Lease Provisions

The Shut-in Royalty Provision: Isn’t It Just for Gas?

Fee Lease 101 Series, Lease Provisions, Royalty Issues, , , ,

With the advent of the shale oil revolution, the significance of some traditional oil and gas lease provisions, such as the shut-in royalty provision, have been recently neglected. As a result, landmen may be asking themselves, “What is the shut-in royalty provision and will it ever impact a lease taken in an oil play?” The resounding answer is YES! Although a more traditional tool for gas plays, a shut-in royalty provision may apply to either a gas or oil well depending on the language used.

What is this thing anyway?

Nearly all oil and gas leases include a habendum clause,1 which allows a lease to be held in effect for a period of time and so long thereafter as oil and gas is produced in paying quantities. However, production can cease or be temporarily suspended for a number of reasons. Without a savings clause, even a brief a cessation in production would cause a lease past its primary term to expire. In light of this, lessees developed the shut-in royalty provision, among other savings clauses. Essentially, the shut-in royalty provision allows a lessee to temporarily cease production (i.e., shut-in a well) and pay a shut-in royalty to the lessor in place of the royalty on production that is not occurring during the shut-in period. The following is a typical, older shut-in royalty provision, created specifically for a gas well:

[W]here gas from one or more wells producing gas is not sold or used, lessee may pay as royalty $500.00 per year, and upon such payment it will be considered that gas is being produced within the meaning of Paragraph 2 [the habendum clause] hereof.2

The following is another, older example, used for either an oil or gas well:

This lease shall continue in full force for so long as there is a well or wells on leased premises capable of producing oil or gas, but in the event all such wells are shut in and not produced by reason of the lack of a market at the well or wells, by reason of Federal or State laws, executive orders, rules or regulations, or for any other reason beyond the reasonable control of Lessee, then on or before such succeeding anniversary of the date hereof occurring ninety (90) or more days after all such wells are so shut in and after the expiration of the primary term and prior to the date production is commenced or resumed, or this lease surrendered by Lessee, Lessee shall pay to Lessor as royalty an amount equal to the annual rental hereinabove provided for.3

There are numerous variations of the shut-in royalty provision, many of which may not be ideal for the lessee’s operations. For example, the provision might be focused on shutting-in a well for the purpose of finding a buyer of natural gas, dewatering a coalbed methane well, or repairing broken-down equipment. Although this article cannot discuss all of the variations, there are numerous additional resources on this subject.4

Aww shucks, the crank broke again!

Although the shut-in royalty provision may have been historically created to protect a lessee in the event that there is a lack of a market for gas, a lessee might use it for numerous other reasons. Some additional causes include: governmental restrictions, inability to economically produce the leased substances, lack of available linear infrastructure, equipment failure, or Force Majeure.5 Many older shut-in royalty provisions provide specific reasons to shut-in a well, while most newer versions are silent on the matter. If silent, a court will determine whether or not the cause for the temporary cessation was reasonable. While there is comfort in expressly describing the allowed causes for the temporary cessation, this could potentially lead to an unfavorable outcome for the lessee. Unless the lessee is aware of certain circumstances that might occur, the better approach may be to choose a shut-in royalty provision that allows the lessee to use its good faith judgment. In any event, it should be noted that some courts have required a well to be physically able to produce if it were turned on, based on the historic development of this clause (but see the discussion below under shale oil).6

Uh… did we pay that shut-in royalty on time?

Many older shut-in royalty provisions require the payment of a shut-in royalty to be paid in order for the lease to be considered held by production (e.g., the first example above). Over time, lessees realized that structuring the shut-in royalty payment as a condition may cause the lease to expire if the payment is not timely made.7 As a result, newer versions structure the shut-in royalty provision as a covenant rather than a condition. In other words, the existence of a shut-in well maintains the lease in effect, not the payment of the shut-in royalty (e.g., the second example above).

If the shut-in royalty provision is silent regarding the timing of payment (e.g., the first example above), a court will determine a reasonable time.8 If the shut-in royalty provision provides the timing of payment, it typically does so by using a specific time period (e.g., within 90 days), a specified date (e.g., on the anniversary of the lease date), or a combination of both (e.g., on the next anniversary date of the lease occurring 90 days after the well is shut-in, such as in the second example above). Generally, it is more practical to expressly provide the timing of payment and for such timing to be after the well is shut-in so that the shut-in provision won’t be triggered if the well is only shut-in for a brief period of time.

Wait, you mean that “oll” company can hold my lease forever?

Arguably, a lessee is expected to resume production from a shut-in well within a reasonable time. However, in order to avoid potential disputes and to limit what is a reasonable time period, mineral owners developed additions to the shut-in royalty provision. The following examples are illustrative:

Notwithstanding the provisions of this section to the contrary, this lease shall not be continued after ten years from the date hereof for any period of more than five years by the payment of said annual royalty;

[P]rovided, however, that in no event shall Lessee’s rights be so extended by shut-in royalty payments for more than two (2) years beyond the primary term; or

[T]he Lessee may extend this lease for two (2) additional and successive periods of one (1) year each by the payment of a like sum of money each year on or before the expiration of the extended term.9

Such additions to the shut-in royalty provision may prove useful in the event the parties to the lease cannot agree on whether or not a shut-in royalty provision should be included in the lease.

I can’t use this for horizontal oil wells, can I?

