#### HANNA OIL AND GAS COMPANY v. David Patton TAYLOR

88-144

759 S.W.2d 563

Supreme Court of Arkansas

Opinion delivered November 14, 1988

[Rehearing denied December 12, 1988.]

Dorsey Ryan, for appellant.

Jeff Dangeau, for amicus curiae Seeco, Inc.

Charles S. Chambers; Turner and Mainard, by: James Mainard-, and Friday, Eldredge & Clark-, by: Michael G. Thompson and M. Gayle Corley, for appellee.

Robert H. Dudley, Justice.

The sole issue presented by this appeal is whether appellant, Hanna Oil and Gas Company, is entitled to deduct a pro rata share of its compression costs from appellee’s, David Taylor’s, royalties. The chancellor held that appellant was not entitled to deduct the costs. We affirm.

*81. In 1975, appellee, David Taylor, entered into an oil and gas lease with appellant, Hanna Oil and Gas Company. The leased land was pooled with other land to form a production unit. In 1976, appellant completed a producing natural gas well. Gas from the well was sold to Arkansas Louisiana Gas Company pursuant to a gas purchase contract between appellant and Arkansas Louisiana Gas Company. The gas purchase contract was entered after the lease agreement and required appellant to deliver the gas at a pressure of 500 pounds per square inch.

During the first eight (8) years, from 1976 to April 1984, it was not necessary to compress the gas in order to deliver it at the required pressure. Beginning in April 1984, however, appellant had to compress the gas. Yet, compression costs were not deducted from the royalty paid to appellee until October 1986. On May 5, 1987, appellee filed his petition in chancery court challenging the deduction of the compression costs.

In determining whether appellant is entitled to deduct compression costs, we must first examine the language of the oil and gas lease. Compression costs are not specifically mentioned in the lease; however, the pertinent portion of the lease provides:

> Lessee shall pay Lessor one-eighth of the proceeds received by Lessee at the well for all gas (including all substances contained in such gas) produced from the leased premises and sold by Lessee.

We have not had an opportunity before now to consider a proceeds royalty clause such as this.

Unless something in the context of an agreement provides otherwise, “proceeds” generally means total proceeds. Warfield Natural Gas Co. v. Allen, 261 Ky. 840, 88 S.W.2d 989 (1935). Webster’s New World Dictionary’s first definition of “proceeds” provides: “what is produced by or derived from something (as a sale, investment, levy, business) by way of total revenue: the total amount brought in: yield, returns.” Thus, we find it unnecessary to go beyond the clear language of the agreement between the parties to hold that appellant is not entitled to deduct compression costs. If it had been their intention to do so, they would have made some reference to costs, or “net” proceeds.

*82Further, even if we found this lease provision to be ambiguous, we would be compelled to construe it in favor of appellee. Ambiguities in an oil and gas lease should be construed in favor of the lessor and against the lessee. Bodcaw Oil Co., Inc. v. Atlantic Refining Co., 217 Ark. 50, 61, 228 S.W.2d 626, 633 (1950).

Finally, perhaps the most compelling support for our conclusion that the compression costs are not deductible lies in the construction the parties themselves placed upon their agreement for more than two years. Compression became necessary in April 1984; however, the costs associated with compression were not deducted from the royalty paid to appellee until October 1986. Thus, for over two years appellant’s construction of the lease was consistent with that urged by appellee. The construction placed upon an agreement by the parties is an important, and often decisive factor in construing an instrument. Skaggs v. Heard, 172 F. Supp. 813 (S.D. Tex. 1959).

Hays, J., dissents.

Steele Hays, Justice,

dissenting. The majority opinion has approached the issue in a straight-forward and literal way. However, the oil and gas lease does not readily lend itself to literal analysis. The majority focuses on the plain meaning of the words of this lease. While that may be a logical starting point, to simply analyze the term “proceeds,” asserting the plain, ordinary meaning, without placing the lease in its proper context, i.e. the oil and gas industry, seems destined to produce an erroneous result.

The majority reasons that no compression costs can be deducted merely because the term “proceeds” was used in the lease. They state “if it had been their intention to do so [to deduct compression costs] they would have made some reference to costs, or ‘net’ proceeds.” However, this analysis addresses only part of the problem. Lease language somewhat more pertinent, but ignored by the majority, provides that the lessor’s proceeds are to be paid on what the lessee receives “at the well for all gas produced from the leased premises and sold by Lessee.” (My emphasis).

