Articles

Post Production Costs: What Can Really Be Charged to the Royalty Owner?

by

Charles A. Morgan

of

Dunn, Nutter & Morgan, LLP
3601 Richmond Road
Texarkana, TX 75503-0716
Phone (903) 793-5651
Fax (903) 794-5651
e-mail

A discussion of the current state of the law in Arkansas, Texas, Oklahoma, Louisiana, and other jurisdictions regarding the authority to deduct from the royalty owner a proportionate share of the post-production costs.

A presentation made to the

2001 Ark-La-Tex A.P.L. Education Seminar

Saturday, February 10, 2001

Shreveport, Louisiana

Copyright © 2001

Post Production Costs:
What Can Really Be Charged to the Royalty Owner?

by

Charles A. Morgan

By the execution of an Oil & Gas Lease, a lessor-royalty owner generally contracts with the lessee-oil company that the lessor will receive a percentage of production, i.e. a royalty, free of all costs of production. Except for a royalty owner who has elected to participate in the drilling and completion of a well, neither the industry nor a royalty owner expects the lessor to bear any part of the costs of drilling or completing a well. Both the industry and the royalty owner expect the lessee-working interest owners to bear these costs.

It is important at the outset to distinguish between a working interest and a royalty interest. The owner of a working interest actually owns a fractional, undivided interest in the mineral estate. He owns this undivided interest concurrently with the other owners of working interests and he may transfer all or part of his interest to someone else in consideration for money, goods or services. ¹ Working interest owners are considered to be co-tenants in the leasehold and they must bear costs of developing the premises for oil and gas production. Thus, working interest owners are accorded a basis in the property, including the cost of acquiring their share of the mineral estate, geological survey costs, tangible drilling costs, tangible costs incurred in testing, completing or reworking a well, secondary recovery costs and, at their election, intangible drilling costs.² These are the production costs traditionally allocated to the owners of the oil and gas leasehold, the working interests.

Definitions of "Post Production" Expenses:

The dispute arises after "production" has been obtained when the operator-lessee attempts to deduct "Post Production" costs or charges from the royalties that would have otherwise been payable to the royalty owner-lessor. What are "Post Production" expenses? For the purpose of this paper I am going to define "Post Production" expenses as follows:

"Post Production" expenses are those expenses incurred by the Lessee after the gas has been brought to the wellhead and are to be contrasted with production expenses which are incurred in bringing the gas to the wellhead. Post Production expenses include costs of dehydration, processing, gathering, compression and transportation.³

"Transportation costs" are costs incurred in transporting gas to the purchaser's pipeline. Such costs usually entail usage fees for a third party's pipeline or gathering system or the costs of building a new pipeline or gathering system which connects with the purchaser's pipeline.⁴

Recent Alabama Litigation

To say that this is a timely topic for discussion, you only have to look at the headlines of the December 20, 2000 issue of the Mobile (Alabama) Register that reads as follows:

Jury Orders Exxon to Pay State $3.5 Billion

World’s largest oil company to appeal finding that it
underpaid offshore natural gas royalties to Alabama

The Montgomery, Alabama Circuit Court jury actually awarded the state of Alabama $71 million in royalty owed, but not paid since 1994, $16.7 million in interest, and $3.42 BILLION ($3,420,000,000) in PUNITIVE DAMAGES. The major issues in the case was whether or not Exxon was entitled to deduct (or not pay for) approximately 10 MMcf of gas per day used as lease fuel to compress and transport sour gas from Bon Secour Bay Field to the Exxon onshore processing plant in Mobile. The punitive damage award was made after the introduction into evidence of a number of Exxon internal documents which warned the company it was wrongly calculating the royalty and suggested that it might get away with the deduction because the Alabama regulators were "inexperienced."

In a paper to be presented at the 2001 Arkansas Natural Resources Institute, Jefferson D. Stewart cites this case and states:

This jury verdict should be a wake-up call to oil and gas lawyers who may be called on to advise operators and lessees about how to calculate lease royalties. Because of the inherent vagueness of the standard gas royalty provision and the dramatic changes in the production marketplace, the last two decades have been filled with litigation in virtually every oil and gas producing jurisdiction on the issue of exactly what does the oil and gas lessee owe to the oil and gas lessor under the gas royalty provision.⁵

Three Lease Issues to be Resolved

Although post production charges can be incurred with regard to the production of oil, almost all of the case law involves the production of gas. Thomas W. Lynch, in an article entitled The Deductibility of "Post-Production" Costs in Calculating Gas Royalties,⁶  states that the deductibility of post production costs is an issue that has been around for more than 40 years, back to the time natural gas first became an economically viable commodity. But the issue has received more attention in recent years and is actually one of three related questions. The three related questions raised by Mr. Lynch in his presentation were:

1. Is the lessee obligated to install or use facilities in order to produce or market gas downstream from the well?
2. If the lessee does install or use downstream facilities, is the lessor (through royalty) entitled to share in the benefits of those facilities?
3. If the lessor does share in the benefits of downstream facilities, may the cost of those facilities be deducted in calculating his royalty?

There are various factors that would affect how these questions are answered. Three factors must be reviewed in order to answer these questions. These three factors are (a) the duties of the Lessee under the implied marketing covenant, (b) the wording of the royalty clause in the lease, and (c) the determination of when "Production Operations" end. How did we get to this point?

