil Procedure 56, the movant bears the burden of proving conclusively that there is no genuine issue of material fact and that the movant is entitled to summary judgment as a matter of law. Smith v. Hudson, 600 F.2d 60 (6th Cir.1979); Tee-Pak, Inc. v. St. Regis Paper Co., 491 F.2d 1193 (6th Cir.1974); Fed.R. *1440 Civ.P. 56(c). The court is obligated to consider all pleadings, depositions, answers to interrogatories, and admissions on file, in addition to the material specifically offered in support of the motion. Smith, supra, at 64. In determining whether there are issues of fact requiring trial, "the inferences to be drawn from the underlying facts contained in the [affidavits, attached exhibits, and depositions] must be viewed in the light most favorable to the party opposing the motion." United States v. Diebold, 369 U.S. 654, 655, 82 S. Ct. 993, 994, 8 L. Ed. 2d 176 (1962). A court may not resolve disputed questions of fact in a summary judgment decision and if a disputed question of material fact remains, the motion should be denied, and the case should proceed to trial. United States v. Articles of Device, 527 F.2d 1008, 1011 (6th Cir. 1976).
III. Discussion
A. Analysis of "At the Mouth of the Well" and "Off the Premises"
Resolution of this dispute requires an analysis of the phrases "at the mouth of the well" and "off the premises." Few courts have grappled with these terms and those that have generally faced fact situations that varied in some significant aspect from the situation presented under either the CPCo/MichCon or MichCon scenario. Nevertheless, after a close review of the existing cases, and keeping in mind the basic doctrine of oil and gas law that mineral leases are to be construed against the lessee (defendants in this case) and in favor of the lessor (plaintiff here), Piney Woods Country Life School v. Shell Oil Co, 726 F.2d 225 (5th Cir.), cert. denied, 471 U.S. 1005, 105 S. Ct. 1868, 85 L. Ed. 2d 161 (1985) (citations omitted), I am satisfied that the gas purchases under the CPCo/MichCon scenario, while in form appearing to be at the well, are, by legal definition, sales off the premises. I am also satisfied that the sales under the MichCon scenario are sales off the premises.
Of the cases dealing with this issue, Piney Woods, supra, provides the greatest guidance. In that case the producer-defendant, Shell Oil, extracted sour gas containing "hydrogen sulfide" from a well leased from the plaintiff. Although title to the gas passed to the common purchasers in the field when the gas was still sour, Shell transported the gas to its processing plant and there separated it into sweet gas and sulphur. Id. at 229. Only then did the buyers take the sweet gas paying "a price commensurate with the value of the sweet gas at the time the contract was made." Id. at 231.
The method used to determine royalties depended on whether the gas was characterized as having been sold "at the well" or "used off" the premises on which the oil wells were located. Plaintiff argued that the gas was used off the premises. Defendant maintained that it was sold at the well. The court concluded that the labels "sold at the well" and "sold off the lease" "distinguish between gas sold in the form in which it emerges from the well, and gas to which value is added by transportation away from the well, and gas to which value is added by transportation away from the well or by processing after the gas is produced." Id. at 231. According to the court,
"At the well" therefore describes not only location but quality as well. Market value at the well means market value before processing and transportation, and gas is sold at the well if the price paid is consideration for the gas as produced but not for processing and transportation.
Id. The court concluded that while title to the sour gas "sold" to buyer passed in the field where the gas was metered, this was of little significance as the buyer "effectively pay[ed] only for the amount of sweet gas delivered at Yazoo City [after processing], and [paid] a price commensurate with the value of sweet gas at the time the contract was made." Id.
