Fee Lease 101 Series

Saving the Best for Last – What Is All That Stuff at the End of My Lease?

On this blog, we have posted our complete Fee Lease 101 Series covering many of the standard fee oil and gas lease provisions from the granting clause to the pooling clause. However, there is typically a group of clauses towards the end of the lease form that appear to be the left-over clauses. These clauses include the assignment clause, proportionate reduction clause, warranty clause, surrender or release clause, and preferential right to purchase or option clause. They can have important ramifications on the relationship of the lessor and lessee and status of the lease and, accordingly, are discussed below.

I.      Assignment Clause

The assignment clause governs how the lessor and lessee may assign their respective interests. It may contain a restraint on the lessee’s power to assign the lease in whole or in part without the lessor’s consent. It may also contain a restraint on the minimum acres or minimum interest that may be assigned, such as “no less than forty acres” or “no less than the lessee’s entire undivided interest.” This restraint on assigning/alienation by the lessee is generally allowed; however, it will be strictly construed.

To avoid a claim that the clause is an unreasonable restraint on alienation, contemporary leases typically authorize assignments by either the lessor or lessee, in whole or in part, but will often include conditions to the assignment. For instance, it may state that lessee will not recognize a change in the lessor’s ownership until it receives an original or authenticated copy of the assignment. It may allow a partial assignment by the lessor, but will require that the assignment cannot increase the lessee’s obligations under the lease, such as drilling offsetting wells, protection of drainage, requiring separate measuring, or installation of separate tanks.

Although often the intent of the assignor, it is important that the assignment clause provides that the lessor relieves the lessee of any further obligations concerning the interest assigned.1 The assignor does not want to assign the interest and thereafter be stuck with the royalty payments if the assignee fails to pay the lessor. If a partial assignment of the lessee’s interest is allowed, a provision should be included that deals with the apportionment of rentals and royalties.

The following example assignment clause addresses all of the above requirements:

Ownership Changes. The interest of either Lessor or Lessee hereunder may be assigned, devised or otherwise transferred in whole or in part, by area and/or by depth or zone, and the rights and obligations of the parties hereunder shall extend to their respective heirs, devisees, executors, administrators, successor and assigns. No change in Lessor’s ownership shall have the effect of reducing the rights or enlarging the obligations of Lessee hereunder, and no change in ownership shall be binding on Lessee until 60 days after Lessee has been furnished the original or duly authenticated copies of the documents establishing such change of ownership to the satisfaction of Lessee or until Lessor has satisfied the notification requirements contained in Lessee’s usual form of division order. In the event of death of any person entitled to rentals or shut-in royalties hereunder, Lessee may pay or tender such rentals or shut-in royalties to such persons or to their credit in the depository, either jointly, or separately in proportion to the interest which each owns. If Lessee transfers its interest hereunder in whole or in part Lessee shall be relieved of all obligations thereafter arising with respect to the transferred interest, and failure of the transferee to satisfy such obligations with respect to the transferred interest shall not affect the rights of Lessee with respect to any interest not so transferred. If Lessee transfers a full or undivided interest in all or any portion of the area covered by this lease, the obligation to pay or tender rentals and shut-in royalties hereunder shall be divided between Lessee and the transferee in proportion to the net acreage interest in this lease then held by each.2

II.       Proportionate Reduction3

The proportionate reduction clause is also referred to as the lesser interest clause. It provides for reduction of rentals and royalties owed to the lessor in the event the lessor owns less than the full mineral estate. A typical proportionate reduction clause will provide:

In case said Lessor owns a lesser interest in the above described land than the entire and undivided fee simple estate therein, then the rentals and royalties herein provided shall be paid to Lessor only in the proportion that his interest bears to the whole and undivided fee.

However, the above example does not differentiate between the proportionate reduction of rentals and proportionate reduction of royalties. It focuses on the entire leased lands. What is the result if the lease covers a 640-acre section, the lessor owns 100% of the mineral estate in the W/2 of the section, 50% of the mineral estate in the E/2 of the section, and the well is located on the E/2? The lessor’s proportionate interest is 75% [(100% x 320/640) + (50% x 320/640)]. The lessor would not only receive 75% of the rental, but also 75% of the royalty even though the well is located on the lands in which the lessor only owns a 50% mineral interest.

The following example makes a distinction between rentals and royalties:

If Lessor owns less than the full mineral estate in all or any part of the leased premises, payment of rentals, royalties, and shut-in royalties hereunder shall be reduced as follows: (a) rentals shall be reduced to the proportion that Lessor’s interest in the entire leased premises bears to the full mineral estate in the leased premises, calculated on a net acreage basis; and (b) royalties and shut-in royalties for any well on any part of the leased premises or lands pooled therewith shall be reduced to the proportion that Lessor’s interest in such part of the leased premises bears to the full mineral estate in such part of the leased premises.

III.       Warranty Clause4

The warranty clause provides a warranty of title by the lessor with respect to the interest described in the granting clause. Additionally, the warranty clause provides the basis for applying the doctrine of after-acquired title in the event the lessor acquires an interest in the leased premises after giving the lease. The following are two examples of warranty clauses:

    • Lessor hereby warrants and agrees to defend the title to the land herein described and agrees that the Lessee, at its option may pay and discharge in whole or in part any taxes, mortgages, or other liens existing, levied, or assessed on or against the above described lands, and in the event it exercises such option, it shall be subrogated to the rights of any holder or holders thereof and may reimburse itself by applying the discharge of any such mortgage, tax, or other liens, to any royalty or rental accruing hereunder.
    • Lessor hereby warrants and agrees to defend title conveyed to Lessee hereunder, and agrees that the Lessee at Lessee’s option may pay and discharge any taxes, mortgages or liens existing, levied or assessed on or against the leased premises. If Lessee exercises such option, Lessee shall be subrogated to the rights of the party to whom payment is made, and, in addition to its other rights, may reimburse itself out of any royalties or shut-in royalties otherwise payable to Lessor hereunder. In the event Lessee is made aware of any claim inconsistent with Lessor’s title, Lessee may suspend the payment of royalties and shut-in royalties hereunder, without interest, until Lessee has been furnished satisfactory evidence that such claim has been resolved.5

The second warranty clause above allows the lessee to suspend payments to the lessor without interest in the event of a title dispute. However, a lessee should never suspend rental payments even if there is a title dispute. Failure to pay rentals could be fatal if the suspension is later determined to be unjustified.

As set forth in the above examples, the warranty clause often will contain a subrogation provision pertaining to a superior lien existing prior to the execution of the lease. To protect the lessee from the lease being extinguished if the superior lien is foreclosed, the clause authorizes the lessee to satisfy any liens and be subrogated to the rights of the lienor. The clause may vary in the types of claims or obligations the lessee is authorized to satisfy, including mortgages, deeds of trusts, taxes, assessment, charges, and encumbrances. Additionally, the clause may address whether the lessee may satisfy the claim or obligation prior to maturity thereof; and whether the lessee is authorized to withhold payments to the lessor for rentals, royalties, or other sums in satisfaction of the claim to reimbursement.

The warranty clause must be read in relationship to the granting clause and proportionate reduction clause. If the lessor owns less than 100% of the mineral interest, a granting clause that only describes the lands, but not the interest, is technically a breach of the warranty clause, but the proportionate reduction clause acts to proportionately reduce the lessor’s interest and the rental and royalties owed. If the granting clause describes the lessor’s percentage mineral interest in the lands, there is no breach of warranty, but there may be confusion as to the applicability of the proportionate reduction clause – is the lessor entitled to 100% of the rentals and royalties, i.e. not further proportionately reduced.

Cases have held that the warranty in the lease does not warrant the title of the lessor, it actually warrants title to the lessee. The warranty clause can be used to make a claim for a breach of warranty if the mineral interest covered by the lease is subject to an interest carved out of the mineral estate. For example, if prior to execution of the lease, the lessor’s mineral interest is subject to a non-participating royalty interest, it could be argued that the warranty clause, in some cases, results in the lessor’s royalty interest being reduced by the amount of the non-participating royalty interest.6

Many lessors will strike out or delete the warranty clause. As discussed above, legitimate reasons exist for using this clause. If the lessor insists on deleting the warranty clause, the lessee should at least propose one of the options for protection: make it a special warranty (“by, through and under”); limit the damages for a breach of warranty to money paid for the bonus, rentals, and royalties; or have the lessor execute an indemnifying division order in the event of production attributable to the leased premises.7 However, even if stricken, some courts have held that a warranty of marketable title is implied by law by use of the words “grant” or “convey” in the granting clause.