History reflects that all too many scriveners who foolishly attempt to write royalty clauses in Oil & Gas Leases fail to "mean what they say and say what they mean". This, in the words of William J. Wynne, is the "genesis" of the problem. Thomas Lynch, in his article, relates:

When I was a young lawyer in the late 1950's, my boss insisted that we fully understand everything we prepared or read, including various oil and gas lease forms then in common use. Nothing was to be considered acceptable simply because it was common. At the time I believed I understood gas royalty clauses based on "proceeds" or "net proceeds" or "gross proceeds". But I was baffled by the words "market value at the well" found in most lease forms.

My mentors, who were older and wiser, explained that it is sometimes necessary for the lessee to transport gas from the well to the purchaser's pipeline, perhaps off the lease and some distance away. The words "market value at the well" were designed to enable the lessee, for royalty purposes, to construct an artificial (but fair) wellhead value by deducting transportation costs from the price he received at the purchaser's pipeline. Thus, if it costs the lessee 2¢ per Mcf to transport the gas to the purchaser's pipeline, where he sells it for 10¢ Mcf, the presumed wellhead value for royalty purposes would be 8¢ per Mcf.

The concept made sense because, had the lessee asked the purchaser to buy the gas at the wellhead, the purchaser would have to construct a gathering line and the actual wellhead price would no doubt have been less than 8¢ per Mcf. By constructing his own gathering line, the lessee enhanced the value of the gas for himself and his lessor. It made sense to deduct the cost in calculating royalty.

Market value royalty clauses have been around for most of this century and people have been trying to explain them for at least half that long.⁷ Nevertheless, the industry continues to use them.

Texas Law & Authority

The Texas courts have construed the words "at the well" to mean anywhere on the lease, not just at the well. Exxon Corporation v Middleton, 613 S.W.2d 240 (Tex.1981). Whatever the words "at the well" mean in a royalty clause, they were obviously intended to mean something. However logical, this reasoning was not followed in Arkansas, as we shall see.

Arkansas Law & Authority

In 1988, Hanna Oil and Gas Co. v. Taylor, 759 S.W.2d 563, 297 Ark. 80 (Ark. 1988), the Arkansas Supreme Court apparently ignored the phrase "at the well" since they concluded that compression costs are to be born by the lessee and not by the lessor-royalty owner, unless the language of a "proceeds" lease had clearly made reference to "net proceeds" or otherwise permitted such a deduction from the royalties due the royalty owner. In Hanna the oil and gas lease specifically provided that:

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.⁸ (emphasis added)

In Hanna, the Arkansas Supreme Court acknowledged that it had not previously had the opportunity to consider a "proceeds royalty clause" but then stated:

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.

. . . Further, 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).

The majority opinion of the Arkansas Supreme Court did not give any consideration to the phrase "at the well", and it is the application of the phrase "at the well" which is largely responsible for the confusion and the diverse opinions that have been rendered by the appellate courts of Texas, Louisiana, Oklahoma and Arkansas. Justice Hays, in his dissenting opinion in Hanna, correctly notes that the term "at the well" is a term of art describing the place where the royalty is calculated.10 Justice Hays, in his dissent, goes on to state:

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 to 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.⁹

M. Keith Blythe, in his case note entitled, Hanna Oil and Gas v. Taylor: Compression Costs in Oil and Gas Leases---Who Pays? ¹⁰ states the Hanna decision is likely to be challenged and should be overruled. I wish I felt as confident as Mr. Blythe, but I don't know that the Arkansas Supreme Court will be so willing to correct the mistakes it made in Hanna.

The majority opinion in Hanna also ignores the position taken by the Arkansas Supreme Court in Parnell, Inc. v. Giller, 372 S.W.2d 627, 237 Ark. 267 (Ark. 1963), where the court, in construing a brine lease, stated that the royalty payable to the lessor is computed upon the market value of the salt water at the well and that the question is whether the lessee, in calculating the market value, is entitled to deduct its expenses in piping the salt water to the chemical company and in disposing of the spent brine. The Supreme Court concluded that both deductions must be allowed under the following royalty provision in the lease:

The royalty to be paid by Lessee is: On brine produced from said land and sold off the premises or used off the premises in the manufacture of bromine or other product therefrom, the market value at the well of one-eighth (1/8) of the brine so sold or used; provided, that on brine sold at the wells the royalty shall be one-eight (1/8) of the amount realized from such sale.¹¹

The court noted that the lease was evidently patterned after a common form of oil and gas lease and stated that a similar clause was construed in Clear Creek Oil & Gas Co. v. Bushmaier, supra, where the gas was used off the premises and the lessee was entitled to deduct its transportation and distribution expense in determining the market value of the gas at the well. In Parnell, supra, the court then stated:

As a transportation cost the pipeline expense falls within the letter of the Bushmaier case. The expense of disposing of the used brine falls within its reasoning. Both services were demanded by the chemical company as a condition to its willingness to enter into the contract of purchase. It is not reasonable to suppose that the buyer would have agreed to pay as much as it did for the brine if the performance of these necessary steps had been its own responsibility. Hence, as in the Bushmaier case, these charges must be taken into account in fixing the market value at the well.

In other words the pipeline expense and the cost of disposing of the salt water from which the bromine had been extracted were to be paid proportionately by the lessor-royalty owner and lessee-operator. Twenty years later this same court reached an opposite result in Hanna as to compression charges.