Okay, it’s finally time to answer the question, “What about the shale oil revolution – can we use the shut-in royalty provision for wells awaiting completion?” Because such a well is not capable of producing, typical shut-in royalty provisions won’t apply. The good news is that this can be easily fixed by expanding the term “capable of producing quantities” (after ensuring that the provision covers oil as well as gas).10 For example, a lessee could add the following after the shut-in royalty provision:

A well that has been drilled and cased shall be deemed capable of producing oil and gas in paying quantities, notwithstanding the fact that any such well has not been perforated, fractured, or otherwise completed.11

If the parties can’t agree on this broad expansion, the timing for such uncompleted wells could be limited (e.g., “…shall be deemed capable of producing oil and gas in paying quantities for a period not to exceed 180 days…”).12 Alternatively, the parties could agree to limit the expansion to specific types of wells (e.g., shale wells, coalbed methane wells, or horizontal wells).13

Fine. Just tell me which form of shut-in royalty provision to use.

As previously discussed, there are numerous forms and variations of the shut-in royalty provision. Of course, there is no one-size-fits-all. The shut-in royalty provision used in a lease form should be carefully selected to meet the needs of the lessee’s operations and regularly modified as technology advances and oil and gas plays shift. Although it won’t apply to all scenarios, the following example appears to embrace most of the key concepts discussed in this article:

If after the primary term one or more wells on the leased premises or lands pooled or unitized therewith are capable of producing Oil and Gas Substances in paying quantities, but such well or wells are either shut in or production therefrom is not being sold by Lessee, such well or wells shall nevertheless be deemed to be producing in paying quantities for the purpose of maintaining this lease. If for a period of 90 consecutive days such well or wells are shut in or production therefrom is not sold by Lessee, then Lessee shall pay an aggregate shut-in royalty of one dollar per acre then covered by this lease. The payment shall be made to Lessor on or before the first anniversary date of the lease following the end of the 90-day period and thereafter on or before each anniversary while the well or wells are shut in or production therefrom is not being sold by Lessee; provided that if this lease is otherwise being maintained by operations under this lease, or if production is being sold by Lessee from another well or wells on the leased premises or lands pooled or unitized therewith, no shut-in royalty shall be due until the first anniversary date of the lease following the end of the 90-day period after the end of the period next following the cessation of such operations or production, as the case may be. Lessee’s failure to properly pay shut-in royalty shall render Lessee liable for the amount due, but shall not operate to terminate this lease.14

Depending on the circumstances, the parties to a lease may desire to expand the term “capable of producing quantities” for an incomplete well or limit the maximum amount of time a well may be shut-in, as each is discussed above.

1See, generally, Trent Maxwell, The Habendum Clause – ‘Til Production Ceases Do Us Part,’ available at http://www.hollandhart.com/lease-provisions-part-2/.
2From a midcontinent form discussed in Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 631 (2014).
3Id.
4See Martin & Kramer, supra note 2 at §§ 631 et seq.; John S. Lowe, “Shut-in Royalty Payments,” 5 Eastern Min. L. Inst. 18 (1984); Robert E. Beck, “Shutting-In: For What Reasons and For How Long?,” 33 Washburn L.J. 749 (1994); David E. Pierce, “Incorporating a Century of Oil and Gas Jurisprudence into the ‘Modern’ Oil and Gas Lease,” 33 Washburn L.J. 786 (1994); Thomas W. Lynch, “The ‘Perfect’ Oil and Gas Lease (an Oxymoron),” 40 Rocky Mt. Min. L. Inst. 3 (1994).
5See Martin & Kramer, supra note 2 at § 632.4.
6See, e.g., Hydrocarbon Mgmt., Inc. v. Tracker Exploration, Inc., 861 S.W.2d 427 (Tex. Ct. App. 1993); see also Milam Randolph Pharo & Gregory R. Danielson, “The ‘Perfect’ Oil and Gas Lease: Why Bother,” 50 Rocky Mt. Min. L. Inst. 19 (2004).
7See, e.g., Freeman v. Magnolia Petroleum Co., 171 S.W.2d 339 (Tex. 1943); see also Pharo, supra note 6.
8See Martin & Kramer, supra note 2 at § 632.6.
9See Martin & Kramer, supra note 2 at § 632.13.
10John W. Broomes, “Spinning Straw into Gold: Refining and Redefining Lease Provisions for the Realities of Resource Play Operations,” 57 Rocky Mt. Min. L. Inst. 26, 26–5 (2011).
11Id. at 26–9.
12Id. at 26–10.
13Id.
14From the Modified Lynch Form. Pharo, supra note 6 at Appendix A.

Deducting Post-Production Costs From Fee Royalty

Fee Lease 101 Series, Lease Provisions, Royalty Issues, , ,

The phone rings. It’s your owner relations department. They just received a call from a lessor who has been taking a closer look at the information provided along with the lessor’s oil and gas royalty checks. The lessor wants to know why you are deducting post-production costs, such as transportation or compression of gas, when calculating the lessor’s royalty.

The deductibility of post-production costs can have significant implications for an oil and gas lessee. Several commentators have addressed this issue in-depth over the years.1 This article is intended to provide an introduction to the deductibility of post-production costs under fee oil and gas leases.2

Production Costs vs. Post-Production Costs

Normally, the lessee under an oil and gas lease, not the lessor, is responsible for paying the expenses of exploration and production.3 These generally include the costs associated with geophysical surveying, drilling, testing, completing, and reworking a well, as well as secondary recovery.4

Post-production costs that may, or may not, be deductible when calculating the royalty generally include gross production and severance taxes, transportation costs, and the costs of dehydrating, compressing, or otherwise processing gas (such as the extraction of liquids from gas or casinghead gas).5

Lease Provisions

When determining whether post-production costs are deductible from the royalty, the lease should be carefully examined. Sometimes the lease terms will specify whether post-production costs are deductible. For example, as part of the royalty clause, a lease may provide:

Lessee shall have the right to deduct from Lessor’s royalty on any gas produced hereunder the royalty share of the cost, if any, of compression for delivery, transportation and/or delivery thereof.6

But what if the lease does not include a provision such as the one above? Or what if the lease provides for the payment of royalty based on market value or net proceeds “at the well”7 but does not spell out the types of post-production costs that are deductible before the royalty is calculated? Is that enough?