IV.       Surrender or Release Clause8

The surrender or release clause was originally included in the “or” form lease to relieve the lessee of the obligations to either drill or pay rentals by allowing the lease to be surrendered back to the lessor. In contrast, the “unless” form lease permits a lessee to extinguish its obligations by merely failing to perform the obligation, i.e. lease will terminate unless rental is paid. However, a surrender clause is also useful in an “unless” form lease when the lessee desires to surrender only a portion of the lease. Following are two examples of a surrender clause:

      • Lessee may, at any time and from time to time, deliver to Lessor or file of record a written release of this lease as to a full or undivided interest in all or any portion of the area covered by this lease or any depths or zones thereunder, and shall thereupon be relieved of all obligations thereunder arising with respect to the interest so released. If Lessee releases less than all of the interest or area covered hereby, Lessee’s obligation to pay or tender rentals and shut-in royalties shall be proportionately reduced in accordance with the net acreage interest retained hereunder.
      • Lessee may at any time surrender or cancel this Lease in whole or in part by delivering or mailing such release to the Lessor, or by placing the release of record in the County where said land is situated. If this Lease is surrendered or cancelled as to only a portion of the acreage covered hereby, then all payments and liabilities thereafter accruing under the terms of this Lease as to the portion cancelled, shall cease and terminate, and any rentals thereafter paid may be apportioned on an acreage basis, but as to the portion of the acreage not released the terms and provisions of this Lease shall continue and remain in full force and effect for all purposes.

Of course, there are many variants of the surrender clause. As set forth in the above examples, a surrender clause may require that written notice be provided to the lessor and/or recording of the release. In some cases, the clause requires the notice be given at some particular date or after certain events have occurred (such as “after production is achieved”) or the surrender is not effective until some particular date after giving notice (such as “the surrender shall become effective 30 days after delivery of the release to Lessee”). The clause may also require a payment as a condition to the surrender.

As to partial surrenders, as provided in the examples above, if the lessee releases part of the lease, the lessee is relieved of all obligations concerning the released part, and rentals and shut-in royalties are proportionately reduced according to the amount of acreage released. However, some clauses specifically provide that certain obligations, including payment of rentals or royalties, will not be affected by a partial surrender. If a partial surrender is authorized, the size of the surrendered or retained lands may be addressed in the clause, i.e. “not less than ten (10) acres;” “contiguous;” or “any legal subdivisions thereof.” Including the phrases “at any time or times” or “may at any time, or from to time to time” clearly evidence that successive partial surrenders by the lessee are allowed. The lessee should include a provision that the partially surrendered lands shall remain subject to the easements and right-of-way provided in the lease for the lessee’s operations. Additionally, restrictions on the lessor’s or its subsequent lessee’s use of the surrendered land should be included stating that the lessor shall not interfere with the original lessee’s operations and requiring adequate set-backs from the exterior boundary of the lands retained or any well drilled by the original lessee.

V.       Preferential Rights to Purchase and Options10

To protect the lessee, particularly with the advent of the short primary terms contained in contemporary leases, preferential rights to purchase and options to extend the primary term or renew the lease have been added to the lease. The following is a preferential right to purchase a new lease clause:

If during the term of this lease (but not more than 20 years after the date hereof) Lessor receives a bona fide offer from any party to purchase a new lease covering all or any part of the lands or substances covered hereby, and if Lessor is willing to accept such offer, then Lessor shall promptly notify Lessee in writing of the name and address of the offeror, and of all pertinent terms and conditions of the offer, including any lease bonus offered. Lessee shall have a period of 30 days after receipt of such notice to exercise a preferential right to purchase a new lease from Lessor in accordance with the terms and conditions of the offer, by giving Lessor written notice of such exercise. Promptly thereafter, Lessee shall furnish to Lessor the new lease for execution, along with a time draft for the lease bonus conditioned upon execution and delivery of the lease by Lessor and approval of the title by Lessee, all in accordance with the terms of said draft. Whether or not Lessee exercises its preferential right hereunder, then as long as this lease remains in effect any new lease from Lessor shall be subordinate to this lease and shall not be construed as replacing or adding to Lessee’s obligations hereunder.11

The twenty year limitation is to avoid a violation of the rule against perpetuities in some states. This provision provides that the new lease is subordinate to the old lease to avoid any question about the status of the new lease while the old lease is still in effect.

An option to extend the primary term may provide for the lease to be extended for a specified period of time upon payment of a specified consideration. For instance, the following is an option to extend the primary term:

Lessee is hereby given the option to extend the primary term of this lease for an additional Two (2) year(s) from the expiration of the original primary term hereof. This option may be exercised by Lessee at any time during the original primary term by paying the sum of One Hundred and 00/100 Dollars ($100.00) per net mineral acre to Lessor or the credit of Lessor mailed to Lessor at the above address. This payment shall be based upon the number of net mineral acres then covered by this lease and not at such time being maintained by the other provisions hereof. If, at the time this payment is made, various parties are entitled to specific amounts according to Lessee’s records, this payment may be divided between said parties and paid in the same proportion. Should this option be exercised as herein provided, it shall be considered for all purposes as though this lease originally provided for a primary term of Five (5) years.

A lease may also contain an option to renew the lease. Courts have differed on whether there is a distinction between “renew” or “extend.” In an Ohio decision, the court held that the clause “Lessor grants Lessee an option to extend or renew under similar terms a like lease” provided the lessee with two options: (1) to extend the lease on the same terms as the existing lease; or (2) to renegotiate for a renewal “like lease” on similar terms. The court reasoned that the terms “renew” and “extend” are distinct terms.12

In our Fee Lease 101 Series, we have covered most of the standard fee oil and gas lease clauses. As discussed above, these “left-over” provisions can affect the lessor’s and lessee’s, and their successor and assigns, rights, interests, and obligations and the status of the lease. A caveat for this article, and all our Fee Lease 101 Series articles, in interpreting any lease provision, care must be used in examining the specific language of the provision and the case law of the jurisdiction must be understood and applied. In order to avoid unintended consequences, the same caveat applies to drafting any lease provision.

1 See Pennaco Energy v. KD Co. LLC, 2015 WY 152, ¶ 19 (2015) (Finding, “Among the covenants [obligations] the original lessee-assignor retains after assignment of its interest are those requirement payments of rentals and/or royalties and restoration of the surface to its original condition once production activities have ceased.”).
2 Thomas W. Lynch, The “Perfect” Oil and Gas Lease (An Oxymoron), 40 Rocky Mtn. Min. L. Inst. 3-1, § 3.10 (1994).
3 See, generally, id. § 3.09.
4 See, generally, 4-6 Williams & Meyers, Oil and Gas Law § 685.1.
5 See, generally, Lynch at fn. 3, § 3.15.
6 Id.
7 Milam Randolph Pharo & Gregory R. Danielson, The Perfect Oil and Gas Lease: Why Bother!, 50 Rocky Mtn. Min. L. Inst. 19-29 (2004).
8 See, generally, 4-6 Williams & Meyers, Oil and Gas Law § 680.
9 The use of the terms “surrender” or “release” are used interchangeably to describe this clause. For purposes of this article, we will use the term “surrender”.
10 See, generally, 4-6 Williams & Meyers, Oil and Gas Law § 697.6.
11 See, generally, Lynch at fn. 3, § 3.17.
12 Kenney v. Chesapeake Appalachia, 2015 Ohio 1278 (Ohio Ct. App. 2015); Eastman v. Chesapeake Appalachia, 754 F.3d 356 (6th Cir. 2014).

Top Leases: Assessing (and Avoiding) the Risks of Novation

You only have three more months on the primary term of an oil and gas lease that was issued nearly five years ago with a 1/6th royalty.  A drilling permit should be issued any day now, and you anticipate commencing operations to drill a well in sufficient time to hold the lease.  You instruct your landman to obtain a top lease from the mineral owner just in case there is a hiccup and you can’t start operations in time to hold the existing lease. Your landman negotiates a new lease from the mineral owner covering the same lands but has to agree to a 3/16ths royalty in order to obtain the top lease.  But, the top lease fails to expressly state that it is a top lease to the existing lease and doesn’t contain any other language clarifying that the top lease will only be effective if and when the underlying existing lease expires.  Despite the precautionary top lease, the well permit is issued when expected and you are able to commence drilling a well in time to hold the prior existing lease.

After the well is drilled and completed, is there a risk that the mineral owner could successfully argue that the new top lease is a replacement of the existing lease and you are required to pay a 3/16ths royalty instead of a 1/6th royalty? In the oil and gas industry, you often hear landmen and attorneys frame the question as whether or not the top lease will be deemed a “novation” of the prior existing lease. But what is the standard to prove a novation? How likely is it that the mineral owner above could successfully argue that the top lease is a novation of the prior lease, even though the well was drilled in time to hold the prior existing lease? This article will provide a brief overview of the elements and burden of proof to establish a novation.

