Real Estate Center

Director

Dr. R. Malcolm Richards

The Real Estate Center was created in 1971 by the Texas Legislature and placed at TexasA&M University.

The Center conducts a comprehensive program of research and education to meet the needsof many audiences, including the real estate industry, instructors and the general public.

A catalog describing hundreds of publications and computer programs is free for the asking.Write the Real Estate Center, Texas A&M University, College Station, Texas 77843-2115 ortelephone 1-800-244-2144. Timely real estate information also is available on the Internet athttp://recenter.tamu.edu.

Advisory Committee

John P. Schneider, Jr., Austin, chairman; Gloria Van Zandt, Arlington, vice chairman; Joseph A.Adame, Corpus Christi; Celia Goode-Haddock, College Station; Carlos Madrid, Jr., San Antonio;Catherine Miller, Fort Worth; Kay Moore, Big Spring; Angela S. Myres, Houston; Jerry L. Schaffner,Lubbock; and Pete Cantu, Sr., San Antonio, ex-officio representing the Texas Real Estate Commission.

Reprinted July 1997© 1997, Real Estate Center. All rights reserved.

Solutions Through Research

Contents

Summary ........................................................................................................................................1

Leasing Provisions .........................................................................................................................1

Granting Clause .............................................................................................................................2

Granting Clause and Surface Operations .....................................................................................2

Duration of the Lease ....................................................................................................................3

Extension of the Primary and Secondary Terms ..........................................................................3

Royalty Clause ...............................................................................................................................5

Surface Damages ............................................................................................................................7

Pooling............................................................................................................................................7

Assignment Clause .......................................................................................................................8

Warranty Clause ............................................................................................................................9

Lessee's Right to Free Water, Oil and Gas ...................................................................................9

Force Majeure Clause ..................................................................................................................10

Horizontal Drilling ......................................................................................................................10

A Leasing Perspective ..................................................................................................................11

Other Terms for the Mineral Owner's Consideration...............................................................14

Conclusion ...................................................................................................................................15

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SummaryFrom the mineral owner’s perspective, an oil company seeking a lease is

generally a welcome sight. The prospect of productive wells on the propertycould mean substantial income. Before exploration can begin, however, themineral owner (lessor) and the oil company (lessee) must agree to certain termsregarding the rights, privileges and obligations of the respective parties duringthe exploration and possible production stages. The negotiation of these termsmay be the mineral owner’s first exposure to an oil and gas lease. Because ofthe legal nature of the leasing arrangement, an inexperienced mineral ownermay be at a disadvantage when dealing with a more experienced lessee.

The purpose of this report is to acquaint nonexperts with the more commonprovisions of an oil and gas lease and explain their legal significance. Thereport details some provisions that the mineral owner may wish to insert forpersonal benefit and protection. However, the report is not a substitute forlegal counsel.

Leasing Provisions

N o standard or universal leaseform is used by the oil and gasindustry. Instead, each company(or independent lessee) has a

predrafted agreement, usually some versionof a Producers 88 Lease Form that has provensuitable to them in the past. The agreementmay not necessarily be in the best interest ofthe mineral owners.

Mineral owners should remember that allprovisions of a lease are negotiable. Eventhough the oil company representative orlandman soliciting the lease may be unau-thorized to make changes, certain clauses oreven the complete lease may be altered.However, the mineral owner’s ability tonegotiate more favorable terms varies witheach situation.

Three factors influence the negotiatingpower of the mineral owner. The first is theamount of acreage the lessor controls. Thesecond is the proximity of the acreage toknown production. And the third is thenumber of oil companies vying for the lease.The ideal situation for the mineral owner isto have a larger tract next to a newly discov-ered field with numerous oil companiesseeking a lease.

If favorable terms are negotiated, theyshould be in writing and incorporated intothe lease. There are three acceptable meansof accomplishing this.

First, for minor modifications, strike theprovision to be altered, insert the change andinitial the margin of the page (both parties).Some authorities want the date inserted nextto the initials. This process would be fol-lowed when changing the lease royalty from1/8 to 1/6.