When does "production" end and "post production" begin?

Accordingly, before we can answer the question of deductibility of certain charges or expenses as they relate to the phrase "at the well", it becomes necessary to determine when does "production" end and "post production" begin?

As an oil and gas industry executive or as an oil and gas lawyer, where would you draw the line between "production" and "post-production" operations? The plain fact is that a lawyer, a geologist, a landman, a petroleum engineer and an accountant may each have different opinions, each of which can be supported by its own set of facts that make it fair and equitable. In fact, two of the leading legal scholars on oil and gas law are split:

Prof. Howard Williams says that production ends when the raw oil and gas come out of the well, at least where royalty is payable "at the well".¹²

Prof. Eugene Kuntz says that production does not end until there is a "marketable product," at least with facilities that are located on the lease.¹³

In Middleton, the court defined "At the Well" as meaning that the gas has not been increased in value by processing or transportation. It has this meaning in conjunction with "value" or "amount realized" as well as with "sold." When Prof. Williams focuses on the words "at the well", he does not mean "anywhere on the lease" as defined by the Middleton¹⁴ case. He literally means at the well or close to it. On the other hand, Prof. Kuntz would not require a lessee to transport gas miles off the lease in order to make it "marketable".

It can generally be said that the Louisiana and Texas cases17¹⁵ line up on the side of Prof. Williams. In Martin v Glass, 571 F. Supp. 1406 (N.D. Tex. 1983), aff'd 736 F.2d 1524 (5th Cir. 1984), at p.1415, the Court stated as a matter of fact that: "Under the law of Texas, gas is 'produced' when it is severed from the land at the wellhead."

What are Production Facilities?

What is the practice of the oil and gas industry? Operationally (apart from the wording of royalty clauses), most industry people would classify the following as "production" facilities:

1. well and the wellhead,
2. lease separator,
3. oil storage tanks,
4. salt water disposal well; and,
5. various flow lines connecting these facilities to each other.

In other words, the cost of these facilities and their operation would be borne solely by the lessee unless there were express lease provisions to the contrary.

What are Marketing Facilities

Most people would classify other downstream facilities, such as the dehydrator, the compressor and the meter, as "marketing" facilities. Of course, a processing plant is even further removed (in location and function) from "production" operations and is definitely considered a marketing facility.

Severance Taxes

In Texas the industry practice is confirmed by regulations issued under the Texas severance tax statute. In calculating "market value at the mouth of the well", the regulations allow deductions for certain "marketing costs" including compression, dehydration, sweetening and delivering the gas, but do not allow a deduction for the cost of "normal lease separation."¹⁶ Arkansas case law and authority also directs severance taxes to be shared proportionately based upon the production proceeds actually received. In P & O Falco, Inc. v. Riley, 610 S.W.2d 255, 271 Ark. 562 (Ark. 1980), the Arkansas Supreme Court stated:

The severance tax is levied as a privilege or license tax upon the severance of natural resources from the soil or water in Arkansas. With respect to oil the tax rate is 4% or 5% of the market value of the oil, depending upon the volume of production. Ark. Stat. Ann. §84-2101 and -2102(e) (Repl.1980). The monthly tax reports are to be filed, and the tax paid, by the producer actually severing the oil from the soil, but the producer is required to deduct a proportionate part of the tax in making payment to the royalty owner. §84-2105. Thus the owner of a one-eighth royalty interest bears his one-eighth of the tax burden.¹⁷

Also, it can be broadly stated that Arkansas and Oklahoma follow the position of Prof. Kuntz when he says that production does not end until there is a "marketable product", at least with facilities that are located on the lease.

Louisiana Law & Authority

Frederick R. Parker, Jr., in his article entitled Costs Deductible By The Lessee in Accounting To Royalty Owners Production of Oil or Gas, 46 La. L. Rev. 895, March, 1986, outlines the Louisiana position when he states:

The Louisiana Mineral Code specifies that in the absence of an express contractual provision to the contrary the lessee-operator bears all drilling and production costs.

. . . It is generally accepted that the production phase of oil and gas operations terminates upon reduction of the minerals to possession at the well. While the peculiarities of individual lease provisions may provide otherwise, the general rule is that a royalty owner is liable for a proportionate share of the costs incurred subsequent to production. Such 'subsequent to production' costs generally include those related to taxes, transportation and processing.

The general rule in Louisiana was summarized in 1960 by the United States Court of Appeals for the Fifth Circuit in Freeland v. Sun Oil Co, 277 F.2d at 159. In Freeland, the court stated:

[T]he value of the raw, wet gas in its relatively unmarketable state at the wellhead was not equivalent to the price which the end product of that industrial process would command. The wet gas was important. Indeed, it was the indispensable raw material. But the availability of the extracting process and its application enhanced the value of the gas. The enhancement is of the value of the gas at the wellhead . . . In determining the market value of such gas at the well where there is no established criteria of a market, the Louisiana approach . . . is to consider the end product of the extraction process as a factor. But it is a factor in reconstructing a market value at a place where there was no, or little, market and consequently an appropriate deduction must be made.

The Freeland the court went on to summarize the general principle previously established by the Louisiana Supreme Court:[The principle] is not . . . limited to the extraction cost necessary to make an absolutely worthless thing (gas) into something of value. It stands for the proposition that in determining market value costs which are essential to make a commodity worth anything or worth more must be borne proportionately by those who benefit.