A recent 2015 case out of Pennsylvania provides an excellent overview and example of the novation analysis in the context of oil and gas leases. In Mason v. Range Resources-Appalachia LLC, 120 F. Supp. 3d 425, 433 (W.D. Pa. 2015), an oil and gas lease was issued in 1961 in Western Pennsylvania and was arguably held by gas storage operations on the property (and by the payment of rentals). Years later, during the Marcellus shale boom, a landman working for Range Resources obtained an oil and gas lease in 2007 from the same mineral owners and covering the same lands as the 1961 lease. Range Resources only later discovered that it already owned the existing 1961 lease. Testimony in the case indicated that the leasing environment at that time was “chaotic,” that Range Resources did not have a good process for evaluating lease validity, and that landmen were taking leases without conducting complete due diligence of possible existing leases. Range Resources did not drill a well within the term of the 2007 lease, and the mineral owners asserted that the 2007 lease was a novation of the 1961 lease (which had unique provisions allowing the lease to be held by rental payments for gas storage), and that the 2007 lease then expired.

The Pennsylvania court set forth four elements to show a novation, which elements are the same or similar in other jurisdictions that have undertaken a discussion of novation:

“(1) the displacement and extinction of a prior contract, (2) the substitution of a valid new contract for the prior contract, (3) sufficient legal consideration for the new contract, and (4) the consent of the parties.”1

The Pennsylvania court further stated that “whether a contract has the effect of a novation primarily depends upon the parties’ intent” and “the party claiming the existence of a novation bears the burden of demonstrating the parties had a meeting of the minds.” The court stated that evidence of the parties’ intent to enter in to a novation can be shown “by other writings, or by words, or by conduct, or by all three.” Courts in other states have similarly emphasized that a party claiming a novation has the burden of proof, and that the party asserting the claim of novation has the burden of proving all of the required elements for a novation.2 A novation is never presumed. Instead the presumption is that the new contract was taken conditionally or as additional security, absent evidence of intention to the contrary.3 In the Pennsylvania case, the court determined that the mineral owners continued to accept rentals under the 1961 lease even during the term of the 2007 lease, and there was no evidence that the parties expressly intended to replace the 1961 lease with the 2007 lease.

Returning to our example above, the case law suggests that a mineral owner attempting to argue that the top lease was a novation of the base lease would have a very challenging case. But there is still a risk of such a claim, even if the claim is ultimately for nuisance value only. How can an operator protect itself from novation claims? Obviously, the best approach is to always put language in any top lease that makes it clear that the lease will only go into effect if and when the base lease expires by its terms, and make that intent clear in any other written correspondence to a landowner (such as an initial offer letter).

But what if an operator accidentally obtains a standard lease with no top lease language when it already owns an existing lease? For drilling purposes, the mineral interest will be leased either way. But an operator should ideally take steps to address any ambiguity resulting from the top lease and clarify the intent of the parties. If the well is successfully completed in time to hold the existing lease, the best approach would be to have the mineral owner (and operator) sign and record a ratification document where the parties acknowledge that the base lease was held by the drilling of the well, and that the top lease will remain of record as a top lease only in the event the well ceases operations.

Another approach (with attendant risks) would be to send an informative letter to a landowner prior to drilling, informing them of the pending well, stating that the operator will deem the base lease as held by the drilling of the well. That would at least set up an estoppel argument, and the operator will know prior to drilling the well whether or not the landowner objects and claims a novation. Or, an operator may simply pay proceeds on the prior existing lease, see if the landowner accepts royalty payments under that lease, and simply run the risk of a future novation claim. There may also be facts that make an operator more confident that a novation argument will be unsuccessful that justifies a riskier wait-and-see approach.4

Each fact scenario will be different, and an oil and gas lessee must evaluate the facts and risks to determine what level of clarification and curative action it requires to address risks of novation claims when there are overlapping leases.

1 Another novation case in the oil and gas context, Warrior Drilling & Eng’g Co. v. King, 446 So. 2d 31, 33-34 (Ala. 1984), framed the elements as: “[T]o establish a novation there must be: (1) a previous valid obligation, (2) an agreement of the parties thereto to a new contract or obligation, (3) an agreement that is an extinguishment of the old contract or obligation, and (4) the new contract or obligation must be a valid one between the parties thereto.”
2 In re United Display & Box, Inc., 198 B.R. 829, 831 (Bankr. M.D. Fla. 1996). See also Fusco v. City of Union City, 618 A.2d 914 (App. Div. 1993); Alexander v. Angel, 236 P.2d 561 (1951); Scott v. Bank of Coushatta, 512 So. 2d 356 (La. 1987); Credit Bureaus Adjustment Dep’t, Inc. v. Cox Bros., 295 P.2d 1107 (1956).
3 For example, a Utah court conducting a novation analysis stated: “The burden of proof as to a novation by the transaction in question rests upon the party who asserts it; … an intention to effect a novation will not be presumed; … in the absence of evidence indicating a contrary intention, it will be presumed, prima facie, that the new obligation was accepted merely as additional or collateral security, or conditionally, subject to the payment thereof; and the intention to effect a novation must be clearly shown.” First Am. Commerce v. Washington Mut., 743 P.2d 1193 (Utah 1987); see also Tri-State Oil Tool Indus., Inc. v. EMC Energies, Inc., 561 P.2d 714, 716 (Wyo. 1977).
4 For example, if the existing lease covers multiple parcels in several drilling units, and the new lease only covers one parcel, that may make an argument for a novation more difficult. Also, if there are unrecorded documents that evidence clear intent that the second lease was intended only as a top lease, that fact may make an operator more confident that a novation claim would be unsuccessful.

Force Majeure – May the Force Be With You and Save Your Oil and Gas Lease

In Star Wars, the force means an “energy field created by all living things… It binds the galaxy together.”1 In French, force majeure means superior force. In a fee oil and gas lease, the force majeure clause is designed to protect the lessee from being liable for damages or the lease from terminating for causes beyond the lessee’s control. The lease typically contains numerous clauses designed to protect the lessee and save the lease when particular events occur. Such clauses include the shut-in royalty, dry hole, cessation of production, continuous drilling, and entirety clauses. We have addressed most of these clauses in this blog, The Oil and Gas Report.2 The force majeure clause is often thought of as the savings clause of last resort. Force majeure clauses vary widely and their application depends on the specific language of the clause.

Force Majeure Events: “Judge me by my size, do you?”3

The events covered by the force majeure clause can vary from narrowly defined events to broad acts of God. Some clauses are limited to excusing performance only when it is prevented by governmental actions through laws, rules, regulations, or orders. For example:

All terms and express or implied covenants of this lease shall be subject to all Federal and State Laws, Executive Orders, Rules, or Regulations, and this lease shall not be terminated in whole or in part, nor Lessee held liable in damages, for failure to comply therewith if compliance is prevented by, or if such failure is the result of any such Law, Order, Rule or Regulation.4

Other force majeure clauses excuse performance for a comprehensive array of events. For example:

The term “force majeure” as used herein shall be Acts of God, strikes, lockouts, or other industrial disturbances, acts of the public enemy, wars, blockades, riots, epidemics, lighting, earthquakes, explosions, accidents or repairs to machinery or pipes, delays of carriers, inability to obtain materials or rights of way on reasonable terms, acts of public authorities, or any other causes, whether or not of the same kind as enumerated herein, not within the control of the lessee and which by the exercise of due diligence lessee is unable to overcome.5

Courts will carefully scrutinize the list of events identified in the clause to judge whether the subject event is covered in the force majeure clause.6 Additionally, courts have held that the force majeure event must be outside of the lessee’s control7 and the lessee cannot be the cause of the event.8

Performance Excused: “Do. Or do not. There is no try.”9

The force majeure clause will only excuse the performance identified therein. Care should be exercised in determining whether the clause applies to the performance of general or specific covenants or conditions. Generally, failure to perform a covenant will not automatically result in termination of the lease; however, failure to perform a condition will automatically cause the lease to terminate.10 Following are some examples of the types of performance that may excused in the force majeure clause:

    • all terms and express or implied covenants;
    • lessee’s obligations whether express or implied;
    • drilling operations or compliance with the provisions of this lease, both expressed and implied;
    • drilling, working or production operations; or
    • performance or operations.

The force majeure clause may only apply to part of the lease term, i.e., the primary term or secondary term. For instance, if rentals are due during the primary term and a force majeure event occurs, some forms excuse the rental payment; however, others require payments continue to be made, and others are silent on payment. If the lease is in the secondary term and a force majeure event occurs, the clause may require a royalty or a minimum royalty payment during the force majeure event to keep the lease alive without drilling or production. For example:

If after the expiration of the primary term and while the lease is in force and the lessee cannot maintain the same in effect because prevented by force majeure, then the lease will nevertheless continue, but lessee will pay to the owners as royalty an amount equal to ___ dollar per year for each acre retained hereunder.11

If payments are due after the beginning of the force majeure event, the force majeure clause should describe when the payments are due, such as a reasonable time after the occurrence of the event, with subsequent payments due on the anniversary date of the lease, and calculation of a prorated amount due if the event occurs and ends on a date other than the anniversary date.