“At the Well”

The following is an example of a gas royalty provision with “at the well” language:

Royalties to be paid by Lessee are: . . . (b) on gas, including casinghead gas or other gaseous substance, produced from said land and sold or used, the market value at the well of one-eighth (1/8) of the gas so sold or used, provided that on gas sold at the well the royalty shall be one-eighth (1/8) of the amount realized from such sales[.]8

Bice v. Petro-Hunt, L.L.C.9 provides an example of the majority view on deducting post-production costs when the royalty clause contains “at the well” language.10 In Bice, the North Dakota Supreme Court determined whether processing costs for sour gas were properly deducted when calculating the royalty under oil and gas leases that contained “market value at the well” language. The Court noted that the majority of oil and gas producing states have adopted the “at the well” rule and “interpret the term ‘market value at the well’ to mean royalty is calculated based on the value of the gas at the wellhead.”11 The Court also noted that in states that have adopted the “at the well” rule,12 a lessee has the option of calculating the market value at the well through the “comparable sales method” or the “work-back” (a/k/a “net-back”) method.13 The comparable sales method involves “‘averaging the prices that the lessee and other producers are receiving, at the same time and in the same field, for oil or gas of comparable quality, quantity, and availability.’”14 Under the work-back method, the “market value at the well” is determined by deducting reasonable post-production costs (incurred after the product is extracted from the ground) from the sales price received at a downstream point of sale.15

The Court found that the gas at issue had “no discernible market value at the well before it is processed . . . .”16 The Court reasoned that “[s]ince the contracted for royalty is based on the market value of the gas at the well and the gas has no market value at the well, the only way to determine the market value of the gas at the well is to work back from where a market value exists . . . .”17 Adopting the “at the well” rule, the Court held that the operator properly deducted post-production costs for processing prior to calculating the royalty.18

A similar result was reached in Emery Resource Holdings, LLC v. Coastal Plains Energy, Inc.19 In Emery, the federal district court in Utah was asked to interpret oil and gas leases that contained “at the well” royalty clauses20 and determine whether post-production gathering and processing costs were deductible.21 The Court noted that “[t]he majority of courts . . . have found ‘at the well’ royalty clauses to mean that natural gas is valued for royalty purposes at its wellhead location and condition.”22 Predicting what a Utah court would do when faced with this situation,23 the Court inEmery held that the “at the well” language in the leases was clear and that the parties intended for the royalty to be calculated according to the market value at the well.24 Thus, the Court allowed the operator to deduct post-production costs incurred from the wellhead separators to the pipeline in determining the market value at the well prior to calculating the royalty.25

In some states, however, including the words “at the well” in the royalty provision may not be enough. For example, inRogers v. Westerman Farm Co.26 the Colorado Supreme Court determined whether post-production costs were properly deducted under leases that provided for royalty “at the well” or “at the mouth of the well.” The Court held that the leases were “silent” as to the allocation of post-production costs, even with “at the well” language.27 The Court held that “[a]bsent express lease provisions addressing allocation of costs, the lessee’s duty to market requires that the lessee bear the expenses incurred in obtaining a marketable product. Thus, the expense of getting the product to a marketable condition and location are borne by the lessee.”28 After the product is “marketable,” any further costs incurred in improving the product or transporting it may be shared by the lessor and lessee.29 The point at which the gas is “marketable” is a question of fact for the judge or jury to decide.30 Thus, in Colorado,31 lease language that defines the royalty as being payable “at the well” or “at the mouth of the well” is not enough to allocate post-production costs.32

Conclusion

Now is the time for lessees under fee oil and gas leases to carefully examine their records, on a lease-by-lease basis, and determine whether they are properly deducting post-production costs prior to calculating the royalty. The deductibility of post-production costs depends on the lease terms and the laws of the state where the leased lands are located. Lessees should not, and in some states cannot, rely on “at the well” language to provide for the deduction of post-production costs. As needed, lessees should modify their lease forms to specifically provide for the deduction of post-production costs and identify all of the post-production costs that are deductible.


How to increase attention to detail in title examination.