Mississippi Law & Authority

In Piney Woods Country Life School v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984) the lessors and Shell entered into Mississippi oil and gas leases in the mid-1960's. Shell used three different royalty clauses in seven different forms. The relevant portions of the leases generally stated that the royalty for gas sold or used off the premises was based on the market value at the well, while the royalty for gas sold at the well was based on a percentage of the amount realized from the sale. Because the gas from these wells was sour, Shell processed or treated the gas before selling it. Shell paid royalties based on actual revenues from sales of sweet gas and sulfur, and not based on the market value. A substantial part of the processing costs were deducted from the royalties.

In Piney Woods, the Court of Appeals for the Fifth Circuit decided that market value means the current market value when the gas is produced and delivered. The court considered whether Shell actually sold the gas 'at the well.' Although the sales contracts provided that title passed in the field, the actual sale prices were determined off the field after processing and transportation. The court stated that the simple passage of title does not control whether the gas was sold at the well within the meaning of the leases. The court reasoned that to decide otherwise would place the lessors at the mercy of the lessee since the lessors had no say as to where title would pass. Therefore, for two of the lease royalty clause provisions, the gas was not 'sold at the wells' since processing and transportation added to the value of the gas. The court then allowed Shell to deduct processing and transportation costs for gas sold in order to compute market value at the well. The Court reasoned that because production ends when the gas is extracted, expenses subsequent to production may be charged to royalty when royalty is computed at the well. The case was then remanded to determine market value and the existence of reasonable expenses subsequent to production.

Oklahoma Law & Authority

Prior to the recent Oklahoma Supreme Court decision in Fox Wood III v. TXO Prod. Co.,¹⁸ most commentators and most producers in the Oklahoma oil and gas industry placed Oklahoma among the states that permit compression expenses to be deducted from royalties absent contrary language in the governing lease. In Wood, however, the Oklahoma Supreme Court (the "Court") held, in a five-four decision, that the costs of compressing gas for delivery into a pipeline on the lease premises could not be deducted from royalties absent express language so providing in the lease. As a result of the Wood decision, Oklahoma was suddenly transformed into a state that, absent express authorization in the lease, does not allow post-production expenses to be deducted from royalties. One of the cases cited and relied upon by the Oklahoma Supreme Court was the Arkansas case of Hanna Oil & Gas v. Taylor.¹⁹

The Lessee's Implied Duty to Market

While it is generally accepted that a lessee has an implied duty to market production,²⁰ authority is split with respect to the extension of this duty to include preparation of the product for market at the lessee's sole expense if the product is unmerchantable in its natural form.²¹

A duty to market gas does not equate to a duty to pay all marketing costs arising after the gas has been produced.²² This logic applies equally to all post-production expenses, including gross production and severance taxes, processing, compression, dehydration and transportation. This argument is strengthened by the fact that most leases, including the leases in Wood and Hanna, call for the royalty to be determined "at the well."

While the lessee has a duty to diligently market the gas, it is "almost universally recognized that the lessee's marketing obligation is measured at the wellhead," absent a contrary lease provision.²³ If there is no market at the well, or if the gas is not marketable at the well, then the lessee's sole financial responsibility ceases. One commentator stated:

If the gas cannot be sold there [at the wellhead] and must be transported to a market elsewhere, the lessor must contribute his portion of the transportation costs. Why is it any more or less a part of the lessee's obligation to 'market' gas, to transport it to some distant market if no local outlet is available, than to pay for its dehydration if such processing is necessary in order to render it saleable? Here is a well and here is gas at the wellhead. At this time and place we evaluate that gas for purposes of computing royalty. It is worth what it will bring at that point in its natural state, no more, no less. Of course the lessee has an implied duty to market it. But it is a duty to market or dispose of it at the well. If it cannot be sold there for lack of a purchaser, it may be transported elsewhere. Fine. But for that transportation the lessor must pay proportionately. If it cannot be sold at the well because of its inferior quality, how can the lessee's duty to 'market' be transposed into a duty to render the gas more valuable than it actually is, all at his expense? ... To my mind it is at least equally persuasive to insist that the duty to market is confined to the product in the state in which it is produced at the well, and does not include any duty, at the lessee's sole expense, to increase its value by processing, any more than it includes a duty to transport it free of charge to distant markets.²⁴

Once the gas is made available for market, the lessee's duty to market ceases and any further expenses should be shared by the lessor.

Possible Solutions to the Dilemma of "Post Production" Charges

1. Add Express Deductibility Provisions to New Leases

Since the language currently being used in most oil and gas leases does not explicitly provide that lessors must share in post production costs, as a result of the Wood decision in Oklahoma and the Hanna decision in Arkansas most producers should and will revise the language of the royalty provisions in their oil and gas lease forms to expressly provide that lessors are to share in all post production expenses. Of course, adding such provisions to all new leases does not provide relief from the effects of Hanna and Wood on outstanding or existing leases. Consequently, producers in Arkansas and Oklahoma that fail to revise their royalty provisions will likely be challenged by their lessors if they continue to deduct their post production costs. Furthermore, such a challenge is likely to succeed unless the producer can distinguish its circumstances from those in Wood and Hanna.

