CHAPTER 2 CUSTOMIZING THE OIL AND GAS LEASE FROM THE LESSEE'S PERSPECTIVE
| Jurisdiction | United States |
CUSTOMIZING THE OIL AND GAS LEASE FROM THE LESSEE'S PERSPECTIVE
Santoyo Moore Wehmeyer P.C.
San Antonio, TX
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KATY WEHMEYER advises oil and gas exploration and production companies in oil and gas acquisitions, sales, leasing and operations, title examination and due diligence. Katy also advises landowners and energy companies regarding lease and land management issues. She is board certified in Oil, Gas and Mineral Law by the Texas Board of Legal Specialization.
EDUCATION/ADMISSIONS:
• The University of Texas School of Law, J.D., with honors, 2006
• Baylor University, B.A., magna cum laude, 2002
• Texas, 2006
• Oklahoma, 2015
• New Mexico, 2016
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I. Introduction
Over a century since it first came into existence,1 the oil and gas lease remains a critical component of oil and gas production in the United States. And while modern leases match their predecessors in history in terms of basic purpose and importance, today's leases have grown in length and complexity.
This Article is not intended as a drafting guide or a full discussion of every possible lease provision, which could each be the subject of an entire article or treatise. Instead, this Article simply aims to highlight certain areas of concern for lessees and provide tips for addressing them. It proceeds in roughly the same order as one would expect a typical oil and gas lease to. And although the Article applies Texas law, its basic message is equally applicable to other jurisdictions: know the default rules and the governing provisions in your lease and how the lease varies from the default.
II. Royalty Clause
No one disputes lessors are entitled to payment. But the devil is in the details. How much is the lessor entitled to? When is the lessor entitled to payment? What happens if the lessee fails to pay? What follows is a discussion of the lessee's primary considerations with respect to royalty clauses.
A. Method of Valuation.
1. Fair Market Value
Many leases provide that the lessor's royalty will be calculated based on the "fair market value" of production. Generally, "market value" is defined as "the price property would bring when it is offered for sale by one who desires, but is not obligated to sell, and is bought by one who is under no necessity of buying it."2 However, although the definition is easy enough to state, actually supplying meaning to that phrase in the context of a royalty clause can be a difficult task and fodder for expensive litigation. As one court succinctly put it, "Many elements go into the makeup of fair market value."3 For instance, what method does a lessee use to determine what "market value" is? Without a reference in the clause to a particular price index, a lessee must look elsewhere to calculate the market value of the production. There are two principal methods of ascertaining market value: the comparable sales method and the net-back method.4 According to the Texas Supreme Court, "[t]he most desirable method is to use comparable sales."5 Comparable sales are those that are comparable in time, quality, and availability of marketing outlets.6 However, such sales may not exist, meaning this method is not always available.7 And by tying the calculation of royalty payments to only those sales that are "comparable," using the fair market value method provides job security to litigators and expert witnesses, as lawsuit often devolve into a battle of the experts over whether a given sale is truly "comparable."8 Each sale's relevance is determined in reference
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to several factors, each of which can be the focus of expensive litigation and provides lawyers and experts with plenty to argue over. When information about comparable sales is not "readily available," courts use the net-back method.9 This method entails subtracting reasonable post-production marketing costs from the market value at the point of sale.10 The net-back approach is not without its own difficulties, however, because what constitutes a reasonable post-production costs can be the subject of vigorous dispute, as discussed below. Ultimately, determining what a lessor is owed under a fair market value lease can be somewhat like determining how many angels can dance on the head of a pin.
Lessees must not only be mindful of what method is used to calculate fair market value but also of where the production is valued. Some leases provide for market value to be determined at the well, which is ideal for lessees and should be seriously considered if offered. Other leases may provide for value to be measured at the point of sale or the point of use. It is important for lessees to be aware of these variations and what a particular lease provides in determining the amount due to the lessor.