1See Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 645, Footnote 1 (2014) for citations to such articles.
2This article is not intended to provide a comprehensive analysis of the law on the deductibility of post-production costs or the law of any particular jurisdiction. The reader should consult with competent legal counsel regarding the law that applies to any particular situation and jurisdiction.
3Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 645.1 (2014).
4Id.
5Id. § 645.2.
6Id. § 643 (quoting a Mid-Continent lease form).
7The term “at the well” is often included in the royalty clause of an oil and gas lease in defining the point of valuation of the oil and gas. Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Manual of Oil and Gas Terms 63 (2009).
8Brown, The Law of Oil and Gas Leases, 2nd Edition § 6.13 (2014) (emphasis added).
9768 N.W.2d 496 (N.D. 2009).
10Id. at 499.
11Id. at 500-501 (citing Byron C. Keeling & Karolyn King Gillespie, The First Marketable Product Doctrine: Just What is the Product?, 37 St. Mary’s L.J. 1, 51 (2005); Edward B. Poitevent, II, Post-Production Deductions from Royalty, 44 S. Tex. L. Rev. 709, 716 (2003); and Brian S. Wheeler, Deducting Post-Production Costs When Calculating Royalty: What Does The Lease Provide?, 8 Appalachian J.L. 1, 7 (2008)).
12The Court noted that Louisiana, Mississippi, Texas, California, Kentucky, Montana, and New Mexico follow the “at the well” rule. Bice, at 501 (citing Babin v. First Energy Corp., 96 1232, p. 2 (La. App. 1 Cir. 3/27/97); 693 So.2d 813, 815;Heritage Res., Inc. v. NationsBank, 939 S.W.2d 118, 122 (Tex. 1996); Piney Woods Country Life Sch. v. Shell Oil Co., 726 F.2d 225 (5th Cir. 1984) (interpreting Mississippi law); Elliott Indus. Ltd. P’ship v. BP America Prod. Co., 407 F.3d 1091, 1109–10 (10th Cir. 2005); Atlantic Richfield Co. v. State, 214 Cal. App. 3d 533, 262 Cal.Rptr. 683, 688 (1989);Montana Power Co. v. Kravik, 179 Mont. 87, 586 P.2d 298, 303 (1978); Reed v. Hackworth, 287 S.W.2d 912, 913 (Ky. 1956)).
13Bice, at 501.
14Id. (quoting Keeling & Gillespie, supra, at 31-32).
15Id. (quoting Keeling & Gillespie, supra, at 32).
16Id. at 502.
17Id. The Court noted that the comparable sales method was unavailable to calculate the royalty in this case because “no comparable sales exist since the gas is not saleable at the wellhead.” Id.
18Id. For an in-depth analysis of the Court’s decision in Bice, see David E. Pierce, Royalty Jurisprudence: A Tale of Two States, 49 Washburn L.J. 347, 370-374 (2009).
19915 F.Supp.2d 1231 (D. Utah 2012).
20Most of the leases included the words “at the well” in the royalty clause. Id. at 1237. Two of the leases provided for royalty on “the proceeds from the sale of the gas, as such, for gas from wells where gas only is found . . . .” Id. at 1238. The Court examined the language surrounding this clause and concluded that “the parties intended all products produced from the wells to be valued at the prevailing market rate at the wellhead” rather than “some location downstream and away from the leased premises.” Id. at 1238-39.
21Id. at 1235.
22Id. at 1240 (citations omitted).
23Noting that the Utah Supreme Court has not directly ruled on the deductibility of post-production costs in oil and gas operations, the Court in Emery looked to the Utah Supreme Court’s decision in Rimledge Uranium and Mining Corp. v. Federal Resources Corp., 374 P.2d 20 (1962). Emery, at 1241. In Rimledge, the Utah Supreme Court found that where a deed of uranium mining claims provided for a royalty of 15% “of all gross proceeds from the sale of ore,” the parties intended for the royalty to be based on the sale proceeds of raw ore, or the fair market value of raw ore in the vicinity, rather than the value of concentrated ore after processing in the mill. Emery, at 1242.
24Id.
25Id.
2629 P.3d 887 (Colo. 2001).
27Id. at 902.
28Id.
29Id.
30Rogers, at 906.
31Other states that have rejected the “at the well” rule include Arkansas, Oklahoma, Kansas and West Virginia. Bice, supra, at 501 (citing Keeling & Gillespie, supra, at 51; Wheeler, supra, at 10).
32For an in-depth analysis of the Court’s decision in Rogers, see Pierce, supra, at 358-364; see also Martin & Kramer,supra, at § 645.

The Habendum Clause – ‘Til Production Ceases Do Us Part

Fee Lease 101 Series, Lease Provisions, , , ,

The habendum clause is a fundamental provision of oil and gas leases. This clause (also called the term clause) sets forth the time period that the rights granted to the lessee under the lease are extended—i.e. how long the lease will be active.1

Basics

An habendum clause in an oil and gas lease typically contains two separate terms, the primary term and the secondary term. The primary term is a fixed period of time during which the lessee has the option, but not the obligation, to pay delay rentals and/or explore for and produce oil and gas. No actual production is necessary to keep the lease active during the primary term. Ten years used to be a common primary term; however, shorter primary terms (e.g. 1 to 5 years) are often seen in areas with proven fields or anticipated drilling.2 As with other lease terms, its length can be negotiated by the lessor and lessee; the relative bargaining power between the parties and the amount of bonus a lessee is willing to pay are important in determining term length.3

At the expiration of the primary term, the lease terminates as a matter of law unless production4 is achieved during the primary term. The time period under the secondary term is indefinite—so long as lease substances are produced, the lease remains in effect. While many leases expire at the end of the primary term without production, if production is achieved, it is not uncommon for oil and gas leases to be held by production for many years.