The force majeure event typically must prevent, delay, interrupt, or make impossible performance of the specified covenants or conditions. Although performance may appear impossible, some courts are willing to look at alternatives the lessee should have attempted before invoking the force majeure clause.12 The force majeure clause comes into effect only if the performance is rendered impossible unless the subject clause contains less exacting terms, then, in some cases, it may be invoked if performance is unreasonably burdensome.13

Reconciling Lease Provisions:”Use the Force, Luke.”14

To use the force majeure clause, it must be reconciled and construed along with all the other provisions of the lease. Generally, courts will refuse to excuse performance under the force majeure clause if another clause is applicable, such as excusing production by the payment of shut-in royalties.15 Similarly, courts have been willing to find that a cessation of production for whatever reason is not relieved by the force majeure clause if the lease contained a cessation of production clause requiring commencement of operations for drilling or reworking on the leased premises within a defined amount of days and the force majeure event did not prevent commencement of drilling or reworking operations.16

The interplay of the habendum clause17 and force majeure clause was the subject of two nearly identical cases in which the lessees claimed as a force majeure event the State of New York’s highly publicized moratorium, and now ban, on high volume hydraulic fracturing (“fracking”) of horizontal wells. The lessees invoked the force majeure clause claiming that the fracking moratorium prevented them from drilling on the leased lands prior to the expiration of the primary term.18 On appeal of one of the cases to the United States Second Circuit Court of Appeals, the federal Court of Appeals asked the state court19 to answer two previously unanswered questions of state law: (1) under New York law did New York’s moratorium constitute a force majeure event; and (2) if so, does the force majeure clause modify the habendum clause and extend the leases’ primary terms?20

Each of the subject leases contained a habendum clause providing that the lease “shall remain in force for a primary term of FIVE (5) years from the date hereof and as long thereafter as the said land is operated by Lessee in the production of oil or gas.” The leases also contained the following force majeure clause:

[i]f and when drilling or other operations hereunder are delayed or interrupted … as a result of some order, rule, regulation, requisition or necessity of the government, or as a result of any other cause whatsoever beyond the control of the Lessee, the time of such delay or interruption shall not be counted against Lessee, anything in this lease to the contrary notwithstanding. All express or implied covenants of this lease shall be subject to all Federal and State laws, Executive Orders, Rules or Regulations, and this lease shall not be terminated, in whole or in part, nor Lessee held liable in damages for failure to comply therewith, if compliance is prevent by, or if such failure is the result of any such Law, Order, Rule or Regulation.

(Emphasis added)

Unfortunately, the state court punted on the first question, rendering it academic by its answer to the second question. The court stated that the force majeure clause does not modify the primary term of the habendum clause and, therefore, a force majeure event cannot be used to extend the leases’ primary terms. Importantly, the state court found that the habendum clause in the leases does not incorporate the force majeure clause by reference or contain any language expressly subjecting it to the other lease terms and the force majeure clause does not refer to the habendum clause with specificity; therefore, the habendum clause is not expressly modified or enlarged by the force majeure clause. It found that the phrase in the force majeure clause “anything in this lease to the contrary notwithstanding” does not supersede all other clauses in the lease, just those in which it is in conflict, and the habendum and force majeure clauses are not in conflict during the primary term of the lease. Additionally, the court stated that the force majeure clause pertains only to express or implied covenants (the lessee’s obligations) and, in the primary term, the covenant is to pay rentals (not drilling). As to the secondary term of the habendum clause, the court did recognize that since the force majeure clause expressly refers to a delay or interruption in drilling or production, the force majeure clause modified the secondary term of the habendum clause in which the lessee has the obligation to produce oil or gas or the lease terminated. The court stated that drilling and production operations are covenants only applicable to the secondary term of the lease. Finally, the court made the distinction between termination and expiration noting that the force majeure clause expressly deals with lease termination, something that only occurs in the secondary term, rather than lease expiration that occurs at the end of the primary term. The court stated that if the lessees intended for the habendum clause to be subject to other provisions of the contract, they could have expressly done so.21 Accordingly, the United States Second Circuit Court of Appeals applied the law as set out by the state court and held that under New York law the force majeure clause did not modify the habendum clause. Therefore, even if the moratorium was a force majeure event, it did not operate to extend the leases.22

The lesson of the Beardslee decision is that in similarly drafted leases, the force majeure clause is basically inapplicable to the primary term and, if the lessee is prevented or delayed from drilling and the force majeure clause is not applicable, the primary term of the lease will continue on and the lessee will have no way in which to extend the lease into the secondary term.

Conclusion: “The Force is strong with this one.”23

To invoke superior force, such force must be understood. In drafting the lease, careful consideration should be given to: (1) the lease play and anticipated operations; (2) defining the force majeure events in the force majeure clause in a sufficient manner; (3) defining the covenants, conditions, and obligations, with consideration to the primary and secondary terms, in the force majeure clause that will be excused upon the occurrence of a force majeure event; (4) incorporating by reference the force majeure clause in the habendum clause and any other pertinent clauses; and (5) reconciling all of the lease provisions. If dealing with the preservation of an existing lease, the safest route may be to request a ratification and amendment of the lease or other such agreement with the lessor confirming the existence and status of the lease and obtaining an extension thereto as necessary; of course, this is assuming that the lessor is willing to execute such an agreement.

Under general principles of contract interpretation, the courts will construe the lease against the party who drafted it, most often the lessee. Fracking bans and other prohibitions on oil and gas exploration and production exist across the country24 and depending on the results of the 2016 Presidential Elections,25 lawsuits claiming that the force majeure clause will not save an oil and gas lease during a fracking ban may become more prevalent. Looking ahead, the next impediment may include bans on transporting oil by rail through certain states.26 If transportation by rail is crucial to the economic viability of the play, then such a ban on the transportation of the oil should be addressed in the lease.

In all your lease endeavors, MAY THE FORCE BE WITH YOU.

1 Obi-Wan Kenobi, Star Wars (subtitled Episode IV: A New Hope) (1977).
2 Fee Lease 101 Series, www.theoilandgasreport.com.
3 Yoda, The Empire Strikes Back (1980)
4 4-6 Williams & Meyers, Oil and Gas Law § 683.1 (citations omitted).
5 Aukema v. Chesapeake Appalachia, LLC, 904 F. Supp. 2d 199 (N.D.N.Y. 2012).
6 See Allegiance Hillview, LP v. Range Texas Prod., LLC, 347 S.W.3d 855 (Tex. App. 2011); Sun Operating Ltd. Partnership v. Holt, 984 S.W.2d 277 (Tex. App. 1998); Perlman v. Pioneer Ltd. Pship, 918 F.2d 1246 (5th Cir. 1990).
7 Vortt Exploration Co., Inc. v. EOG Resources, Inc., 2009 Tex. App. LEXIS 4113 (Tex. App. – Eastland, May 29, 2009); Maralex v. Resources, Inc. v. Gilbreath, 76 P.3d 626 (N.M. 2003) (if the cessation of production was caused by the pressures in a third party pipeline, it would be beyond the control of the lessee; however, if the cessation was caused by insufficient pressure within the well, it would not be an external cause beyond the lessee’s control).
8 Schroeder v. Snoga, 1997 Tex. App. LEXIS 4030 (Tex. App.–San Antonio July 31, 1997) (Commission shut-in order was caused by the operator’s violation of the Commission’s rules); Edington v. Creek Oil Co., 690 P.2d 970 (Mont. 1984) (Commission shut-in order for a seepage issue could have been resolved by the lessee); Caddell v. Threshold Dev. Co. 609 S.W.2d 871 ( Tex. App.-Amarillo 1980) (a lockout by the lessor was within the meaning of the force majeure clause).
9 Yoda, The Empire Strikes Back (1980).
10 Older lease forms may contain conditions such as payment of rentals during the primary term or payment of shut-in royalties in the secondary term. In that case, failure to timely and appropriately make the payments will result in the lease automatically terminating.
11 4-6 Williams & Meyers, Oil and Gas Law § 683.1 (citations omitted).
12 See Logan v. Blaxton, 71 So. 2d 675 (La. Ct. App. 1954). Although the force majeure clause identified floods as an event and heavy rainfall made roads impassable and impracticable to transport crude oil to market, the court found that the rains were seasonable and could be predicted and the evidence of impossibility was not demonstrated, i.e. that roads could not be improved, alternative routes were not available, or smaller trucks could not be used to transport the oil to market.
13 Id.
14 Obi Wan Kenobi, Star Wars (subtitled Episode IV: A New Hope) (1977).
15 See Welsch v. Trivestco Energy Co., 221 P.3d 609 (Kan. App. 2009) (bankruptcy of a gas purchaser is covered by the shut-in royalty clause, not the force majeure clause. The unavailability of purchasing and transportation services did not prevent the lessee from paying shut-in royalties and the force majeure clause was not triggered).
16 Trinidad Petroleum Corp. v. Pioneer Natural Gas Co., 416 So. 2d 290 (La. Ct. App. 1982, writ denied).
17 The habendum clause sets forth the term of the lease. It typically divides the lease into the primary term of a fixed number of years and the secondary term “for so long thereafter as oil or gas is produced.” See Trent Maxwell, “The Habendum Clause – ‘Til Production Ceases Do Us Part,” The Oil and Gas Report, Fee Lease 101 Series, www.theoilandgasreport.com.
18 Aukema v. Chesapeake Appalachia, LLC, 904 F. Supp. 2d 199 (N.D.N.Y. 2012); Beardslee v. Inflection Energy, LLC, 904 F. Supp. 2d 213 (N.D.N.Y. 2012). These cases were decided on the same day, by the same judge, with the same results. The court found that the moratorium did not prevent the lessees from performing under the leases and drilling by other methods, i.e. drilling a conventional vertical well. The lessees had the right to drill, but were not required to do so; it was merely an option and “invocation of a force majeure clause to relieve them from their contractual duties is unnecessary.” Beardslee, 904 F. Supp. 2d at 220. The Beardslee decision was appealed by the lessees.
19 The New York Court of Appeals, being New York’s highest appellate state court.
20 Beardslee v. Inflection Energy, LLC, 761 F.3d 221 (2nd Cir. 2014).
21 Beardslee v. Inflection Energy LLC, 31 N.E.3d 80 (N.Y. 2015).
22 Beardslee v. Inflection Energy, LLC, 798 F.3d 90 (2nd Cir. 2015).
23 Darth Vadar, Star Wars (subtitled Episode IV: A New Hope) (1977)
24 Mora County, New Mexico was the first county in the United States to ban “any corporation to engage in the extraction of oil, natural gas, or other hydrocarbons within Mora County” and prohibiting the use of water for fracking, among other related activities. The District Court held that the ban was preempted by state law. SWEPI, LP v. Mora County, 2015 U.S. Dis. LEXIS 13496 (D.N.M. Jan. 19, 2015). Similarly, Fort Collins and Longmont, Colorado’s recent bans have also been held to be preempted by state law and outside their authority and struck down. City of Fort Collins v. Colo. Oil & Gas Assn, 2016 CO 28 (May 2, 2016); City of Longmont v. Colo Oil & Gas Assn, 2016 CO 29 (May 2, 2016).
25 Hillary Clinton outlines a series of conditions on fracking stating, “You know, I don’t support it when any locality or any state is against it…. I don’t think there will be many places in America where fracking will continue to take place.” The New York Times, “Transcript of the Democratic Presidential Debate in Flint, Mich,” March 6, 2016. Bernie Sanders advocates for a total ban on fracking, “We need to put an end to fracking not only in New York and Vermont, but all over this country.” The New York Times, “Bernie Sanders Proposes Fracking Ban and Attacks Hilary Clinton on the Environment,” April 11, 2016.
26 Canadian Business, “Leaders Ask Oregon, Washington Governors to Ban Oil-by-Train,” June 14, 2016.