2. Proceeds
Instead of providing for royalty payments to be based on the fair market value of production, some leases look to the proceeds from the sale of production to compute the lessor's royalty.11 In other words, instead of turning on the hypothetical value of the minerals produced, proceeds royalty clauses tie the lessor's royalty to the amount the lessee actually received from the sale of such minerals.12 This makes it much easier to calculate the payments due to the lessor because instead of undertaking the complicated process of determining fair market value, a lessee can simply look to what it actual received from the sale of production. However, proceeds-based clauses are not without their own nuances. For one, Lessees must be aware of whether the royalty is paid on gross proceeds or on net proceeds.
Proceeds leases also pose a conceptual problem with respect to "lease use gas," which refers to the hydrocarbons consumed by the lessee in its operations of the lease are immediately used after being produced. Produced gas is not sold, so there are no proceeds upon which to base royalty. Some leases may account for this by providing that the lessee must pay market value on lease use gas.
Finally, as with market value clauses, lessees under proceeds leases must be mindful of where they are to value the sale. The lease typically designates the well head or the point of sale at the point of valuation for calculating proceeds. The point of sale is determined by the lessee's sales agreements.
3. A Combination of Methods
Some leases provide for a combination of the above-mention methods, and require that the lessor be paid according to the one that would result in the greatest royalty payments. Lessees should resist these clauses if possible because they constitute a substantial administrative burden. For example, imagine a lease that provides for royalty on the higher of either a percentage of net proceeds or fair market value. Under such a lease, the lessee would need to determine which is higher every time it paid its lessor. Not only is this a lot to keep track of, but it also creates a lot of room for error (and lawsuits).
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13 B. Deductibility of Post-Production Costs
"Royalty is commonly defined as the landowner's share of production, free of expenses of production." In other words, post-production costs (i.e., those that occur after the wellhead) are generally deductible when calculating royalty.14 Naturally, lessees would prefer as many costs be deductible as possible. While a full discussion of what constitutes a post-production cost is outside of the scope of this Article, the Texas Supreme Court has given the following as examples: taxes, treatment costs to render production marketable, and transportation costs.15 Because it is possible for parties to agree post-production costs may not be deducted, lessees must be mindful during lease negotiation of the post-production expenses they intend to deduct and make sure the lease provides for such deduction. This is often a carefully negotiated item in the context of more sophisticated lessors.
C. Timing of Payment, Division Orders, and Consequences for Payment Errors
Even in the absence of specific lease provisions, payors16 have a statutory obligation under Texas Natural Resources Code § 91.402 to pay "payees" (i.e., a lessor) their share of the proceeds from the sale of production on or before 120 days after the end of the month of first sale of production from the well.17 The statute contains several "safe harbor" provisions that allow payors to withhold payment beyond the statutory time limits without interest when there is:
(A) a dispute concerning title that would affect distribution of payments;
(B) a reasonable doubt that the payee:
(i) has sold or authorized the sale of its share of the oil or gas to the purchaser of such production; or
(ii) has clear title to the interest in the proceeds of production; or
(C) a requirement in a title opinion that places in issue the title, identity, or whereabouts of the payee and that has not been satisfied by the payee after a reasonable request for curative information has been made by the payor . . . . 18
The statute further entitles payors to receive a signed division order from payees as a precondition to payment. Section 91.402(c)(1) states: "As a condition for the payment of proceeds from the sale of oil and gas production to payee, a payor shall be entitled to receive a signed division order from payee containing [several] provisions . . . ."19 And section 91.402(e) provides: "If an owner in a producing property refuses to sign a division order which includes only the provisions specified in Subsection (c) of this section, payor may withhold payment without interest until such division order is signed."20 Thus, the statute confers on
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payors the right to withhold payments until a payee has signed a division order that complies with the statute.21
However, parties may freely alter the statutory timetables by including their own requirements in their leases.22 Texas courts have not been clear regarding whether the...
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