Second, for more pronounced modifica-tions, attach an addendum to the lease. Thepreface to the addendum begins, "Notwith-standing anything to the contrary in theforegoing Oil, Gas and Mineral Lease, thefollowing terms and provisions control. . . ."The individual changes are then listed.

If the addendum becomes quite extensive,and if it contains terms the lessee does notwant to become public knowledge, a Memo-randum Lease may be executed and recordedin its place. The Memorandum Lease con-tains the minimal information necessary togive constructive notice of the lessee's oiland gas lease. Generally, it will recite thename and address of both the lessor andlessee, the lease date, the length of theprimary term and the legal description of theproperty.

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Third, a way to make changes to a leaseand, at the same time, to keep the changesfrom becoming public information is toenter a letter agreement. Letter agreementsgenerally are used to clear up minor prob-lems with the lease just prior to the com-mencement of drilling operations.

Granting ClauseThe opening paragraph of the lease is the

granting clause. It outlines the purpose ofthe lease and describes the substances thatcan be explored and produced. Typically, theclause will state that the lease is given forthe purpose of exploring, drilling, miningand producing oil and gas and all otherminerals, whether similar or dissimilar.

If substances other than oil and gas areproduced, two problems become apparent inTexas. First, if the substances sought lie nearthe surface or will substantially damage thesurface when produced, the substance maybelong to the surface owner. (This creates aproblem only when the mineral owner is notthe respective surface owner.) Second, ifsubstances other than oil and gas or associ-ated hydrocarbons are discovered, will thelease cover them? (For more information, seeMinerals, Surface Rights and Royalty Pay-ments, publication 840.)

There are no easy answers, but here aresome suggestions to consider:

• To avoid any dispute between thesurface and the mineral owners, specifythat the extraction method used by thelessee can be through a borehole only.Bar all strip mining and other methodsthat substantially destroy the surface.Mineral owners must realize that allsubstances lying beneath the surface donot necessarily belong to the mineralowner.

• Resolve speculation concerning thesubstances covered by the lease byspecifying those included to the exclu-sion of all others, i.e., all petroleum andnatural gas and related hydrocarbonsexcept coal, lignite and uranium.

Granting Clause and SurfaceOperations

With few exceptions, the grant of an oiland gas lease carries the implied right to use

as much of the surface area as is reasonablynecessary to explore and produce the oil andgas. Most leases expand these implied rightsand explicitly permit a wide range of surfaceactivities.

Even though the lessee may be liable forsurface damages (see p. 7), the inconvenienceof unwanted and unwarranted structures andentries upon the surface may be avoided tosome degree by the following:

• Do not grant an unrestricted right forthe underground disposal of salt waterin abandoned wells on the property.Instead, state that prior written consentof the lessor is needed.

• Confine the lessee’s routes of ingressand egress to existing roadways on theleased premises. If deviations arenecessary, require them from thenearest roadway. Determine whethernew roadways built by lessee must beremoved when the lease terminates.Specify where cattleguards are requiredand who will maintain locked gates.Discuss erosion prevention techniquesalong roadways and around drill sites.For convenience sake, leases generallydo not permit wells within 200 feet (orsome other stipulated distance) of adwelling. The mineral owner may wantmore distance. Further, provide that allunderground transmission devices suchas pipelines and telephone lines mustbe buried below plow depth (or aspecified depth) in agricultural areas.

• Mineral owners wishing to cultivate orgraze the area immediately above anypipelines should direct the lessee to usethe double ditch method for laying pipe.This method requires the top soil to beplaced on one side of the trench and thesubsoil on the other. When backfilling,the subsoil is replaced first, followed bythe top soil.

• In Texas, the lessee has the impliedright to use caliche found on the leasedpremises free of charge for constructionof drill sites and roads. The mineralowner may wish to alter contractuallythis rule in the lease.

• Specify that the lessee’s structures andequipment must be removed within acertain time after the lease expires or be

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forfeited. Otherwise, problems mayarise concerning their ownership.

• Identify the parties liable for the con-struction and maintenance of fencesand gates or similar structures aroundthe premises, pits, drilling sites andabove intersecting pipelines. Theprecise dimensions and characteristicsof the fences and gates may need to beincluded.