In having both a primary and secondary term, the interests of both lessors and lessees are represented. The fixed primary term protects lessors from having their mineral interests endlessly tied up without production and encourages development on the land. If production is not achieved by the lessee within the primary term, the lease terminates (unless otherwise extended, such as by other lease terms) and the lessor is free to re-lease his or her mineral interests. Conversely, if production is achieved, the lessee’s risk in expending substantial sums to develop the land is rewarded by extending the lease so long as production continues.5

Formulation

Although there are numerous variations of habendum clauses, a typical habendum clause will read substantially as follows:

[T]his lease shall remain in force for a term of ___ years from this date, and as long thereafter as oil or gas or either of them is produced from said lands.6

Additionally, the phrase “produced in paying quantities” or “produced in commercial quantities” is commonly included in the clause, along with phrases allowing for production to come from lands pooled or unitized with the leased lands.7

Meaning of “Produced”

As noted above, the typical habendum clause requires that oil or gas be “produced” from the leased land to extend the lease beyond its primary term. In most states, “produced” means exactly that—oil or gas must actually be produced from the leased land. A minority of states, including Oklahoma and West Virginia, hold that discovery of oil or gas is sufficient—no production is actually necessary—to extend the lease beyond its primary term, although the well must be completed and capable of production, and the lessee must make diligent efforts to market.8 Another minority of states, including Montana and Wyoming, appear to differentiate between oil and gas, with the discovery of gas being sufficient to extend the lease beyond the primary term, while actual production for oil is necessary to extend.9 The distinction arises because oil can be produced and stored economically while gas generally cannot be stored economically above the ground.10

Some habendum clauses include language that the lease will be extended “so long as oil or gas is capable of being produced in paying quantities.” In such instances, actual production is not necessary to extend the lease beyond its primary term, but may require a well that can be turned “on” to produce in paying quantities without the addition of extra equipment or repair.11

Once the lease is extended into the secondary term, if production ceases the lease automatically terminates (unless otherwise extended by a different provision in the lease).12 However, courts have held that it is not required that production be entirely continuous throughout the extended term to hold the lease. Courts recognize that production may temporarily cease due to repairs, breakdowns, and reworking operations.13 Where the lease is silent, and cessation in production is litigated, the burden of proof rests on the lessee to show that the cessation was for a reasonable reason and for a reasonable amount of time. Courts vary in what constitutes a reasonable amount of time.14 For example, one court held that a four-year cessation in production was “temporary,” while another court held that a six-month cessation was “permanent.” To provide more certainty in the face of inconsistent court rulings, modern oil and gas leases often include a “cessation of production” clause that specifies when production must be continued after cessation for the lease to not terminate.15

Meaning of “Produced in Paying Quantities”

A question that frequently arises when construing an habendum clause is how much production is necessary—i.e. is any amount of production sufficient to hold the lease, or must the production reach a certain level? As noted above, modern oil and gas leases commonly include the qualification that production be in “paying” or “commercial” quantities. For leases that only state “production” is required, courts generally have construed the clause to include this qualification. Thus, regardless of whether the lease includes the qualification “in paying quantities,” the term “produced” typically means “produced in paying quantities.”16

The question then becomes what constitutes “produced in paying quantities.” The Kansas Court of Appeals stated the general rule:

[T]he phrase “in paying quantities” as used in an oil and gas lease habendum clause means production of quantities of oil or gas sufficient to yield a profit to the lessee over operating expenses, even though the drilling costs or equipping costs are never recovered, and even though the undertaking as a whole may thus result in a loss to the lessee.17

Put simply, a lease is considered “producing in paying quantities” if production revenue is greater than operating expenses.

In determining production revenue, any royalty paid to the lessor is excluded, although any payment to overriding royalty owners generally are included as revenue.18 For operating expenses, any direct costs to operate, such as labor costs, electricity for pumping units, taxes (but not income taxes) payable by the working interest owner(s), and day-to-day maintenance cost are included.19 There is some dispute among courts whether depreciation and overhead costs should be included as operating expenses.20 Initial expenditures, such as the costs of drilling, equipping, and completing are not included as operating expenses.21 Such analysis makes economic sense—after these initial expenditures, an operator will continue to operate so long as the production on a lease is marginally profitable in order to recover as much of these costs as possible.22

It is important to have a reasonable time period when evaluating production revenues against operating expenses. Leases may operate negatively in the short-term, but profitably in the long-term. One source notes that in almost every instance, a time period of at least a year was used by the courts to evaluate profitability, and frequently a time period of eighteen months to three years was used.23 In times of distressed market conditions, courts have used longer time periods or have assessed whether the lease would have been profitable under normal market conditions.24

Conclusion

An understanding of the habendum clause is crucial when negotiating a lease or when evaluating whether a lease has been held by production past its primary term. As you do so, keep in mind that other lease provisions not discussed in this article may also affect lease duration, such as shut-in royalty, pooling, unitization, Pugh, continuous operations, delay rental, and cessation of production clauses, among others. Additionally, be aware that the law varies from jurisdiction to jurisdiction, and may be different from the general principles discussed in this article.