As in Piney Woods, the parties to the purchase contracts under the CPCo/MichCon scenario system meter the wet gas stream at the well where title passes to the buyer. Likewise, in Piney Woods and under the CPCo/MichCon scenario the price that the purchaser ultimately pays for the *1441 desired gas is established at the time the contract is entered into. It is true that in the instant case CPCo and MichCon pay defendants when the gas is delivered to the wetheader system, whereas in Piney Woods payment was not made until delivery of the sweet gas. However, the after processing rebate provided CPCo and MichCon by AMOCO and Gulf results in virtually the same pricing arrangement as in Piney Woods. In Piney Woods the purchaser did not pay for the sour gas and in this case the purchasers do not pay for the liquid hydrocarbons. In both cases the purchasers bargain and pay for only the processed residue gas that they ultimately remove from the sellers' processing plant. In Piney Woods the purchaser knows when it contracts that it is establishing a price per unit of sweet gas, the final amount paid to be determined when the gas is measured after processing. Under the CPCo/MichCon scenario, the common purchasers contract for a price per Btu or a volume price adjusted for Btu content and while they pay for the entire wet gas stream at the well, they know that the wet gas stream is subject to processing by the defendants and that defendants reserve title to liquified hydrocarbons removed from the wet gas stream. They also know that they will receive a rebate for Btus lost in processing and retained in the form of liquid hydrocarbons and that the rebate will be calculated at the same cost per Btu established in the sales contracts.
Thus, the only difference between the payment arrangement in Piney Woods and that used in the CPCo/MichCon scenario, is the order in which the exchange of goods (the gas), services (the processing), and payment takes place. In essence, the transactions are identical. The parties bargain once establishing a price for processed residue gas. The buyers do not purchase the right to any other gas components remaining after processing. Had the common purchasers in the instant case bargained for the sale of the wet gas stream, and bargained again for AMOCO's and Gulf's processing services, then taken all of the resulting gas components, liquified hydrocarbons as well as residue gas, I might have concluded that the gas was sold at the well for the first transaction would have reflected the value of the entire wet stream prior to processing. The purchasers would have paid for unprocessed liquid hydrocarbons as well as unprocessed residue gas and the cost of processing would have been established through separate negotiations. In other words, they would have paid for the entire wet gas stream in its unprocessed state.
With respect to the MichCon scenario, I must also conclude that AMOCO and Gulf are selling processed gas as that term is defined in Piney Woods. Under the CPCo/MichCon scenario defendants reserve the right to process the wet gas stream after transfer of title. In contrast, under the MichCon scenario, the purchase contracts give defendants the right to process the gas stream prior to delivery. Thus, the contracts explicitly contemplate a transfer of title of the processed residue gas only. Defendants ignore this portion of the contract.
In fact, defendants do not exercise their right to undertake predelivery processing. Instead, MichCon delivers the wet gas stream to a processing plant owned by Shell Oil. According to defendants, "[a]fter purchase of the wet gas stream at the well, MichCon, or its processor, Shell, was entitled to manufacture and market the natural gas liquids.... The subsequent manufacturing and marketing of such liquids did not vitiate the prior sale at the well of the entire wet gas stream." (Defendants' Brief, Jan. 20, 1987, at 16.) The underlying assumption of this characterization of the processing arrangement is that since defendants failed to exercise their presale right to process, title to the entire wet gas stream passed to MichCon. The parties behavior directly contradicts this conclusion.
If title to the entire stream of unprocessed gas actually passed to the common purchasers at the wellhead, why does Shell pay AMOCO and Gulf for the value of the liquid hydrocarbons that it retains after processing? Why aren't the common purchasers paid for that portion of the wet gas *1442 stream that Shell keeps and sells? Gulf and AMOCO explain that they recognized "that the price without Btu adjustment paid by MichCon for the wet gas stream failed to recognize the heating value of the gas sold at the wellhead." (Affidavit of Mary A. Smith, Nov. 20, 1987, ¶ 6; Anderson III, ¶ 6.) "Accordingly," they entered into the "reimbursement" agreements with Shell. This explanation supports the conclusion that neither AMOCO nor Gulf believes that it sold the entire wet gas stream at the well. Although neither defendant retains the right to process the wet gas after delivery, they nevertheless negotiate with and receive payment from Shell for the liquid hydrocarbons it obtains during processing. It appears that defendants offer nothing to Shell in exchange for forty-five percent of the value of each liquid hydrocarbon other than the hydrocarbons. It would seem that defendants sell the liquid hydrocarbons to Shell.