• The mineral owner may require priorconsent for conducting seismic or othergeophysical operations. With the adventof three-dimensional (3-D) seismic, thepotential for surface damages is signifi-cantly increased, adding to the impor-tance of this clause.

• If the lessee must cut a fence to build aroad or install a pipeline, describe themethods for bracing the fence prior toits breach.

Duration of the LeaseLeases are divided into two periods. The

first period (primary term) is a set number ofyears negotiated by the parties during whichdrilling operations must begin or delayrentals must be paid. The lease generallystates that if drilling operations are not beingconducted within one year after the lease isentered, the lease terminates unless anagreed sum is paid to the lessor. This sum iscalled a delay rental. Delay rentals must bepaid on each subsequent anniversary date ofthe primary term whenever drilling opera-tions or production are inactive.

Failure to receive a required delay rentalpayment automatically terminates the leasewhenever the word unless is used to indicatethe necessity of the payment. Some leasescontain the word or rather than unless. Inthe latter case, the lease will not terminatefor a delinquent payment. Some leases haveall the delay rentals paid in advance at thecommencement of the lease. These areknown as paid-up leases.

If production is not established by the endof the primary term, the lease will end. Ifproduction has been established, the leasewill continue into its secondary term andlast so long as substances covered by thelease continue to be produced. Generally thefull clause will read, "This lease shall remain

in force and effect for a term of ______ yearsand as long thereafter as oil, gas or othermineral is produced from said land." Newerleases substitute the word operations forproduction. These leases read, ". . . as longthereafter as operations, as herein defined,are conducted upon the said land."

For protection, the lessor should consider oneor more of the following recommendations:

• Strive to keep the primary term as shortas possible. This will force earlierexploration.

• If the primary term cannot be short-ened, strive to negotiate a higherannual delay rental payment.

• Make sure the word unless is used.Avoid using the word or. Keep a watch-ful eye on the date by which the delayrental payments must be received.Acceptance of a late payment may beconstrued as a ratification, and thelease will not terminate.

• Require the lessee, when tenderingdelay rentals, to identify the leasenecessitating the payment. This is aninvaluable aid for mineral ownerstrying to keep track of several differentleases on their land, especially when allor part of a lease has been assigned toanother oil company.

• State that the delay rentals must bereceived, not simply postmarked, on orbefore the due date. Delete any leaseprovisions requiring the prior notice tothe lessee of nonpayment of delayrentals before the lease will terminateas drafted in a 12/79 Producers 88 LeaseForm.

Extension of the Primaryand Secondary Terms

The primary and secondary terms of thelease may be extended via the shut-inprovisions, dry-hole provisions andcessation-of-production provisions. Mostleases contain all three.

The shut-in provisions allow the lease toremain in effect whenever the productionfrom a well is not being sold or used by thelessee. Only a well capable of producing inpaying quantities may be shut in. A shut-inwell, though, is classified as a producing

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well, and the lease will not terminate aslong as the shut-in continues. Even so, ashut-in royalty (generally a sum approximatingthe amount of the delay rental payment)must be paid annually after the expiration ofthe primary term to continue the lease.

The dry-hole provisions, on the otherhand, will extend both the primary andsecondary terms of the lease. Basically, thelease provides that if oil or gas has not beendiscovered when a dry hole is drilled, thelessee has several options for continuing thelease. First, in the event the primary termhas not expired and more than 15 monthsstill remain, the lessee has two options. Thelessee either can pay the next delay rentalpayment that comes due 90 days after thedry hole was drilled or alternatively com-mence drilling or reworking operations on orbefore the next anniversary date occurring 90days after the dry hole.

Second, if less than 15 months remain inthe primary term, the lease will continue tothe end of the primary term even though thelessee's operations remain idle and no delayrentals are paid. However, drilling or rework-ing operations must recommence on orbefore the end of the primary term to con-tinue the lease.

Finally, if the lessee was in the process ofdrilling a well when the primary term ended,the lease will not terminate when the dryhole is discovered. Instead, the lessee has 90days to resume drilling or reworking opera-tions to continue the lease. (A 90-day periodis the most common time frame. However,the period may vary from 60 to 180 days,depending on the lease.)