The royalty clause from a lease that is in general circulation in Southwest Arkansas states:

1. In consideration of the premises, the said Lessee covenants and agrees:
   1. To deliver to the credit of Lessor, free of cost, in the pipeline to which it may connect its wells, the one-eighth (1/8) part of all oil (including but not limited to condensate and distillate) produced and saved from the leased premises;
   2. To pay Lessor for gas of whatsoever nature or kind (with all of its constituents) produced and sold or used off the leased premises, or used in the manufacture of products therefrom, one-eighth (1/8) of the gross proceeds received for the gas sold, used off the premises, or in the manufacture of products therefrom, but in no event more than one-eighth (1/8) of the actual amount received by the Lessee, said payments to be made monthly;
   3. To pay Lessor for gas produced from any oil well and used off the premises, or for the manufacture of casinghead gasoline or dry commercial gas, one-eighth (1/8) of the gross proceeds, at the mouth of the well, received by Lessee for the gas during the time such gas shall be used, said payments to be made monthly; and,
   4. That all royalties, shut-in royalties, or other sums which may become payable to Lessor under the terms of this lease may be paid or tendered by cash, check, draft, electronic funds transfer, or any other commercially reasonable method which Lessee may elect from time to time.²⁵

After having to complete the research necessary to prepare this paper, I have revised this oil and gas lease so that now the royalty clause reads as follows:

1. In consideration of the premises, the said Lessee covenants and agrees:
   1. To deliver to the credit of Lessor the one-eighth (1/8) part of all oil (including but not limited to condensate and distillate) produced and saved from the leased premises;
   2. To pay Lessor for gas of whatsoever nature or kind (with all of its constituents) produced and sold or used off the leased premises, or used in the manufacture of products therefrom, one-eighth (1/8) of the net proceeds received for the gas sold, used off the premises, or in the manufacture of products therefrom, but in no event more than one-eighth (1/8) of the actual amount received by the Lessee, said payments to be made monthly;
   3. To pay Lessor for gas produced from any oil well and used off the premises, or for the manufacture of casinghead gasoline or dry commercial gas, one-eighth (1/8) of the net proceeds, at the mouth of the well, received by Lessee for the gas during the time such gas shall be used, said payments to be made monthly;
   4. Lessee is authorized to deduct from such proceeds the cost incurred in compressing, treating, dehydrating, marketing and transporting such oil, gas and/or casinghead gas for delivery in computing the net proceeds at the well payable as royalty; and
   5. That all royalties, shut-in royalties, or other sums which may become payable to Lessor under the terms of this lease may be paid or tendered by cash, check, draft, electronic funds transfer, or any other commercially reasonable method which Lessee may elect from time to time.²⁶

M. Keith Blythe, in his case note that appeared in the Arkansas Law Review following the Hanna decision, notes that the royalty clause in AAPL Oil and Gas Lease, Form 235 (Rev. 12-88) had been rewritten to read as follows:

While such a change in the lease provisions may prevent problems in subsequently executed leases, it does nothing to protect the lessee-operator under leases already taken.

If an operator negotiates an "arms length" contract which provides that the purchaser will acquire the oil and gas at the well and then the purchaser will be solely responsible for the subsequent costs of treatment, compression, dehydration, marketing and transportation, then I believe the courts will honor such contracts even though they permit the lessee to accomplish indirectly what it cannot do directly under the terms of some leases. The caveat, however, is that the contract must be made in good-faith and there can be no hint of collusion between the lessee-operator and the purchaser, as evidenced by Texas Oil & Gas Corp. v. Hagen, 683 S.W.2d 24 (Tex.App.-Texarkana 1984).²⁸

In Hagen, supra, several royalty owners brought an action against their gas lessee based on breach of contract, failure to market gas with good faith and reasonable diligence, and fraud by misrepresentation and concealment. Texas Oil & Gas (TXO) contracted to sell the plaintiffs' royalty share of gas to Delhi Pipeline Company, TXO's wholly owned subsidiary. Delhi transported the gas to a central dehydration facility in the field, then transported the gas seven and one-half miles to a gas treating plant. After treating, Delhi transported the gas to two end-line users fifty and one hundred miles away. These end-line users paid fifteen cents per Mcf more than the price provided in the TXO-Delhi contract. TXO paid the plaintiffs royalties based on the lower-price in the TXO-Delhi contract.

The plaintiffs claimed that because Delhi was a subsidiary of TXO, the gas was not actually sold at the wells but was "sold or used off the premises" by TXO. Based on proof that the subsidiary was merely the alter ego of its parent company, the court disregarded the purported sale of gas at the wells and found that the true sale was off the premises. The court found the evidence insufficient to create a presumption of arm's-length contracting and held that the sale of gas by the lessee to its wholly owned subsidiary was a sham. Therefore, the market value royalty clause was operative, and not the proceeds royalty clause. Although the Hagen court found the gas contract to be a sham, it did acknowledge that, under proper circumstances, a presumption of arm's-length contracting could be sustained:

The mere fact that a subsidiary is wholly owned by the parent and there is an identity of management does not justify disregarding the corporate entity of the subsidiary, but where management and operations are assimilated to the extent that the subsidiary is simply a name or a conduit through which the parent conducts its business, the corporate fiction may be disregarded in order to prevent fraud and injustice.²⁹

Even though the judgment in Hagen was set aside by the Texas Supreme Court based on a settlement reached by the parties, and therefore has no precedential value, it is still illustrative of the attitude of the Texas courts.