Looking at all the inferences that can be drawn from the filed contracts and affidavits in the light most favorable to the defendants, I am satisfied that in neither the CPCo/MichCon scenario nor the MichCon scenario did defendants ever intend to transfer the entire wet gas stream to MichCon. Under Piney Woods, all that they sold at the well was processed residue gas. Furthermore, I do not find persuasive any of the arguments proffered by defendants to distinguish this case from Piney Woods.
Defendants make much of two relatively minor points of difference between the instant case and Piney Woods. They cite the provisions in the Piney Woods sales contracts stating that the sales price included consideration for processing and that the producer assumed the risk of loss during transportation to the processing plant. In the instant case, no mention is made in the sales contract of consideration for processing services. The fact that the sales contract does not state that the purchase price is consideration for processing is of little significance in light of the fact that in this case, as in Piney Woods, the producers and purchasers bargain for future residue gas of a specified Btu content which is far lower than the Btu content of the wet gas stream as it emerges from the well. In other words, while parties may not formally offer consideration for processing services, they do bargain for gas to which the value of processing has been added.
With respect to the latter provision, defendants are correct. Unlike the defendant in Piney Woods, they do not assume the risk of loss or cost of transporting the gas to the processing plant. However, while this is a point of difference between the instant case and Piney Woods, I do not believe that it outweighs the more fundamental similarities between the cases. The purchasers here, like the buyer in Piney Woods, bargained for and purchased processed gas.
In attempting to counter the Piney Woods analogy, defendants also look to Barby v. Cabot Corp., 465 F.2d 11 (10th Cir.1972), Sowell v. Natural Gas Pipeline Co., 789 F.2d 1151 (5th Cir.1986), and a 1975 ruling by the Kansas Court of Appeals, Waechter v. AMOCO Production Co., 537 P.2d 228 (Kan.S.Ct.1975). I do not find these cases dispositive of either scenario.
In Barby v. Cabot Corp., defendant Cabot, a producer-lessee, sold a wet gas stream to a common purchaser retaining to itself an option (which it exercised) to construct a gas processing plant for the extraction of liquid hydrocarbons. The wellhead price was adjusted depending on the Btu content of the gas from a particular well. The defendant reimbursed the buyer for losses in Btu content and shrinkage in volume caused by removal of liquifiable hydrocarbons. The liquid products produced after processing were sold by defendant Cabot, but the amounts received for those products were not considered in computing royalties. Plaintiff claimed that they should have been. The court ruled that royalties should be based upon the amount received by Cabot from the entire wet gas stream.
Asserting that the facts of Barby are "identical for all relevant purposes" to the facts here, (Defendants' Brief, Jan. 20, 1987, at 5.) defendants argue that this court must also find that AMOCO and Gulf *1443 correctly based royalty calculations on the amount received at the mouth of the well. I do not agree that Barby provides precedent for the instant situation.
Defendants ignore the fact that the contract at issue in Barby varied considerably from those under consideration in this case. It is true that with respect to gas determined to have been sold at the well, the Barby lease provision governing royalties is the same as the provision here. But, with respect to royalties for products sold off the premises, the Barby lease required calculation of royalties based on "market value at the well." Barby, supra, at 13. In contrast, the lease provisions here require calculation based on "amount realized" at the well for gas sold off the premises. This is a crucial difference. Although the Barby Court states early in its opinion that the language of the contract between purchaser and producer "shows that all of the gas was sold at the wellhead," id. at 14, the actual basis of its conclusion is the fact that the "market value" provision prohibited the lessor from sharing in the profits of processing irrespective of whether the gas was sold at the well or off the premises. The court stated:
The fact that appellee did repurchase and remove the liquifiable hydrocarbons jointly with other producers, and did manufacture valuable products, is of no consequence here. The appellants, by choice, tied their royalty payments to the wellhead market value of the gas. Nor, for that matter, can appellant complain that they were unaware that processing might increase the ultimate value of the gas off the premises.
. . . . .
Appellants could, if they so desired, have insisted on a contractual provision which would permit them to participate in all of the profits arising from the extraction of the liquifiable hydro-carbons.
Id. at 15.