The cessation-of-production provisionscorrespond quite closely to the dry-holeprovisions. The main difference is that thecessation-of-production rules apply only afteroil and gas have been discovered. In thisevent, the lease provides that if oil and gasproduction should cease for any reason, thelease will continue if the lessee follows oneof the options previously described for thedry-hole provisions.

It is theoretically possible for the leaseterm to be extended indefinitely via the dry-hole and cessation-of-production provisions.If the lessee has not discovered oil or gas,and if the lessee is in the process of drillingor reworking operations when the primary

term ends, the lease will continue in forcefor so long as the lessee faithfully renewsdrilling or reworking operations within 90days after the termination of each operation.However, if a producing well subsequentlyshould be discovered and its production laterceases, the lessee must again renew drillingor reworking operations within 90 days tohold the lease. Although the indefiniteextension is theoretically possible, in realityit does not happen because of the costsinvolved.

More recent leases combine the dry-holeprovisions and the cessation-of-productionprovisions under one general heading knownas operations.

Most mineral owners usually do notdisagree with the dry-hole and cessation-of-production provisions because, in eithercase, oil and gas are being sought diligently.However, mineral owners may have diffi-culty accepting the shut-in provisions,especially when no apparent reason fornonproduction exists.

Because of the high cost of bringing a wellon line, shut-in provisions are used rarelyexcept for the lack of a pipeline or buyer.Even so, mineral owners may wish toconsider the following alternatives:

• Place a maximum limit on the shut-in,i.e., no more than three years or threeyears beyond the end of the primaryterm. Beware of placing a limit on theconsecutive months for a shut-inwithout limiting the cumulativemonths.

• Possibly escalate the amount of theshut-in royalty payments for each yearthe gas or oil is shut in.

• As an alternative, permit the shut-in tocontinue after a stated period but onlyfor a given number of acres immedi-ately surrounding the well, i.e., 160acres. The rest of the lease reverts tothe lessor. (This provision may bequalified, depending on the reasons forthe shut-in.)

• Because shut-in royalties are generallyprepaid annually, confusion may arise ifthe lessee lifts the shut-in and producesduring the year. Is the lessee allowedcredit for both the money and themonths that were prepaid but not used?

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One alternative is for the lessee toprepay shut-in royalties monthly, notannually. Another is to require thelessee to account to the lessor for anymonths that were prepaid but not usedat the end of each payment period. Thefailure to account causes a forfeiture ofthe unused months.

• Specify the circumstances when theshut-in clause may be invoked, i.e., forlack of market, available pipeline orgovernmental restrictions. As a possiblealternative, permit the shut-in when, inthe lessee’s good faith judgment andwith the lessor’s consent, it is economi-cally inadvisable to produce.

• Consider limiting shut-ins to gas wellsonly. Exclude oil wells from shut-ins.

• Automatically terminate the shut-inwhenever a well located on adjacentland, situated within a certain numberof feet of the leased premises andcompleted within the same producingreservoir, begins producing and sellinggas in marketable quantities.

Royalty ClauseEach lease contains a paragraph that

allocates to the mineral owner a certainportion of the substances produced. Theallocation may be stated in terms of marketprice or value, proceeds or in kind. This isthe royalty clause. From an economicstandpoint, this may be the most importantclause to the mineral owner.

The terms of royalty clauses vary fromlease to lease. Through the evolution ofcourt cases, the clause has been clarified inTexas. However, the mineral owner stillshould consider several items.

One consideration is expense that can bededucted from the royalty payments. Thecosts encountered throughout the explora-tion, drilling, production and marketingstages are divided into two categories:

• those borne solely by the oil company(producer) and

• those shared by the mineral owner.

All expenses encountered through theproduction stages are borne solely by the oilcompany unless the mineral owner has

purchased a working interest in the well.Expenses subsequent to production eithercan be shared or borne solely by the oilcompany, again depending on the terms ofthe lease.

If any costs are shared, the lessor's per-centage is dictated by the size of the royalty.If the royalty is 1/6, the royalty owner'sshare is 1/6. By negotiating a larger royalty,the mineral owners, in effect, are agreeing toshoulder a greater percentage of the costs.