The proper circumstances alluded to in Hagen were in fact presented to the Texas Court of Appeals two years later in Parker v. TXO Production Corp., 716 S.W.2d 644 (Tex.App.--Corpus Christi 1986, no writ). Parker involved a suit by royalty owners for breach of the implied covenant to market gas in good faith. The lessee sold gas to its wholly owned subsidiary at ninety-five percent of market value, deducting five percent for compression charges, even though other prospective purchasers made no similar deduction. The court held there was no basis for piercing the lessee's corporate veil to determine if the sale was a sham. Therefore, if the contract gas sales price is found to be "close" to its market value price at the time the contract was negotiated, the court will presume the contract was negotiated at arm's length and the "proceeds" gas royalty clause will be operative. Unfortunately, the Arkansas courts may reach a different result in light of Hanna.³⁰

The following division order provision illustrates one possible way that a producer has attempted to protect himself from the claims of a disgruntled royalty owner:

Settlements for gas and/or casinghead gas produced from the property covered by this Division Order shall be based upon the net proceeds received by the working interest owners from the sale of such oil, gas and/or casinghead gas computed at the wells. You are authorized to deduct from such proceeds the cost incurred in compressing, treating, dehydrating, marketing and transporting such gas and/or casinghead gas for delivery in computing the net proceeds at the wells payable as royalty. . . . Each of the Owners who own a royalty interest (landowner's royalty) in the property hereinabove described, by the execution of this Division Order, hereby adopts, ratifies and confirms each oil and gas lease, and each gas purchase contract, together with any amendments thereof, to which this Division Order applies. . . This contract shall remain in full force and effect until canceled by any party hereto upon giving 60 days written notice in advance of any such cancellation.

The problem with incorporating such a provision in the Division Order rather than the lease is that the case law is fairly clear that the Division Order does not alter or amend the terms of the lease. While such a provision may protect the purchaser of the oil or gas, it does little to insulate the lessee from subsequent litigation seeking an accounting and/or reimbursement for any sums deducted from the royalty owners' share of production, if such compression, treatment, dehydration, marketing or transportation charges were not expressly authorized by the lease. Accordingly, this is not an ideal solution and may be only partially effective. Consider it, but do not feel that a Division Order provision will offer any security or comfort when forced to respond to an angry or disgruntled royalty owner.

Summary

Post production expenses such as the costs of compression, dehydration, processing and transportation should be apportioned among lessors because royalties are to be determined under most leases at the wellhead. In other words, a lessee's duty to market the product ceases at the wellhead. Post production compression costs, in particular, are analogous to and should be treated like transportation costs since compression costs are incurred only to push or transport gas into the purchaser's pipeline. While this is not currently the law in Arkansas and Oklahoma, it should be. Hopefully the opportunity will present itself to the Arkansas Supreme Court and the Oklahoma Courts to "undo" what was done in Hanna and Wood.

In fact, if any type of post production expense should fall within the lessee's duty to market gas, it is a transportation expense, not the other post production expenses. Transportation expense is incurred merely to transport gas in its natural state (i.e., the substance which was actually produced from the well) from the wellhead at which no market for the gas exists, to a pipeline at which there is a market for the gas. Conversely, costs of compression, dehydration and processing are all attributable to the transformation of the gas from its natural state as produced at the well into a new, more valuable product. It seems unreasonable to allow lessors to benefit from higher prices received for processed or compressed gas that result from the post production activities after the gas passes the wellhead (where, according to most leases, the gas is to be measured for royalty purposes) without requiring the lessors to share in the costs of such activities.

This was perhaps said best by Richard B. Altman and Charles S. Lindberg, in their article entitled Oil and Gas: Non-Operating Oil and Gas Interests' Liability for Post-Production Costs and Expenses, 25 OKLA. L. REV. 363, 376 (1972) stated:

[i]t defies logic to argue that where gas cannot be sold at the wellhead because of its inferior quality the lessee's duty to market gas can be converted into a duty to render the gas more valuable than it actually was, all at his own expense.

In summary, read your lease, rewrite your future leases, rewrite your division order, and then cross your fingers that the Arkansas Supreme Court and the Oklahoma Supreme Court each come to a better appreciation of what is meant by the phrases at the well and post production expenses.

B I B L I O G R A P H Y

Case Law:

Bell Oil & Gas Co. v. Allied Chem. Corp. 431 S.W.2d 336 (Tex.1968)

Bodcaw Oil Co., Inc. v. Atlantic Refining Co., 217 Ark. 50, 61, 228 S.W.2d 626, 633 (1950)

Clear Creek Oil & Gas Co. v. Bushmaier, 165 Ark. 303, 264 S.W. 830 (1924)

Exxon Corporation v Middleton, 613 S.W.2d 240 (Tex.1981)

Fox Wood III v. TXO Prod. Co., 854 P.2d 880 (Okla. 1993) (modifying 63 Okla. B.J. 2023 (July 11, 1992)

Freeland v. Sun Oil Co., 277 F.2d at 159

Gentry v. Credit Plan Corp. of Houston, 528 S.W.2d 571 (Tex.1975)

Gilmore v. Superior Oil Co., 388 P.2d 602, 607 (Kan. 1964)

Hanna Oil and Gas Co. v. Taylor, 759 S.W.2d 563, 297 Ark. 80 (Ark. 1988)

Katschor v. Eason Oil Co., 63 P.2d 977 (Okla. 1936)

Kretni Dev. Co. v. Consol. Oil Corp., 74 F.2d 497 (10th Cir. 1934), cert. denied, 295 U.S. 750, (1935)

Lone Star Gas Company v Murchison, 353 S.W. 2d 870, 879 (Tex. App. Dallas 1962),writ ref'd n.r.e.