This view was reinforced by the practicalities of the factual situation. Leasors conceded that the actual proceeds on which their royalties were calculated equalled the best market value that could have been obtained at the well. This stipulation, eliminated any practical distinction between royalties calculated on sales on and off the premises. Thus, plaintiffs admitted that under the particular market situation if the court had found that there had been a sale off the premises, the amount on which their royalties would have been calculated would not have changed.
Here, in contrast, plaintiff has made no such stipulation. Furthermore, the contract provision governing calculation of royalties on gas sold off the premises not only permits but requires that the profits from processing be accounted for. It states that for production used or sold off the premises royalties are to be paid on "one eighth of the amount realized at the mouth of the well...." And, as discussed below, I am satisfied that the phrase "amount realized at the mouth of the well" is a recognized means of referring to profits from processed gas.
With respect to the Sowell case, AMOCO and Gulf argue that, like themselves, the plaintiff-lessors there claimed that they were entitled to additional royalties on the sale by the defendant-producer of liquids recovered in the processing of a wet gas stream. According to AMOCO and Gulf, the district court and the court of appeals ruled that the Sowell plaintiffs were not entitled to royalties on the sale of natural gas liquids by the defendant-producer on the grounds
(i) that the royalty had been calculated and paid pursuant to contractual requirements on such manufactured liquids at the time they were contained in solution in the wet gas stream as a constituent part thereof, i.e. liquifiable hydrocarbons; (ii) that such was the condition of the wet gas stream at the time of production and metering at the well; (iii) that the royalty obligation was triggered by production of gas, not by its subsequent sale; and (iv) the subsequent sale by the defendant, then acting as processor and not as lessee, of the manufactured liquids recovered after processing was not relevant to the calculation of royalty. *1444 (Defendants' Brief, Jan. 20, 1987, at 7-8.) Amoco and Gulf argue that this rationale should be applied to the instant case to dismiss plaintiff's claim. I disagree.
The real basis of the court's decision in Sowell was a 1933 Gas Division Order which the parties in Sowell agreed covered their dispute. The order provided that royalties were to be paid on "sulfur free gas produced in its natural state from said well or wells ... one-eighth ( 1/8 ) of the average market price per thousand cubic feet that is paid for gas in Carson, Hutchinson, Potter, Moore, Gray and Wheeler Counties, Texas." Sowell, supra, at 1153, n. 1. Gas produced on the land in question had been designated as "old flowing" gas and prior to the lawsuit the producer looked only to the price in the six county area of comparable "old flowing" gas to calculate royalties due.
The Sowell plaintiffs first contended that in contrast to a typical market value lease where the aim is to compute the value of the gas being sold, the Division Order provided for calculation of the average six-county price without reference to the value of the gas recovered from plaintiff's land. The district court and the court of appeals agreed. Both concluded that the division order was not a typical market value lease requiring the royalty to be determined on the basis of the actual market value of the gas produced. Rather, "[t]he mathematical universe for computing the average [was] gas sales in the six counties. There is absolutely no contractual limiting of that universe to gas that is physically or legally comparable to what is produced on the ranch." Id. at 1155. In the present case there is no such external standard of measure. Royalties are to be determined by reference to the value of the gas itself.
The other claim of the Sowell plaintiffs relevant to the instant case was that they were entitled to additional royalties on natural gas liquids extracted from various drip pots at the wellhead, along the pipeline leading to the processing plant, and as a result of the processing itself. The circuit court held that "[s]ince the nature gas liquids here are with the exception of some drip collected at the wellhead before metering produced as gas, production being what triggers the royalty obligation, plaintiffs are not entitled to royalty based on component elements that assume the form of natural gas liquids after the gas is metered." Id. at 1157. The district court had similarly denied plaintiffs' request for royalties on the liquified hydrocarbons concluding that "[t]he parties were free to draft a royalty provision granting royalties for liquid hydrocarbons produced from the gas stream. However, they did not do so." Sowell v. Natural Gas Pipeline Co. of America, 604 F. Supp. 371, 379 (N.D.Tex. 1985).