1See PEC Minerals LP v. Chevron U.S.A., Inc., 439 F. App’x 413, 416 (5th Cir. 2011).
2John S. Lowe, Oil and Gas Law in a Nutshell (6th ed. 2014).
3Id.
4Or a lease provision that serves as a substitution for actual production such as continuous drilling operations or payment of shut-in royalty.
5Lowe, supra note 2.
63 Patrick H. Martin & Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 603.3 (2014).
7Id.
8See McVicker v. Horn, 322 P.2d 410 (Okla. 1958); Eastern Oil Co. v. Coulehan, 64 S.E. 836 ( W. Va. 1909).
9See Severson v. Barstow, 63 P.2d 1022 (Mont. 1936); Pryor Mt. Oil & Gas Co. v. Cross, 222 P. 570 (1924).
10See 2 Eugene Kuntz, A Treatise on the Law of Oil and Gas § 26.6 (rev. ed. 2014). See also Lowe, supra note 2.
11Martin & Kramer, supra note 6.
12See Anadarko Petroleum Corp. v. Thompson, 94 S.W.3d 550, 554 (Tex. 2002).
13Martin & Kramer, supra note 6, at § 604.4.
14Id.
15Id. See also Dave Hatch, Potential Pitfalls of Continuous Drilling Provisions in HBP Fee Leases (Apr. 10, 2014), available at: http://www.hollandhart.com/pitfalls-of-continuous-drilling-provisions-in-hbp-fee-leases/.
161 Earl A. Brown, Earl A. Brown, Jr., & Lawrence T. Gillaspia, The Law of Oil and Gas Leases § 5.03 (2d ed. 2014).
17Avien Corp. v. First National Oil, Inc., 79 P.3d 223, 230 (Kan. Ct. App. 2003); see also Maralex Res., Inc. v. Gilbreath, 76 P.3d 626, 630 (N.M. 2003) (“To satisfy the habendum clause production must be in ‘paying quantities,’ such that the income generated from oil and gas production exceeds the operating costs.”).
18Lowe, supra note 2.
19Id. See also Martin & Kramer, supra note 6, at § 604.6(b).
20Martin & Kramer, supra note 6, at § 604.6(b).
21Kuntz, supra note 10, at § 26.7.
22Martin & Kramer, supra note 6, at § 604.6(b).
23Lowe, supra note 2.
24Id. See also Kuntz, supra note 10, at § 26.7.

The Granting Clause: The Gift That Keeps on Granting

Fee Lease 101 Series, Lease Provisions, Title Issues/Curative,

The granting clause of a lease contains the required words of grant that create an interest in the lessee.1 This clause is typically found at the beginning of the lease and is often overlooked when drafting a lease, to the detriment of the lessee. The granting clause generally covers three main topics: (i) the leased substances; (ii) the associated easement rights; and (iii) the property description.

Leased substances

The granting clause should include a careful description of the substances covered by the lease. Typical granting clauses include language such as “oil, gas, and other minerals,”2 “oil and all gas of whatsoever nature or kind,”3 or some variation of these simplistic descriptions. Even though this language may, at first glance, seem uncontroversial, the failure to adequately list the substances covered by the lease has led to a multitude of lawsuits.

For example, the failure to adequately define the leased substances can lead to questions whether the lease covers coalbed methane, which depending on the state, may not be included in a general grant of gas. Another problem is encountered when interpreting what is included in the “other minerals” under a lease. The parties to a lease should not rely on a court to dictate what substances are covered by that lease.

As a practical matter, the goal in drafting the leased substances portion of the granting clause is to ensure that the lease covers all substances that are necessary to produce the oil and gas from the leasehold. Any special substances that may be encountered, such as coalbed methane, helium, carbon dioxide, hydrogen, or sulfur, should be individually listed in the lease. By including a list of known or expected substances, together with catch-all language to cover substances that may not yet be known or expected in the field, the lessee can avoid unfavorable interpretations by a court that could render the lease unprofitable or unusable.

Associated Easement Rights

The second part of the granting clause is the description of the easement granted to the lessee. Historically, the grant of an easement and the right to conduct surface operations has been broadly, if not vaguely, described in the lease. The lessee has, instead, relied on the implied right of access to the surface estate arising from the mineral estate’s dominance. Reliance on this implied right of access can be problematic when the surface owner engages in activities that prevent or inhibit oil and gas development or when the surface owner disagrees with and challenges the lessee’s use of the surface estate.

As for split estate lands, the lessee should be careful to ensure that the lease does not grant and that the lessee does not rely on a right of access that was not reserved or conveyed in the deed creating the split estate. Keep in mind that the lessor can only grant the rights that the lessor owns.

To avoid these issues, I recommend that this portion of the granting clause describe the specific activities that the lessee will be conducting on the leased premises, such as construction and location of the various production facilities, powerlines, roads, pipelines, and any other activity that may foreseeably be required to produce the oil and gas. By describing the specific activities, the surface owner is put on notice of the types of activities that the lessee is planning to conduct on the surface estate. If a lawsuit ensues, it will be very difficult if not impossible for the surface owner to argue that they were unaware that the surface would be used for these activities.

I note also that, even though the lessee, through careful drafting of the lease, may be able to secure surface access for gathering facilities and other surface disturbance activities not related to production of oil and gas from the leasehold, this grant of access could be terminated upon expiration of the lease term. For such activities, I recommend that the lessor obtain a separate surface use agreement specifically granting the right to conduct these activities to ensure that they survive termination of the lease.

The Leased Premises

Finally, the granting clause should include a description of the land covered by the lease. This should, of course, include a legal description of the property together with the acreage covered by the leasehold. For small or irregular tracts of land, the lease should include a Mother Hubbard clause4 to ensure that inadequately described property that is adjacent to and contiguous with the leasehold will be covered by the lease.

In the event that the lease is limited in depth, the property description should include language that identifies the specific interval covered by the lease, making sure that the depth description is tied to a measured depth in a specific well. A carefully crafted depth description will avoid confusion as to the actual depth covered by the lease.

Other Considerations

A common, but surprising, issue is that some granting clauses fail to include present words of grant. That is, the granting clause describes the activities that can be undertaken on the leasehold but does not expressly grant the rights to the underlying oil and gas.5

Another issue that you should be aware of is that, with horizontal drilling resulting in ever increasingly long laterals, the easement in the granting clause should include language granting the lessee a subsurface easement to accommodate horizontal development. Again, if this subsurface easement will be used for the benefit of lands located outside the leasehold, the subsurface easement should be created by a separate agreement between the parties, thereby preventing the easement from terminating with the underlying lease. Also, for a lease limited by depth, the granting language should include a subsurface easement for all depths that must be traversed in order to access the leased interval.