Martin v Glass, 571 F. Supp. 1406 (N.D. Tex. 1983), aff'd 736 F.2d 1524 (5th Cir. 1984)

Molter v. Lewis, 134 P.2d 404 (Kan. 1943)

Parker v. TXO Production Corp., 716 S.W.2d 644 (Tex.App.- Corpus Christi 1986, no writ)

Parnell, Inc. v. Giller, 372 S.W.2d 627, 237 Ark. 267 (Ark. 1963)

Phillips Petroleum Co. v. Ochsner, 146 F.2d 138 (5th Cir. 1944)

Piney Woods Country Life School v. Shell Oil Co., 539 F. Supp. 957,

973 (S.D. Miss. 1982)726 F.2d 225 (5th Cir. 1984)

P & O Falco, Inc. v. Riley, 610 S.W.2d 255, 271 Ark. 562 (Ark. 1980)

Sartor v. Arkansas Natural Gas Corp., 321 U.S. 620 (1944),reh'g denied, 322 U.S. 767 (1944)

Texas Oil & Gas Corp. v. Hagen, 683 S.W.2d 24 (Tex.App.-Texarkana 1984)

Warfield Natural Gas Co. v. Allen, 261 Ky. 840, 88 S.W.2d 989 (1935)

Wolfe v. Texas Co., 83 F.2d 425, 432 (10th Cir. 1936), aff'd, 299 U.S. 553 (1936)

Statutes, Regulations, etc.:

34 Tex. Adm. Code, §3.15

Internal Revenue Code, 26 U.S.C., §263 (1982)

Other authorities:

Altman, Richard B. and Lindberg, Charles S., Oil and Gas: Non-Operating Oil and Gas Interests' Liability for Post Production Costs and Expenses, 25 Okla. L. Rev. 363, 376 (1972)

M. Keith Blythe, Hanna Oil and Gas v. Taylor: Compression Costs in Oil and Gas Leases---Who Pays? 43 Ark. Law. Rev. 201

Kuntz, THE LAW OF OIL & GAS §40.5 (1989)

Lynch, Thomas W., The Deductibility of "Post-Production" Costs in Calculating Gas Royalties, Review of Oil and Gas Law X, August 24-25, 1995, Energy Law Section of the Dallas Bar Association

Maurice H. Merrill, MERRILL ON COVENANTS IMPLIED IN OIL AND GAS LEASES, s 85, at 214 (2d ed. 1940)

Frederick R. Parker, Jr., Costs Deductible By The Lessee in Accounting To Royalty Owners Production of Oil or Gas, 46 La. L. Rev. 895, March, 1986

Redwine, R. Kevin and Heinen, Steven G., Deductibility of Natural Gas Compression Costs in Light of Fox Wood III v. TXO Production Co., Tulsa Law Journal, Spring/Summer 1994 (Footnote #1)

Seifkin, Rights of Lessor and Lessee With Respect to Sales of Gas and as to Royalty Provisions, 4 INST. ON OIL & GAS LAW & TAXATION 181 (1953)

Sneed, J., Value of Lessor's Share of Production Where Gas Only is Produced, 25 TEX. L. REV. 641, 644 (1947)

Stewart, Jefferson D., Post-Production Charges to Royalty Owners: What Does the Contract Say and When is it Ignored?, Arkansas Natural Resources Law Institute, February 23, 2001, Hot Springs, Arkansas

Williams & Meyers, OIL AND GAS LAW, §501, §503, § 645.1, §645.2

Williams & Meyers, MANUAL OF OIL AND GAS TERMS, 128 (5th ed. 1981)

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¹  H. Williams & C Meyers, OIL AND GAS LAW ss 501, 503 (1984); see also H. Williams & C. Meyers,
  MANUAL OF OIL AND GAS TERMS (5th ed. 1981)

²  See 2 Williams & Meyers, supra, s 645.1; and Internal Revenue Code, 26 U.S.C. s 263 (1982)

³  Redwine, R. Kevin and Heinen, Steven G., Deductibility of Natural Gas Compression Costs in Light of Fox Wood III v. TXO Production Co., Tulsa Law Journal, Spring/Summer 1994

⁴ Redwine, R. Kevin and Heinen, Steven G., Deductibility of Natural Gas Compression Costs in Light of Fox Wood III v. TXO Production Co., Tulsa Law Journal, Spring/Summer 1994

⁵ Stewart, Jefferson D., Post-Production Charges to Royalty Owners:  What Does the Contract Say and When is it Ignored?, February 23, 2001, Hot Springs, Arkansas

⁶ Lynch, Thomas W., The Deductibility of “Post-Production” Costs in Calculating Gas Royalties, Review of Oil and Gas   Law X, August 24 – 25, 1995, Energy Law Section of the Dallas Bar Association