In contrast, the parties to the contract at issue here included language that the plaintiff-leasors are to receive royalties on any profits from processing. The contract refers specifically to oil, condensate, and gas, and states that royalties shall be calculated on "the amount realized at the mouth of the well" for substances which are not sold at the mouth of the well but sold or used off the premises or for the manufacture of gasoline or other products. Nowhere does the contract limit royalties to the value of the gas in its "natural state" and, as I stated in reference to the Barby case and discuss below, I am satisfied that the phrase "at the mouth of the well" indicates the parties intent to calculate royalties based in part on the amount realized from the sale of liquified hydrocarbons.
Finally, with respect to Waechter, while that court addressed the question of what constitutes a sale at the well versus a sale off the premises, it did so in the context of a fact situation that varies significantly from that presented here. There was no dispute in the Kansas trial court or the court of appeals over the amount owed to the leasors for the value of the liquified hydrocarbons removed by defendants in processing. Defendants paid plaintiffs a separate royalty on that substance and plaintiffs did not argue that a dispute existed in that regard. Waechter, supra. Here the very essence of plaintiff's claim is that they were properly entitled to but did not receive royalties on the portion of the wet *1445 gas stream that was processed into liquified hydrocarbons.
B. Use of the Proceeds Less Expenses Method for Gas Sold Off the Premises
All of the leases at issue here provide that for gas sold off the premises, the royalty to be paid is one-eighth of the "amount realized at the mouth of the well." Defendants argue that the amount realized at the mouth of the well should be interpreted to mean the market value at the well. This value, they argue, is established by the contract price negotiated between themselves and the common purchasers. I do not agree with either of these assertions.
Had the parties to these leases wished to establish a "market value" means of calculating royalties, they could easily have done so. Contracts explicitly referring to "market" measure of royalties abound and frequently have been the subject of judicial opinions both before and since the signing of the leases at issue here. See e.g., Kingery v. Continental Oil Co., 626 F.2d 1261 (5th Cir.1980); Weymouth v. Colorado Interstate Gas Co., 367 F.2d 84 (5th Cir. 1966); J.M. Huber Corporation v. Denman, 367 F.2d 104 (5th Cir.1966).
Yet the parties did not include the term "market" in the contract clauses establishing royalties. Instead the parties settled upon the language, "gross proceeds" and "amount realized at the mouth of the well." Neither of these phrases implicitly or explicitly refer to market values. Cf. Holbein v. Austral Oil Co., 609 F.2d 206, 208-09 (5th Cir.1980) (drawing a distinction between contracts incorporating the phrases "market price" and "amount received" and the phrase "amount realized"). The meaning of "gross proceeds" is self-evident. It is the contract price settled on by the producer and the buyer purchasing the wet gas stream. In contrast, the phrase "amount realized at the mouth of the well" is less susceptible of a plain meaning. However, accepted trade usage of similar, if not identical phrases, leads me to conclude that the parties could only have intended it to refer to the proceeds less expenses method of calculating royalties.
In interpreting an oil and gas lease lease incorporating the well location into its measure of royalties, the Fifth Circuit stated:
Certainly a lease may provide for royalties based on proceeds less processing. But this result may be accomplished clearly and explicitly by stating that royalty is "one eighth of the amount realized from the sale of the gas less processing and transportation expenses," or even more simply, "one eighth of the amount realized by leasee, computed at the well."
Piney Woods, supra, at 235 (citations omitted). Clearly the Fifth Circuit believes the phrase "the amount realized by the lessee computed at the mouth of the well," a phrase very similar to the phrase at issue here, is the clearest shorthand for a proceeds less expenses method of calculating royalties.
This position is supported by Williams's Oil and Gas treatise which the district court in Piney Woods cited. In a section titled Expenses Shared by Operator and Nonoperator, the treatise states:
A royalty or other nonoperating interest in production is usually subject to a proportionate share of the costs incurred subsequent to production where, as is usually the case, the royalty or nonoperating interest is payable "at the well."
3 Williams, Oil and Gas § 645.2, at 596 (1986). Much of the support cited by the treatise in its discussion of this point, existed well before the parties to the instant suit negotiated the contract at issue here. See, e.g. Phillips Petroleum Co. v. Johnson, 155 F.2d 185, 188-89 (5th Cir.1946). Thus, it cannot be argued that the parties did not understand the import of their words when they concluded their contract.