The shared expenses depend partly onwhere the lease fixes the royalty. Com-monly, the royalty for oil is set "at the well"or "wellhead." In such cases, the mineralowner’s royalty payment is free of produc-tion costs, but all costs subsequent toproduction are shared. (Two 1996 TexasSupreme Court decisions, Heritage Re-sources, Inc. v. NationsBank, 09-0515, andJudice v. Mewbourne Oil Co., 95-0115, soheld even though the lease addendum statedthe royalty was free of such costs.) If thelease fixes the royalty "in the pipeline," "atthe place of sale" or at other delivery points,different costs subsequent to production maybe shared. These costs may include itemssuch as compression expenses necessary tomake the product deliverable into thepurchaser’s pipeline, expenses necessary tomake the product salable, transportationcosts and the expenses used in measuringproduction.

Another consideration for the mineralowner is determining how the royaltypayment is valued or received. The leasesgenerally provide three methods.

First, the mineral owner’s royalty may bebased on the "market price" of the productproduced. Market price basically means thehighest posted field price existing for thefield. If there is no field price, then the valueis determined by comparable sales in time,quantity, quality and availability. And ifthere were no comparable sales, the actual orintrinsic value of the substance is used.

Sometimes the posted prices are discrimi-natory, set artificially and substantially lessthan the prices paid for comparable mineralsat other fields. In such cases, it may bepossible to get a higher valuation for theroyalty payments but only after a difficultburden of proof has been met by the mineralowner in a judicial proceeding.

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To avoid the problem, a formula may beinserted to determine how the market priceor value will be established. For example,some leases read, "at the highest price (orpercentage thereof) posted for a field within100 miles by any of the seven major oilcompanies for like grade and gravity on theday the oil is removed."

The second means of evaluating royalty is"proceeds." This method bases the royaltyupon the actual revenue derived from thesale of the mineral. As such, the resultingsales price may or may not equal themineral’s actual market price as discussedearlier. In the past, royalties based on pro-ceeds have been popular for marketing gas.By committing gas to long-term contracts,the producer could insure the mineral ownerof a constant, dependable royalty incomeover time. The disadvantage was that theresulting proceeds were not immediatelysensitive to a rising market.

The third method of receiving royalties is"in kind." This method presents an excellentalternative for dealing with a lease based onproceeds. By inserting an option to takeroyalties either "in proceeds" or "in kind,"the mineral owner can get the best of bothworlds. When the market price rises aboveany long-term commitment price, themineral owner can take his or her share "inkind" and seek a market outlet. When themarket price falls below any long-termcommitment, the lessor’s share can be takenin proceeds.

The in-kind, in-proceeds alternative isquite attractive to a mineral owner whenone or more gas wells or pipelines are dedi-cated to the highly regulated interstatemarket. By the mineral owner opting to takeroyalty "in kind," the gas possibly can besold on a more lucrative intrastate market.As a general rule, lessees are hesitant aboutgranting this option unless the lease is in amajor producing field. Otherwise, the cost ofstorage, accounting, delivery and otherassociated expenses will outstrip any gainsto the mineral owner.

Briefly, the following factors may beconsidered when negotiating a royaltyclause:

• Detail the time, place and frequencyroyalty payments are to be tendered.Outline the consequences for missing

royalty payments. Do not limit thepenalty for a delinquent payment tointerest only. Terminate the lease if thedelinquency exceeds a stated period,such as 180 days. Should the leaseterminate for nonpayment of royalties,make sure the equipment, tubing,casing and other machinery used inproduction are forfeited as well so themineral owner may use them to with-draw any remaining oil or gas.

• Discuss whether or not the lessee hasthe right to disburse royalty payments.Some purchasers will give 100 percentof the proceeds to the lessee and requirethe lessee to pay the royalty owners.Operators have been known to keep thefunds and disappear.

• Reserve the option to take "in kind" iffeasible.

• Consider an extra royalty (or overridingroyalty) based upon recovering all or acertain percentage of the productioncost from the well. The overridingroyalty also may be based on othervariables.

• Determine if and when the mineralowner should have access to free gas.Many leases allow the lessor the freeuse of gas for domestic (and sometimesagricultural) purposes.

• By the same token, decide whether thelessee should have free use of water, oiland gas produced on the leased pre-mises. (See p. 9 under the heading"Lessee's Right to Free Water, Oil andGas" for further details.)