Unitizing the Lessor’s Interest: No, It’s Not the Same as Pooling

The terms “pooling” and “unitization” are often used interchangeably, but they have different meanings. Pooling is “the bringing together of small tracts sufficient for the granting of a well permit under applicable spacing rules,” while unitization is “the joint operation of all or some portion of a producing reservoir.”[1] While pooling and unitization are both used to prevent waste and protect correlative rights,[2] unitization works on a much larger scale, allowing an operator to maximize the amount of resources extracted from an entire field or reservoir, without regard to lease or property boundaries. Generally, the lessee of a fee (private) oil and gas lease is free to commit its working interest to the unit agreement, but the lessee can only commit the lessor’s interest through voluntary ratification, compulsory unitization, or a unitization clause. This article will focus specifically on the third option: the unitization clause in fee leases.

Unitization clauses (if included at all) generally follow two patterns. First, the unitization clause may be interwoven into the pooling clause. Second, the unitization clause may appear separately, often immediately following the pooling clause (we believe this to be the preferred method). There are typically four parts to a “standard” unitization clause.

Part One – When can the lessee unitize the lessor’s interest?

Example: Lessee shall have the right to unitize, pool, or combine all or any part of the leased premises with other lands in the same general area by entering into a cooperative or unit plan of development approved by any governmental authority.

The unitization clause should expressly grant to the lessee the authority to unitize the leased premises under a cooperative or unit plan of development. Depending on the type of unit being formed (for example, a federal exploratory unit or a state voluntary unit), the language should be broad enough to cover the proposed plan of development. Because the lessee may not know its future unitization plans at the time it negotiates a lease, the lessee should ensure that the unitization clause is broad enough to cover all forms of unitization.[3]

Even with a unitization clause, the lessee has an implied duty of good faith and fair dealing when pooling or unitizing a fee oil and gas lease.[4] This means that the lessee should be careful when attempting to commit a lease that is about to expire or includes non-productive lands, or when the lessee’s economic interests are not aligned with those of the lessor. However, if the unit plan of development is approved by a governmental entity (such as the BLM or the state conservation commission), courts will generally defer to the government’s approval in determining whether the lessee acted in good faith.[5]

Unfortunately, when describing how the leased premises can be unitized with other lands, it is not uncommon to find combined pooling/unitization clauses where the lessee mistakenly used pooling language (such as “into a drilling or spacing unit in conformance with a state drilling or spacing order”) instead of replacing it with unitization language (such as “to one or more unit plans or agreements for the cooperative development or operation of one or more oil and/or gas reservoirs or portions thereof”).

Properly drafted unitization clauses should cover the development of a field or reservoir as opposed to just those lands within a single drilling or spacing unit.

Part Two – How will the terms of the lease be affected?

Example: When such a commitment is made, this lease shall be subject to the terms and conditions of the unit plan or agreement and this lease shall not terminate or expire during the life of such plan or agreement.

To effectively extend the lease under the unit plan of development, the lease terms should be amended to conform to those of the unit agreement. This can be done either by having the lessor ratify the unit agreement or by including express language to that effect (such as described above) in the unitization clause. This will ensure that the lease won’t expire while the operator of the unit is actively engaged in drilling operations under the unit agreement.

Conforming the lease to the unit agreement may not be the end of the analysis in terms of lease extension. Specifically, all or a portion of the leased premises could still expire if the lease contains a severance provision in the unitization clause or a separate Pugh clause. A severance provision in a unitization clause could result in lease expiration as to any non-unitized lands at the end of the primary term. For example:

Anything in this lease to the contrary notwithstanding, actual drilling on, or production from, any unit or units (formed by private agreement or by any State or Federal governmental authority, or otherwise) embracing both lands herein leased and other land, shall maintain this lease in force only as to that portion of Lessor’s land included in such unit or units, whether or not said drilling or production is on or from the leased premises.

Similarly, a Pugh clause could result in lease expiration as to any non-producing lands at the end of the primary term. For example:

Notwithstanding any provision to the contrary, this lease shall terminate at the end of the primary term or any extended term, as to all the leased land except those lands within a production or spacing unit prescribed by law or administrative authority on which is located a well producing or capable of producing oil and/or gas or lands on which Lessee is engaged in drilling or reworking operations.

The threat posed by either of these provisions requires careful review of the lease as a whole. Oftentimes, Pugh clauses are negotiated independently of the general lease terms and ultimately included on an addendum attached to the lease. As a result, they are not always consistent with the other terms of the lease. To avoid ambiguity, when negotiating a fee oil and gas lease, it is prudent to review any included Pugh clause (and all other lease terms) and consider how it will reconcile with the unitization clause. Ideally, the Pugh clause should only result in lease expiration as to those lands outside of an approved unit. However, at a minimum, the Pugh clause should be drafted (or amended) so as to not sever the lands within a unit production area (for example, a participating area in a federal exploratory unit).

Part Three – How will the lessor’s royalty interest be calculated?

Example: Where there is production on any particular tract of land covered by such plan, it shall be regarded as having been produced from the particular tract of land to which it is allocated and not to any other tract of land and the Lessor’s royalty interest shall be based upon production only as so allocated.

Generally, a pooling clause will allow the leased premises to be combined with other lands to form a drilling unit, wherein proceeds from production anywhere on the drilling unit are allocated according to the percentage of the acreage of each tract divided by the total acreage of the drilling unit. However, because units are concerned with the development of a field or reservoir, the unitization clause should provide that proceeds from production should only be allocated to that tract included in a unit production area (such as a participating area in a federal exploratory unit). In other words, if the lessor’s interest is properly committed to a cooperative or unit plan of development, production anywhere on the unit will hold the lease, but the lessor will only receive proceeds from production if its tract is included in a unit production area containing a producing well (not the drilling or spacing unit that would exist if the well was drilled outside of the unit).

So what happens if the lessee’s working interest is committed to the unit agreement, but the lessor’s royalty interest is not? While the lessee will be allocated proceeds according to its proportionate share of the unit production area, the lessor will be allocated proceeds on a leasehold basis. This can result in a windfall either for the lessor or the lessee (compare the allocation of proceeds from the 1H and 2H wells in the diagram to the right, assuming 320 acre standup spacing units).

Part Four – How can the lessee commit the lessor’s interest?

Example: Lessor shall formally express Lessor’s consent to any cooperative or unit plan of development by executing the same upon request of Lessee.