Although not briefed, defendants at oral argument on June 18, 1987, argued the proceeds less expenses method of valuation should only be used when there is no market at the well. At paragraph eight in *1446 defendants' response to plaintiff's motion for summary judgment they state:
But, even if the facts were different and sale of the liquifiable hydrocarbons ... did in fact occur off-premises and after processing, as contended by plaintiff, defendants' method of calculating royalty also satisfies lease requirements because gross proceeds represents "the amount realized at the mouth of the well" and thus constitutes the proper basis for such off-premises sales.
(Defendants' Response, Jan. 20, 1987). No case cites are provided. In addition to the fact that nothing in the Williams treatise or any case that I can find indicates that the language "amount realized at the mouth of the well" is only to be interpreted to support a proceeds less expenses method of valuation when there is no market at the well, defendants' reading of this provision is illogical within the context of the contract itself. Defendants say that the "gross proceeds represents `the amount realized at the mouth of the well.'" There are two ways that this statement can be interpreted. If defendants use the term "gross proceeds" in its general sense, in other words, if they are not referring to the "gross proceeds" received in this case but any gross proceeds, it would mean that for sales off the premises a royalty owner would receive one-eighth of the total price obtained by the producer-processor on sales of the processed product. In other words the royalty owner would not be required to shoulder any portion of the post production costs of processing. I cannot accept this interpretation. It is contrary to every discussion that I can locate regarding interpretation of clauses providing for royalties on off-premises sales that do not specifically state that the royalty owner is not responsible for a proportionate share of the presale processing expenses. Furthermore, it simply does not make sense in the context of this litigation. I cannot believe that defendants intend to assert that if the court finds that there is a sale off the premises they believe the proper royalty payment amounts to one-eighth of the total proceeds of the sale of processed products rather than one-eighth of the amount of the sale minus the costs of processing.
It is more likely that by "gross proceeds" defendants are referring to the gross proceeds received by them from the common purchasers. However, this is a nonsensical reading of the phrase as it eliminates any distinction between sales off the premises and sales on the premises. Had the parties intended such a result they would have drafted the contract to provide the same measure of royalties for on and off the premises sales.
IV. Conclusion
For the reasons discussed above, I am satisfied that under both of the described scenarios the sale of gas by defendants to CPCo and MichCon took place off the premises. I am further satisfied that with respect to off the premises sales, royalties are to be calculated according to a proceeds less expenses formula. Therefore, plaintiff's motion for summary judgment is granted and defendants' motion for summary judgment is denied.
NOTES
[1] Anderson Affidavit, Aug. 21, 1985 (hereinafter "Anderson I") ¶ 4.
[2] Anderson Affidavit, Jan. 21, 1987 (hereinafter "Anderson II") ¶ 7.
[3] Plaintiff's Brief, Oct. 8, 1985, at 7.
[4] Anderson II, ¶ 12.
[5] Anderson II, ¶ 8.
[6] Gas Purchase Contract, July 1, 1974, Art. VII.
[7] Anderson I, ¶ 9.
[8] Gas Purchase Contract, July 1, 1974, Art. XXI; Anderson II, ¶ 12.
[9] Gas Purchase Contract, July 1, 1974, Arts. II, XXI.
[10] Anderson II, ¶ 10.
[11] Anderson II, ¶ 11.
[12] Anderson II, ¶ 14.
[13] Defendants' letter, Aug. 22, 1987, at 7-9.
[14] Anderson II, ¶ 12.
[15] Anderson II, ¶ 13.
[16] Gas Purchase Contract, Mar. 31, 1970, Art. X, ¶ 1.
[17] Anderson Affidavit, Nov. 20, 1987 (hereinafter "Anderson III") ¶ 5.
[18] Gas Purchase Contract, Mar. 31, 1970, at Art. VI, ¶ 3.
[19] Gas Purchase Contract, Mar. 31, 1970, Art. VI, ¶ 3.
[20] Anderson II, ¶ 13.
[21] Anderson II, ¶ 14; Anderson III, ¶ 5.
[22] Anderson III, ¶ 6.
[23] Anderson I, ¶ 18.
[24] Anderson II, ¶ 16.