In summary, through careful drafting of the various components of the granting clause, the lessee can protect itself from unexpected complications and ensure that it is allowed to fully develop and produce the oil and gas resource.

1Patrick H. Martin & Bruce M. Kramer, Williams & Myers, Manual of Oil and Gas Terms 497 (12th ed. 2003).
2David E. Pierce, Incorporating a Century of Oil and Gas Jurisprudence Into the “Modern” Oil and Gas Lease, 33 Washburn L. J. 786 (1994).
3Martin & Kramer.
4A clause commonly included in contemporary leases to meet the problem of adequately describing strips of land owned by a lessor contiguous to the land specifically described by the lease and intended to be covered by the lease. Id. at 246. Also known as a cover-all clause or an all-inclusive clause.
5Pierce.

Potential Pitfalls of Continuous Drilling Provisions in HBP Fee Leases

Fee Lease 101 Series, Lease Provisions,

A common but often overlooked oil and gas lease provision is the “continuous drilling” or “continuous operations” provision. Generally, a continuous drilling provision allows a temporary cessation of production without automatically resulting in the termination of an oil and gas lease that has been extended by production. In order to qualify for the temporary cessation, certain operations (as defined in the lease or by case law) must be commenced on the leased premises or lands pooled or unitized therewith within a specified time period (typically from 30 to 120 days). Two examples are as follows:

If, at the expiration of the primary term of this lease, oil or gas is not being produced on the leased premises or on acreage pooled therewith but Lessee is then engaged in drilling or reworking operations thereon, then this lease shall continue in force so long as operations are being continually prosecuted on the leased premises or on acreage pooled therewith; and operations shall be considered to be continuously prosecuted if not more than ninety (90) days shall elapse between the completion or abandonment of one well and the beginning of operations for the drilling of a subsequent well.

If, at the expiration of the primary term, oil or gas is not being produced on said land, but lessee is then engaged in drilling or reworking operations thereon, the lease shall remain in force so long as operations are prosecuted with no cessation of more than 30 consecutive days.

Continuous drilling provisions are of particular importance when analyzing older, HBP leases. Specifically, a number of situations should be considered. Has your lease produced each and every month since the expiration of the primary term? Have you or your predecessor ceased production to rework the well or recomplete in a new formation? Have severe weather conditions caused a temporary cessation of production? Each of these situations could potentially lead to a finding that your lease has expired.

Oil and gas wells generally do not have perfect production histories. Williams & Meyers states: “Since repairs, breakdowns, and reworking operations are incidental to the normal operation of a lease, the parties must have contemplated that the temporary cessation of production caused by such events would not result in automatic termination of the lease.”1 Based upon this implied understanding, if an oil and gas lease does not contain a continuous drilling provision, the lessee may extend the lease by exercising reasonable diligence in the continuance of its operations on the leased premises. In other words, courts have held that a temporary cessation of production is allowed where no specific deadline is provided.2 What is temporary? There is no hard and fast rule. An Arkansas court found a temporary cessation where a fire destroyed a producing well and production was not resumed for four years.3 However, whether a cessation of production is temporary is a question of fact that will depend on the individual circumstances.4 Although the individual facts may vary, courts typically weigh the following factors: failure of the lessor for a substantial period of time to claim forfeiture during which time the lessee was engaged in activities on the lease, absence of drainage, intent of lessee to hold the lease, and diligence of the lessee in seeking to find a market or to resume production.5 Due to the fact-intensive nature of the analysis, each circumstance must be carefully reviewed under the applicable case law in that state.

The continuous drilling provision was created in order to provide more certainty in the face of inconsistent court rulings. While providing the parties with a more reliable test, a continuous drilling provision could prove fatal to an HBP lease. According to Williams & Meyers: “Where there are express savings provisions in a lease that specify dates [i.e., 30-120 days] by which the lessee must take certain action or the lease will terminate, the temporary cessation of production doctrine will not apply so as to extend the lease beyond those specified time limits.”6 Unlike the analysis above, the specific time periods by which a lessee must recommence operations are hard and fast.7 Absent some other lease provision, mechanical issues with the well, lack of a market, or any other delay in production could cause a lease to be deemed expired in as few as 30 days without production. Therefore, careful attention should be made to the production (and operations) history on the leased premises to ensure any continuous drilling provision has been strictly observed.

Despite a constant push for greater efficiencies in acquisition due diligence and title opinions, a thorough HBP analysis should not be forgotten. Such analysis may require obtaining well records back to the date of first production, reviewing the complete well file, and investigating the cause of any delays in production.

For More Information Contact:
David B. Hatch
Phone: 801-799-5834
Email: dbhatch@hollandhart.com

1Williams & Meyers, “Oil and Gas Law” § 604.4.
2Id.
3Saulsberry v. Siegel, 252 S.W.2d 834 (Ark. 1952).
4See Watson v. Rochmill, 155 S.W.2d 783 (Tex. 1941).
5Williams & Meyers, § 604.4 at fn. 11; see, e.g., Somont Oil Co. v. A & G Drilling, Inc., 49 P.3d 598 (Mont. 2002) (finding the intent and diligence of the operator in restoring production is a factor in determining with a cessation of production is temporary).
6Williams & Meyers, § 604.4.
7See, e.g., Greer v. Salmon, 479 P.2d 294 (N.M. 1970) (finding that where the lessee didn’t strictly comply with the 90-day cessation clause the lease terminated).