The legal effect of the proceeds clause in the lease is to give *83some fractional value, e.g. one-eighth, of the gas sold at the wellhead to the lessor. The term “at the well” is a term of art describing the place where the royalty is calculated. Here, due to the low pressure of the gas, there would be no sales at the well, and hence no royalties, but for the compression. Yet, the majority reads the language of this lease and grants the lessor the royalties based upon the proceeds of the appellant’s sales, via long-term gas purchase contracts, with ARKLA. Interpreting this clause in its ordinary meaning requires the lessee to bear the entire cost of enhancing the gas product in order to make it saleable.

In Hillard v. Stephens, 276 Ark. 545, 637 S.W.2d 581 (1982), this court recognized and encouraged long-term gas purchase contracts executed in good faith. In the case now before us, to require the lessee to bear the entire cost of compression not only requires the lessee to enhance the value of the gas at the well, but discourages the entry into long-term contracts because without these long-term contracts there would indeed be no sales at the well, and thus no proceeds for the lessor. But because of the appellant’s diligence in securing long-term contracts for this gas, the majority opinion penalizes the lessee for these efforts.

Moreover, in Hillard v. Stephens, 276 Ark. 545, 637 S.W.2d 581 (1982), we held that, “once the lessee-producer drills a well resulting in the commercial production of natural gas on the leased premises, the lessee-producer has the immediate duty to market the gas.” In order to market the gas effectively, the lessee-producer customarily enters into a long-term purchase contract. In this case, due to the declining pressure in the well, in order to successfully adhere to the implied duty to market the gas, the gas had to be compressed. Not only does the majority opinion place financial impediments towards the lessee fulfilling this marketing duty, but the lessee’s implied duty to market is transposed into a duty to render the gas more valuable than it actually is. According to the lease, gas is to be sold and proceeds paid at the well, however, the fact is the gas in its natural state at the well is unsaleable.

Of course, it could be argued that the lessee must compress the gas at his own cost pursuant to his implied duty to market the gas. But in Clear Creek Oil & Gas Co. v. Bushmaier, 165 Ark. 303, 264 S.W. 830 (1924), we rejected the premise that the duty *84to market gas required the lessee alone to bear the post production cost of transportation. The court in Clear Creek, supra, held that when there was no market for the gas at the wells, the lessee was entitled to deduct costs from the lessor’s royalties for the cost of transportation to carry this gas to the nearest available market. Compression costs, like transportation costs, are post production expenses. Compression costs are comparable to the costs of trucking production to a distant pipeline since both are merely logistical methods by which the gap between production and pipeline is transcended, regardless of whether such gap is measured in inches or miles. Altman and Lindberg, Oil and Gas: Non-Operating Oil and Gas Interests’ Liability for Post-Production Costs and Expenses, 25 Okla. L. Rev. 363 (1972). Therefore, I believe this court should follow Clear Creek and allow the lessee to deduct compression costs from the lessor’s royalties.

Arguably, Clear Creek may be distinguished from the case before us by pointing out the royalty lease provision required that the lessee would pay the lessor based upon the “market price” rather than upon “proceeds.” The essence of the distinction between the terms “market price,” “market value,” and “proceeds” relates to setting the basis from which the royalty will be calculated. In this case, the basis for calculating the royalty is not an issue, but rather, what expenses may be deducted from this basis, and therefore this distinction for our purposes is irrelevant.

Furthermore, the sanctity of literally interpreting the lease language as written was ignored in Hillard v. Stephens, supra. Despite the royalty lease language requiring the lessee to pay the lessor based on the “prevailing market at the well,” we held that the lessors were entitled to receive royalties based on the proceeds of the sales under long-term gas purchase contracts with ARKLA.

Finally, the majority places particular emphasis on the construction the parties gave to this oil and gas lease as to whether compression costs could be deducted. It is interesting to note that the authority cited is a Texas case in which the phrase to be construed was “sold at the well” — the precise term ignored by the majority in this case. While construction of terms in leases is important, here what has occurred reflects the changing gas economy. Until 1981 the gas market was a buyer’s market. In a *85buyer’s market the gas purchasers, if necessary, compressed the gas deducting a portion of the price paid to the supplier. However, due to the oversupply of gas, gas purchasers now opt not to compress the gas themselves, but require the seller/producer to compress the gas. Therefore, the construction placed on these terms by the parties was not so much intended, but rather the construction emerged from the economics of the situation.

The oil and gas authorities, as well as the jurisdictions, are split over whether the lessor should bear any burden for the costs of compression. However, in light of our holdings that a lessee-producer has an implied duty to market the gas, and that the lessee must share the post production cost of transportation when there are no sales at the well, I believe that the lessor and lessee should bear the costs of compression proportionally. Therefore, I respectfully dissent.