The mechanism for the lessee to commit the lessor’s interest to a cooperative or unit plan of development varies depending on the unitization clause. Many unitization clauses allow the lessee to unilaterally commit the lessor’s interest by executing the unit agreement. In some cases, such unitization clauses require the lessee to record a memorandum of the unit agreement. Other unitization clauses, such as the example above, require the lessor to formally consent to the unit plan of development when requested by the lessee. This is typically done by executing a ratification of the unit agreement. In any event, the agency administering the unit (for example, the BLM for a federal exploratory unit) may need to confirm the commitment status of the fee lessor. As such, and to avoid a potential dispute down the road, the lessee may decide to obtain the lessor’s ratification of the unit agreement, even if the terms of the lease do not require it.

Unitization Clause Checklist:

  • ✓ Is there a unitization clause?
  • ✓ Does the unitization clause cover the proposed type of unit?
  • ✓ Does the unitization clause allow the leased premises to be combined with other lands for the development of a field or reservoir (as opposed to a single drilling unit)?
  • ✓ Does the unitization clause amend the lease terms to those of the unit agreement?
  • ✓ If there is a severance provision in the unitization clause, will it impact the proposed operations?
  • ✓ If the lease contains a Pugh clause, is it consistent with the unitization clause? Will it impact the proposed operations?
  • ✓ Does the unitization clause allocate proceeds from production within the unit production area (as opposed to a drilling or spacing unit)?
  • ✓ Will the proposed unitization plan be exercised in good faith?
  • ✓ If required, did the lessor execute a ratification of the unit agreement? Was it recorded?

[1] Williams & Meyers, The Law of Oil and Gas, § 8-U.
[2] In Utah, for example, correlative rights are defined as “the opportunity of each owner in a pool to produce his just and equitable share of the oil and gas in the pool without waste.” Utah Code Ann. § 40-6-2(2).
[3] See, e.g., Trans-Western Petroleum, Inc. v. U.S. Gypsum Co., 584 F.3d 988 (10th Cir. 2009).
[4] See, generally, Williams & Meyers, The Law of Pooling and Unitization § 8.06.
[5] See Amoco Prod. Co. v. Heimann, 904 F.2d 1405 (10th Cir. 1990).

David Hatch and Andrew LeMieux

Practical Advice Regarding Pooling Clauses

Pooling is a fundamental concept within oil and gas law, but one that is often misunderstood. Pooling is most commonly defined as “the combining of two or more tracts of land into one unit for drilling purposes … accomplished voluntarily, or through compulsion.”1 In other words, it is how a lessee is able to extend a lease without physically drilling on the lease. For private (fee) oil and gas leases, the ability of the lessee to pool the lease is typically addressed in the lease provisions. These provisions are known as the pooling clause. This article provides some practical tips in dealing with the issues that arise from pooling clauses.

The first question that should be asked is if there is an existing spacing order in place for the lands and formation(s) involved. Many pooling clauses provide that the lease can only be pooled in conformity with a spacing order from the applicable state regulatory agency. If you encounter such a clause, you will need to check for a state spacing order, and if an order is not already in place, you will need to initiate the required steps to obtain an order. There may also be an order in place that does not match your proposed operation. If so, a new order would need to be obtained modifying the existing order. If spacing is governed by statewide spacing, you will want to double check the language in the pooling clause to confirm that statewide spacing is sufficient.

If the proposed well will be a horizontal well, there are special considerations that need to be addressed. Some lease provisions specifically address horizontal spacing. Many states have special statewide rules that are in place for horizontal wells. Particular attention should be paid to any total acreage limitation included in the pooling clause of the lease, for example, the lease cannot be included in a pooled unit for oil greater than 160 acres. If the lease has this limitation, an amendment to the lease may be the best option to eliminate this conflict.

The next question when reading a pooling clause is what role, if any, the lessor will have in the pooling process. The most common oil and gas lease terms allow the lessee to pool the lease without obtaining any additional consent from the lessor. In some cases, if the lessor desires to retain this right, they will strike out the pooling provision in the entirety, or add a specific lease provision requiring their consent. If the lease does not have a pooling clause, or if the pooling clause is stricken, the lease can only be pooled with the express consent of the lessor. This consent would be expressed by having the lessor execute a pooling agreement. The pooling agreement should be recorded to provide third parties with notice of the terms of the agreement. If obtaining consent is not an option, compulsory pooling by the governing state agency would be the alternative.

Some leases require that notice of the pooling be provided to the lessor in order for the pooling to be effective. If the pooling clause requires that notice be mailed to the lessor, an effort should be made to locate both the last address of record and a current address, utilizing online resources. If a more recent address is discovered, the notice should be mailed to both the address of record and the new address that was located. More commonly, the lease requires that for it to be properly pooled, a proper declaration of pooling needs to be executed and recorded by the lessee in the applicable county. Care should be taken in drafting the declaration of pooling. It should be signed by all parties owning a working interest in the lease. In order to be recorded, the signatures will need to be originals and it will need to be notarized. It should describe the specific lease(s) being pooled, including the recording information (Book/Page, Entry No.) for each lease. It should cite the authority to pool contained in the lease, for example: “Pursuant to Paragraph 10 of the lease.” It should define the pool, the total lands included and the formation(s) covered. If the lease covers more lands than what is being pooled, the declaration should describe all of the lands covered by the lease. This is particularly important in states that utilize a tract index recording system. If the pooling is in conformity with a state spacing order, it should be noted. If the party executing the declaration was not the original lessee, a statement as to the succession (Book/Page, Entry No. of the document transferring the interest in the lease) should be included. If the operator is drilling the well to earn an interest in the lease from another party, for example under a farmout agreement, it is recommended that the declaration be executed by both the record title owner and the party that is to earn the interest. Doing this would avoid any dispute as to the correct party to execute the declaration. Once executed, confirmation should be made that the declaration of pooling is properly recorded and, if it is a tract index state, that it is has been properly indexed against the lands.

Confirmation should be made that the effective date of the pooling is either the date of, or prior to the date, of first production. The effective date should also be prior to the termination date of the lease. Most lease provisions provide that the declaration of pooling must be prior to lease expiration. In the event the well was drilled prior to lease expiration, but the declaration of pooling was not timely recorded in order to avoid any issue, the lessor should execute a pooling declaration which includes a statement that the lease was properly pooled prior to the expiration date of the lease.

Finally, after reading the specific pooling provisions in the leases to be pooled, a broader examination of some additional issues raised by pooling the lease should be conducted. Confirmation should be made that all of the leases to be pooled are private leases. If the pool includes either federal, Indian, or state leases, additional steps will be needed to pool these leases. As to state leases, various state agencies have adopted different rules and procedures regarding private pooling agreements. As to federal and Indian leases, there are two ways to pool them: a federally approved unit or communitization agreement. The nuances of federal unitization and communitization will be further explored in a subsequent article in this series.

1 Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § P Terms. (LexisNexis Matthew Bender 2016).

Pugh(eee)…Get Those Lands Outta Here: A Look at the Pugh Clause

For the unwary, Pugh clauses (pronounced “Pew”) can sometimes stink.  Although it is a fairly common provision in many fee oil and gas leases today, there is no industry standard Pugh clause.[1] As a result, the many variations of the Pugh clause can provide unpleasant surprises to both lessors and lessees who assume that all Pugh clauses operate similarly.  From an industry perspective, it is essential for landmen negotiating oil and gas leases to understand how a Pugh clause will operate an­­­­d potentially affect other provisions in the lease.  Additionally, with the sharp decrease in oil prices, many oil and gas companies have pushed drilling schedules into the indefinite future.  The delay in drilling necessitates a careful review of the underlying lease portfolios to determine when certain leases will expire. A thorough understanding of the effect of a  Pugh clause’s on a lease is vital to this review.

So What Is It?