Entireties Clauses in Oil and Gas Leases: Are Mineral Owners Outside Your Unit Entitled to Proceeds?

Fee Lease 101 Series, Lease Provisions, Royalty Issues, ,

Most oil and gas leases, with certain conditions, permit the lessee to develop the leasehold as a whole, so that drilling one well on one tract covered by the lease will satisfy drilling obligations for all tracts covered by the lease. The language typically reads as follows: “if the leased premises are now or hereafter owned in severalty or in separate tracts, the tracts, nevertheless, may be developed and operated as an entirety.” Known fittingly as the “entireties clause,” by treating the lease as a whole, even if certain tracts are later carved off and sold to others, the clause relieves the lessee of the obligation to drill offset wells to protect owners of the other non-producing tracts from internal drainage.

How are royalty payments treated? Early court decisions developed what is known as the non-apportionment rule, which holds that if the tracts covered by a lease were owned by different parties, and a producing well was drilled, for example, in Bob’s tract, then Jill, who owns a neighboring tract, is not entitled to any proceeds from production from the well on Bob’s tract. The basic principle is that each separate is owner is entitled to production from his or her own tract, free from the claims of the others. The non-apportionment rule was soon recognized as unfair, especially if the lessee was under no obligation to drill offset wells. The rule left landowners like Jill receiving no benefits from production on the leasehold. To avoid the unfair result, language was inserted into the entireties clause to allow for the apportionment of royalty payments. Typical language reads as follows: “royalties shall be paid to each separate owner in the proportion that the acreage owned by him bears to the entire leased area.” Thus a balance was introduced: lessees were allowed to develop the leased premises as a whole while all lessors benefited from production from anywhere within the whole.

Entireties clauses can take any variety of forms, but the form of concern here contains royalty apportionment language. For example:

If the leased premises are now or hereafter owned in severalty or in separate tracts, the premises, nevertheless, may be developed and operated as an entirety, and the royalties shall be paid to each separate owner in the proportion that the acreage owned by him bears to the entire leased area. There shall be no obligation on the part of the lessee to offset wells on separate tracts into which the land covered by this lease may hereafter be divided by sale, devise, or otherwise, or to furnish separate measuring or receiving tanks for the oil produced from such separate tracts.

Now suppose that Bob owned an undivided fractional mineral interest in two 640-acre sections of land, and that he leased his interest in both sections to XYZ Oil in 1985. The lease included the entireties clause above. In 1990, just before the lease expired, XYZ Oil drilled a prolific well (the Titan I well) in the north section, and the well continues to produce today. The lease did not have a Pugh clause, and thus the Titan I well held both the north section and the south section by continuous production. Meanwhile, in 1995, Bob conveyed all of his interest in the south section to his sister Jill by mineral deed. In accordance with the entireties clause, Bob and Jill updated ownership of the lease with XYZ Oil, and Jill thereafter enjoyed her apportioned royalty proceeds from the Titan I well.

To continue the story, in 2014, ABC Oil leased up the remaining undivided mineral owners in the south section, and drilled the Minerva I well on a 640-acre unit basis. XYZ Oil, as lessee of Bob’s and Jill’s lease, participates in the well. A title examination is ordered for the south section, and the examiner confirms not only that Bob’s and Jill’s lease is held by production from the Titan I well, but also that the entireties clause in the lease provides for the apportionment of royalties. At this point the examiner alerts ABC Oil that title to the north section covered by the lease will need to be examined in order to confirm the party or parties entitled to royalty proceeds from the Minerva I well. Perhaps Bob conveyed his interest in the north section to his children and grandchildren. By virtue of the entireties clause, such new owners will be entitled to their apportioned share of royalties, even though production is from a well located in the south section of the lease. Confirming such ownership will require a potentially burdensome title examination of land outside of the subject drilling unit. The title examination problem intensifies when a lease containing an entireties clause covers multiple tracts spread across multiple sections.

Entireties clauses with the type of royalty apportionment language discussed here are not ordinarily found in leases of recent vintage (their use having fallen out of favor), and appear most often in leases dating from the 1950s to 1970s. Importantly, such leases often contain no Pugh clause. Thus, particular care should be taken when reviewing the provisions of leases that have been held by production for multiple decades. Even when certain tracts of leases with royalty apportionment clauses have been released, some have argued that the lessors of released tracts remain entitled to proceeds from actively producing tracts. The entireties clause should also be carefully reviewed in the context of the other lease provisions, which may impact the application of the entireties clause. Further, any lease amendments should be carefully scrutinized because in some instances entireties clauses will have been deleted and replaced with a form of Pugh clause.

The entireties clause deserves the attention of operators, especially considering the many different forms in which the clause is drafted. The royalty apportionment-type clause treated here is just one variant with critical implications for the proper distribution of proceeds, but each lease needs to be examined in its own right with attention paid to the particular language used, in order to determine what issues might arise out of its application beyond royalty apportionment.

Sources:
1-7 Law of Pooling and Unitization § 7.04 (3d ed.).
4-6 Williams & Meyers, Oil and Gas Law § 678.
1-XII The Law of Oil and Gas Leases § 12.01 (2d ed.).
Gene L. McCoy, The Entirety Clause—Its Current Use and Interpretation, 12 Rocky Mt. Min. L. Inst. 10 (1967).
William S. Livingston, The Entirety Clause and the Drafting of Division Orders, 5 Rocky Mt. Min. L. Inst. 12 (1960).