⁷ See Seifkin, Rights of Lessor and Lessee with Respect to Sales of Gas and as to Royalty Provisions, 4 INST. ON OIL & GAS LAW & TAXATION 181 (1953)

⁸ 287 Ark 81
⁹ 297 Ark.84

¹⁰ 43 Ark. Law. Rev. 201, at 215

¹¹ 237 Ark. 268
¹² See Williams & Meyers, Oil & Gas Law §645.2 (1992) at p. 598

¹³ See Kuntz, THE LAW OF OIL & GAS §40.5 (1989) at p. 351

¹⁴ See Exxon Corporation v. Middleton, supra, page 6
¹⁵ Lone Star Gas Company v. Murchison, 353 S.W.2d 870, 879 (Tex.App.Dalas 1962), writ ref’d n.r.e.

¹⁶ 34 Tex.Adm.Code §3.15
¹⁷ 271 Ark. 564

¹⁸ 854 P.2d 880 (Okla. 1993) (modifying 63 Okla. B.J. 2023 (July 11, 1992)). The original opinion was modified to delete references the Court had made to the effect that the Wood decision was in accordance with the “custom and practice” of the natural gas industry in Oklahoma.

¹⁹ 759 S.W.2d 563, 297 Ark. 80, (Ark. 1988)

²⁰ Wolfe v. Texas Co., 83 F.2d 425, 432 (10th cir. 1936), aff’d, 299 U.S. 553 (1936)

²¹ Compare Maurice H. Merrill, MERRILL ON COVENANTS IMPLIED IN OIL AND GAS LEASES, s 85, at 214 (2d ed. 1940) and Gilmore v. Superior Oil Co., 388 P.2d 602, 607 (Kan. 1964) with Piney Woods Country Life School v. Shell Oil Co., 539 F.Supp. 957, 973 (S.D. Miss. 1982) and G. Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas as to Gas Royalty Provisions, 4 Oil & Gas Inst. 181, 199-201 (Sw. Legal Found. 1953). See Kretni Dev. Co. v. Consol. Oil Corp., 74 F2d 497, 500 (10th Cir. 1934), cert denied, 295 U.S. 750, (1935); Martin, 571 F.Supp. at 1416; Piney Woods, 539 F.Supp at 972; Fox Wood III v. TXO Prod. Co., 854 P.2d 880, 884 (Okla. 1993) (Opala, J., dissenting); Hanna Oil and Gas Co. v. Taylor, 759 S.2d 563, 566 (Ark. 1988) (Hays, J., dissenting); Kuntz, supra note 5, s 40.5(b) at 350-51; J. Sneed, Value of Lessor’s Share of Production Where Gas Only is Produced, 25 Tex. L. Rev. 641, 644 (1947)

²² Sartor v. Arkansas Natural Gas Corp., 321 U.S. 620 (1944), reh’g denied, 322 U.S. 767 (1944); Phillips Petroleum Co., v. Ochsner, 146 F.2d 138 (5th Cir. 1944); Kretni Dev. Co. v. Consol, Oil Corp., supra; Clear Creek Oil & Gas Co. v. Bushmiaer, 264 S.W. 830 (Ark. 1924); Molter v. Lewis, 134 P.2d 404 (Kan. 1943); Warfield Natural Gas Co. v. Allen, 88 S.W.2d 989 (Ky. 1935); Katschor v. Eason Oil Co., 63 P.2d 977 (Okla. 1936) G. Siefkin, Rights of Lessor and Lessee with Respect to Sale of Gas as to Gas Royalty Provisions, 4 Oil & Gas Inst. 181, 199-201 (Sw. Legal Found. 1953). Arkansas Producers 88 Revised – M&P (8/13/1992) Arkansas Producers 88 Revised – M&P (12/29/1995)

²³ M. Keith Blythe, Hanna Oil and Gas v. Taylor: Compression Costs in Oil and Gas Leases---Who Pays?, 43 Ark. Law. Rev. 201, at 215 This case subsequently settled, and the judgment and opinion was set aside, 760 S.W.2d 960 (Tex. 1988)

²⁴ Hagen, 683 S.W. 2d at 28 (citing Gentry v. Credit Plan Corp. of Houston, 528 S.W.2d 571 (Tex. 1975), and Bell Oil & Gas Co. v. Allied Chem. Corp. 431 S.W.2d 336 (Tex. 1968)

²⁵ Hanna Oil and Gas Co. v. Taylor, 759 S.W.2d 563, 297 Ark. 80 (Ark. 1988)

²⁶Arkansas Producers 88 Revised M&P (12/29/1995)

²⁷M. Keith Blythe, Hanna Oil and Gas v. Taylor: Compression Costs in Oil and Gas Leases---Who Pays?, 43 Ark. Law. Rev. 201, at 215

²⁸This case subsequently settled, and the judgment and opinion was set aside, 760 S.W.2d 960 (Tex. 1988)

²⁹Hagen, 683 S.W. 2d at 28 (citing Gentry v. Credit Plan Corp. of Houston, 528 S.W.2d 571 (Tex. 1975), and Bell Oil & Gas Co. v. Allied Chem. Corp. 431 S.W.2d 336 (Tex. 1968)

³⁰Hanna Oil and Gas Co. v. Taylor, 759 S.W.2d 563, 297 Ark. 80 (Ark. 1988)