As a general rule, production, or other operations, on “any part of the land, included in an oil and gas lease will perpetuate the lease beyond the primary term as to all of the land covered by the lease.”[2] Moreover, if lands are pooled or unitized, production or operations on any of the lands within the unit can extend all leases committed in whole, or in part, to the drilling or spacing unit.[3] This means that an oil and gas lease can be held past its primary term by production on only a small portion of the leased lands or on lands outside of the leased lands that are located in a drilling or spacing unit. Understandably, lessors can be less than thrilled to discover that all of their lands are locked-up by a lease when only a small portion of their lands are included within a drilling or spacing unit—preventing them from re-leasing their non-producing lands so that they can receive additional bonus payments, rentals, or production royalties from these lands. Without an “express provision in the lease, the lessor only has recourse to the implied covenant of reasonable development (or further exploration in a state that recognizes such a covenant)” to force additional development on the lessor’s lands or allow them to re-lease the lands altogether.[4]

A Pugh clause can prevent this scenario. Named after a Louisiana lawyer named Lawrence Pugh,[5]  the Pugh clause operates to sever the non-producing lands or interval based on some defined criteria, such as acreage or depth.[6] The impact of a Pugh clause “increases the burdens on the lessee who must take additional steps to maintain the lease as to the [non-producing portion]; this may include a return to delay rentals,” (if the lease is not a paid-up lease), “or initiation of drilling operations within a specified period.”[7] In other words, by including a Pugh clause in a lease, any production located on or attributed to leased lands will no longer be sufficient to extend the primary term for the entire leasehold. If the lessee takes no actions to extend the lease excluded by operation of the Pugh clause, the lease will expire as to these excluded lands. This provides an obvious benefit to lessors, who can once again make the forfeited lands available for lease. Since Pugh clauses are decidedly pro-lessor, they are “virtually always inserted into or attached to a lease at the insistence of the lessor’s attorney.”[8]

Horizontal and Vertical Pugh Clauses

It is important to note that Pugh clauses can be horizontal, vertical, or both.  A horizontal Pugh clause “has the effect of severing a leasehold as to the pooled and non-pooled portions on the basis of horizontal planes,” while a vertical Pugh clause “has the effect of severing a leasehold on the basis of vertical planes only.”[9] This means a Pugh clause can be structured by depth (e.g., severing all lands below 100 feet of a drilled well or the bottom of the producing zone), or by acreage.

Give Me An Example

Because there is no industry standard Pugh clause, there can be as many different forms of the clause as there are people drafting the clause.  The following is an example of a generic Pugh clause:

A producing well, or well capable of producing, will perpetuate this lease beyond its Primary Term ONLY as to those lands as are located within, or committed to, a producing or spacing unit established by Government authority having jurisdiction.[10]

This provision in an oil and gas lease operates to segregate the lease at the end of the primary term according to whether the leased lands were within a drilling or spacing unit established by the appropriate government agency. Any lands not located within a drilling or spacing unit would not be extended by production (keeping in mind, of course, that these lands could be extended by other provisions in the lease, such as those pertaining to drilling operations). As a title examiner, it’s not uncommon to see other triggering criteria in a Pugh Clause—such as one or two years after the end of the primary term, or when drilling operations on any portion of the leased lands cease for a specified amount of time.

It’s crucial to clearly specify how and when the clause will come into play, as illustrated by the following real-life Pugh clause:

Notwithstanding anything to the contrary herein, this lease shall terminate after the primary term as to all the lands not included within a drill site spaced unit as provided by the proper Governmental Authority….

This Pugh clause is poorly drafted because it segregates the leased lands only on the basis of whether they are within a “drill site spaced unit,” without clearly specifying that the spaced units must also be producing in order for the lease to be extended beyond its primary term for those lands.  Read literally, the provision raises the question of whether a lease would be extended for lands that are merely subject to a spacing order (and thus presumably within a drill site spaced unit) when there is no production within the drilling or spacing unit, assuming that there is production elsewhere on the lease lands, as was the case in this instance.[11] Although it’s likely that the parties to the lease intended that the clause include a production requirement, it’s uncertain how a court would rule if this clause was litigated, particularly since Pugh clauses tend to be strictly construed.[12]

Problematic Pugh clauses, such as the example above, often arise when the Pugh clause is merely copied and pasted from another oil and gas lease, which can result in omitted words or phrases, or inconsistencies with other provisions of the lease. Problems can also arise when a Pugh clause is drafted by a person who does not fully understand the impact of words or phrases included in, or excluded from, the provision.

Be Careful

As illustrated by the poorly drafted Pugh clause above, not all Pugh clauses are created equal, and it’s important to review and understand the specifics of a Pugh clause when negotiating an oil and gas lease, or when later evaluating how a Pugh clause affects the extension of a lease.


[1] 1 Bruce M. Kramer and Patrick H. Martin, The Law of Pooling and Unitization, § 9.01 (LexisNexis Matthew Bender 2015), hereinafter referred to as “Pooling and Unitization,” citing Robin Forte, “Helpful Hints: The ‘Pugh’ Clause,” 42 Landman 9 (May/June 1997) (“Just as there is no standard oil and gas lease, today there is no standard ‘Pugh’ clause.”).
[2] Adams, James W., Jr., “Lease Issues for Opinion Purposes,” Nuts and Bolts of Mineral Title Examination, Paper 11, Page No. 517 (Rocky Mt. Min. L. Fdn. 2015), hereinafter referred to as “Lease Issues”.
[3] Id.
[4] Pooling and Unitization § 9.01.  For a discussion on the implied covenant to develop as it relates to Montana law, see Miller, Adrian, “The Implied Covenant to Drill and Develop in Montana,” available at:  https://www.hollandhart.com/implied-covenant-to-drill-and-develop-in-montana.
[5] Pooling and Unitization § 9.01, ft. 3.
[6] Patrick H. Martin and Bruce M. Kramer, Williams & Meyers, Oil and Gas Law § 669 (LexisNexis Matthew Bender 2015), hereinafter referred to as “Oil and Gas Law.”
[7] Pooling and Unitization § 9.01.
[8] Pooling and Unitization § 9.04.
[9] Oil and Gas Law § H Terms. According to one commentator, the terms “horizontal Pugh clause” and “vertical Pugh clause” are often mistaken with one another and, as a result, are used somewhat interchangeably within the industry.  Consequently, the commentator suggests that Pugh clause should clarify whether the provision affects depth or acreage. See http://landmaninsider.com/pugh-clauses/.
[10] This example is given in Lease Issues, p. 518.
[11] The question regarding this Pugh clause’s operation might be even more muddled in some states, such as New Mexico, which have standard spacing requirements.  See N.M. Admin. Code 19.15.15.
[12] Pooling and Unitization § 9.01. The treatise notes, however, that “strict construction is by no means uniform,” and “a few courts have seemed almost eager to interpret such provisions in favor of the lessor through readings that do not appear entirely reasonable.”  Id.

The Mother Hubbard Clause

Imagine a scenario in which the property description in one of your leases, meticulously transcribed from a document in the record chain of title, is later found to describe only a portion of the lands thought to be included. You are suddenly at risk of losing part, if not all, of your investment. What do you do? The answer depends on whether the lease contains a “Mother Hubbard clause.”

What is a Mother Hubbard Clause?

The “Mother Hubbard” or “cover-all” clause is a common provision in an oil and gas lease1 that provides a mechanism to include lands not adequately described in the lease or certain interests that vest after the lease has been issued.2 It was primarily designed to protect against the loss of small strips of land that were unintentionally omitted from the property description. But it was also meant to ensure that certain types of after-acquired interests, such as those acquired through adverse possession, were covered by the lease.3 At its core, the Mother Hubbard clause is an insurance policy.

Although many variations exist, the Mother Hubbard clause typically consists of two basic components. The first is a property catch-all. For example, the property description might state that “in addition to the described premises the lease covers adjoining, contiguous, or adjacent lands owned by the lessor.” The second component is meant to cover any interests that vest in the lessor after the lease has been issued. This language will likely include a statement that “the property includes any interests which the lessor may hereafter acquire by revision, prescription or otherwise.” Most modern Mother Hubbard clauses include both of these safeguards. (more…)

A Roadmap for Commencement of Drilling Operations: Are We There Yet?

For oil and gas lessees, the journey from signing a lease to having a producing well can be a long and arduous one. Countless turns, speedbumps and stops along the way can reasonably be expected. The habendum clause alone can quickly bring the lease to a screeching halt. Savings clauses have been inserted into modern fee oil and gas leases to prevent automatic termination of the lease while the lessee conducts certain operations. Discussed herein is the commencement of drilling operations savings clause which, in the majority of states, will permit a lease to be preserved after the expiration of the primary term without production if certain operations are being conducted.1 However, even with this savings clause, lessees should be particularly wary of the roadblock approaching at the end of the primary term when determining whether drilling operations were properly commenced before expiration of the primary term. Well-constructed language in a fee oil and gas lease can allow continued operations even if the primary term has expired and the drill bit has not yet broken ground.2

Which lease provision is the commencement of drilling operation clause?

The following is an example of a commencement of drilling operations savings clause:

Notwithstanding anything in this lease contained to the contrary, it is expressly agreed that if Lessee shall commence drilling operations at any time while this lease is in force, this lease shall remain in force ….

Such clauses may include variations such as “commence operations to drill a well,” “commence drilling or re-working operations,” “commence or cause to be commenced the drilling of a test well,” “commence the drilling of a well in search for oil or gas,” “commence to drill a well,” “if no well be commenced,” “lessee is then engaged in drilling for oil or gas,” “lessee is then engaged in drilling or reworking operations thereon,” or “start drilling for oil.” 3 The question to be answered is what operations must a lessee commence to preserve the lease?4

What does commence mean?

Generally, the majority of the states hold that, unless otherwise provided for in the lease, actual drilling is not necessary in order to reach the threshold for commencement of operations. Courts have proved willing to find commencement of operations even when only “modest” preparations for drilling have been made, such as erecting a part of an oil derrick and working on providing a water supply for drilling.5 Other preparatory activities such as obtaining drilling permit, staking and leveling the well location,6 building board roads to the drill site and a turn-around,7 moving tools and equipment onto the drill site, digging slush pits,8 and similar on-site activities have been held sufficient to be considered commencement of drilling operations.9 In order to reach the commencement of drilling operations threshold, a lessee should conduct as many on-site work activities as it can before the primary term expires. When determining adequate operations for commencement, courts favor active earthwork, clearing, construction, structure placement, etc., as opposed to gathering data, developing reports, obtaining permits, having meetings, and filing paperwork.

Courts have further required that such operations must be performed with the bona fide intention to proceed with good faith and diligence to the completion of the well.10 In a case where the preliminary commencement activities were performed by a company that had not yet acquired the rights to drill due to negotiations over the terms of a farmout agreement, the Wyoming Supreme Court held that the drilling operations were not done in good faith with the intent to complete insofar as the operator’s rights were qualified and contingent and may not ever be realized.11

When does the clause require actual drilling?

Some jurisdictions have differentiated between “commence operations” and “commence drilling operations.” California, Kansas, and Montana courts have made such distinctions and held that “commence drilling operations” or similar language required the drill bit to penetrate the ground prior to the end of the primary term.12 However, a Wyoming court held that there is no such distinction13 and “commence to drill a well” may be satisfied if preliminary commencement activities are not mere pretenses or a holding devise to retain the lease, if the acts are commenced and prosecuted with good faith and bona fide intention to drill and complete the well, and performed with diligence.14 Additionally, the Eighth Circuit Court of Appeals, applying North Dakota law, dismissed an argument that “engaged in drilling or reworking operations” meant “engaged in drilling” (meaning actual drilling was required) or “engaged in reworking operations;” rather, the court interpreted the clause as being engaged in “drilling operations” or “reworking operations.”15

What about off-lease operations?

With the advent of off-lease surface locations for horizontal wells, the question arises as to whether operations on or from off-lease surface locations will qualify as commencement of drilling operations on the leased lands. There is currently little guidance to answer this question. As suggested by other authors, we recommend that new oil and gas lease forms and existing oil and gas leases be amended to include a provision similar to one of the following:

(1) As used herein, the term Operations shall mean any activity conducted on or off the leased premises that is reasonably calculated to obtain or restore production, including without limitations, (i) drilling or any act preparatory to drilling (such as obtaining permits, surveying a drill site, staking a drill site, building roads, clearing a drill site, or hauling equipment or supplies); (ii) reworking, plugging back, deepening, treating, stimulating, refitting, installing any artificial lift or production-enhancement equipment or technique; (iii) constructing facilities related to the production, treatment, transportation and marketing of substances produced from the leased premises; (iv) contracting for marketing services and sale of Oil and Gas Substances; and (v) construction of water disposal facilities and physical movement of water produced from the leased premises;16 or

(2) All operations conducted off the leased premises that are intended to result in the completion of, or restoration of production from, a producing interval on the leased premises or lands pooled or unitized therewith shall be considered operations conducted on the leased premises for purposes of extending and/or maintaining this lease in effect under any other paragraph or provision hereof.17

The lease, of course, would need to be further reviewed to confirm that the use of either of the above suggestions does not create any inconsistencies or confusion and all capital terms (if applicable) are appropriately defined.

What should I do?

In determining whether a lease has been extended beyond its primary term by the commencement of certain operations less than spudding the well, it is critical the specific language of the lease, the specific facts, and case law for the state in which the leased lands are located are reviewed. Even then, it may be difficult to conclusively determine whether the lessee’s actions are sufficient absent actual penetration of the ground with a rig sufficient to reach a producing zone. Facing any uncertainty, if the lease and case law lack clear standards, the safest course of action, if possible, would be to get an extension of the lease.

1Williams & Meyers, Oil and Gas Law § 617 at 297 (2012).
2This article is limited to fee oil and gas leases. As to federal oil and gas leases, actual drilling operations must be commenced prior to the expiration of the primary term – the bit must be “turning to the right” prior to 11:59 p.m. on the last day of the primary term. 71 Interior Dec. 263 (July 10, 1964). Site preparation and even moving a rig onsite do not qualify as actual drilling operations. 43 C.F.R. § 3100.0-5(g).
3Williams & Meyers, supra note 1, § 618.1 at 311.
4Not addressed herein is whether the commencement of drilling operations clause in the habendum clause of the lease also has the effect of being a continuous drilling clause, i.e., if the well is drilled as a dry hole, does the lessee have the right to commence a second well?
5Williams & Meyers, supra note 1, § 618.1 at 320.
6Petersen v. Robinson Oil & Gas Co., 356 S.W.2d 217 (Tex. App. 1962).
7Breaux v. Apache Oil Co., 240 So.2d 589 (La. App. 1970).
8Walton v. Zatoff, 125 N.W.2d 365 (Mich. 1964).
9See Oelze v. Key Drilling, Inc., 135 Ill. App. 3d 6, 481 N.E.2d 801 (5th Dist. 1985) (a drilling rig was moved near the site, brush cleared and one of three pits were dug before the end of the primary term was found to be “commence operations for drilling”); Johnson v. Yates Petroleum Corp., 981 P.2d 288 (N.M. Ct. App. 1999) (any activities in preparation for, or incidental to, drilling a well).
10See Sword v. Rains, 575 F.2d 810 (10th Cir. 1978); Wold v. Zavanna, LLC , 2013 WL 6858827 (D.N.D. Dec. 31, 2013); Murphy v. Amoco Prod. Co., 590 F. Supp. 455 (D.N.D. 1984); Stoltz, Wagner & Brown v. Duncan, 417 F. Supp. 552 (W.D. Okla. 1976) (not required to cause the bit to pierce the earth before the end of the primary term, but must have the good faith intention to unqualifiedly drill the well, commence drilling the well on such date and pursued such drilling as a reasonably prudent operator); Haddock v. McClendon, 266 S.W.2d 74 (Ark. 1954); Oelze v. Key Drilling, Inc., 135 Ill. App. 3d 6, 481 N.E.2d 801 (5th Dist. 1985); Illinois Mid- Continent Co. V. Tennis, 122 Ind. App. 17, 102 N.E. 2d 390 (1951) (lessee lacked good faith); Flanigan v. Stern, 265 S.W. 324 (Ky. 1924) (requiring after spudding reasonably diligence and bona fide effort); Smirth v. Gypsy Oil Co., 265 P. 647 (Ok. 1928); Bell v. Mitchell Energy Corp., 553 S.W.2d 626, 632 (Tex. App. 1977); LeBar v. Haynie, 552 P.2d 1107, 1111 (Wyo. 1976).
11True Oil Co. v. Gibson, 392 P.2d 795 (Wyo. 1964).
12Lewis v. Nance, 20 Cal. App. 2d 71, 66 P.2d 708 (4th Dist. 1937); Hall v. JFW, Inc. 893 P.2d 837 (Kan. 1995); Soldberg v. Sunburst Oil & Gas Co., 235 P. 761 (Mont. 1925) (“commence drilling operations for oil”).
13Fast v. Whitney, 187 P. 192 (Wyo. 1920) (“commences drilling”).
14LeBar v. Haynie, 552 P.2d 1007 (Wyo. 1976) (“commence to drill a well”); True Oil Co. v. Gibson, 392 P.2d 795 (Wyo. 1964).
15Anderson v. Hess, 733 F. Supp. 2d 1100, 1106-07 (D.N.D. 2010) aff’d 649 F.3d 891, 898 (8th Cir. 2011) (insofar as the lessor conceded that the lessee was engaged in drilling operations before the primary term expired, the court did not address whether the lessee’s preparatory activities were satisfactory to constitute drilling operations.). See also Wold v. Zavanna, LLC , 2013 WL 6858827 (D.N.D. Dec. 31, 2013) (granting summary judgement in favor of the lessee based on Anderson v. Hess and finding “drilling or reworking operations” had been commenced when lessee obtained all drilling approvals, engaged in actual on-site construction, hauling of equipment and materials on site, installing culverts and cattle guards, and digging reserve pit prior to the expiration of the primary term and finding that the lessee had capability to drill the well and good faith intent to complete the well with reasonably diligence).
16Milam Randolph Pharo & Gregory R. Danielson, “The Perfect Oil and Gas Lease: Why Bother!,” 50 Rocky Mt. Min. L. Inst. 19-1, 19-18 (2004).
17John W. Broomes, “Spinning Straw Into Gold: Refining and Redefining Lease Provisions for the Realities of Resources Play Operations,” 57 Rocky Mt. Min L. Inst. 26-1, 26-12 (2011).

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

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).
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.
14From the Modified Lynch Form. Pharo, supra note 6 at Appendix A.

Deducting Post-Production Costs From Fee Royalty

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


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).
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.
2629 P.3d 887 (Colo. 2001).
27Id. at 902.
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 Rogerssee Pierce, supra, at 358-364; see also Martin & Kramer,supra, at § 645.