• Provide that costs subsequent to pro-duction may be deducted from themineral owner's royalty, but that theywill be reimbursed on a quarterly basis.This may be one way to avoid theeffects of the Heritage and Judicedecisions mentioned earlier.

• State that any division order tenderedto the mineral owner after productionbegins cannot alter the lease. Texaslaw holds that any executed divisionorder that contradicts the lease over-rides the lease unless the division orderconforms to the one described in TexasNatural Resources Code Section91.402(c)(1). (See Minerals, Surface

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Rights and Royalty Payments, publica-tion 840, for more details.) Conse-quently, provide that if the division order,not in conformity with the statute,contradicts the lease, the mineral ownerhas the right to alter the division orderto comply with the lease before execut-ing it. If, by making the division ordercomply with the lease, additionalcharges are borne by the lessee, ask thelessee to agree to pay the additionalcharges in advance.

• Place a minimum royalty provision inthe lease. A minimum royalty provi-sion provides that unless a certainamount of revenue is received annuallyfrom royalties or other sources, such asshut-in royalties, the lease terminates.The minimum royalty provision pre-vents a small amount of productionfrom perpetuating a lease for a largenumber of acres. (For more information,see Termination of an Oil and GasLease, publication 601.)

Surface DamagesGranting an oil and gas lease carries the

implied right to use as much of the surfaceas is reasonably necessary for the develop-ment of the minerals. Only when the lesseegoes beyond what is reasonably necessary,negligently injures the surface area or fails toaccommodate estates will the lessee becomeliable to the surface owner for damages.Likewise, the lessee is under no legal obliga-tion to restore the surface when productionceases. (For more information, see Minerals,Surface Rights and Royalty Payments,publication 840.)

For better protection, the mineral ownermay wish to insert some provisions in thelease pertaining to surface damages. Forinstance, a lease clause requiring compensa-tion for all surface damages will render thelessee liable even though the injuries wereincurred during the reasonable developmentof the leased premises.

When compensation is required, it iscommonly made at the site when drilling orproduction operations cease. To avoid anyconflicts in this matter, the mineral ownershould consider the following items whennegotiating the lease:

• Require compensation for all surfacedamages such as injuries to growingcrops and pastures; erosion and stagna-tion of the soil; growing timber;livestock; fences, ditches, canals,buildings and other structures; and thepollution of any surface or subsurfacewaters.

• Require the lessee to restore the landwhen operations cease.

• Describe the method or methods to beused for determining the extent of thedamages. If the parties cannot agree,provide for some nonjudicial means ofresolving dispute. Selecting an ap-praiser agreeable to both parties todetermine the damages is a possibility.

• Determine if the compensation will bepaid annually or in a lump sum. In part,this decision will depend on whetherthe damages are temporary or permanent.

• Resolve beforehand how payments willbe distributed among the respectiveowners of the surface estate. Thisproblem mainly arises when an agricul-tural lessee is on the premises.

• Designate the time by which all claimsor notices must be submitted to thelessee and how soon thereafter thelessee must pay them.

• Possibly require a performance bond oran escrow account as security forpayment of surface damages beforedrilling operations begin.

• Another possibility is to require aspecific prepayment for each drill sitein lieu of subsequent surface damages.Approximate the payment based on thefair market value of the land used forthe drill site.

• If the lease is assigned, hold theassignor(s) and assignee(s) jointly andseverally liable for surface damages. Ifthis cannot be negotiated, requiresurface damages to be paid before thelease can be assigned. Otherwise, thelease may be assigned to a failing oilcompany that has no means of payingsurface damages.

PoolingMost leases will contain some provision

giving the lessee the right to consolidate the

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leased premises with adjoining leased tracts.The area thus formed is called a pool orsometimes a pooled unit. Pools are estab-lished to unite under one operator all themineral owners having an interest in acommon underground reservoir. By doing so,the lessee avoids unnecessary drilling,protects the rights of the mineral owners inthe common reservoir and prevents waste.Pooling also permits the lessee to drill thebest site otherwise prohibited by the statespacing requirement of 467 feet from a leaseline. Sometimes pooling arrangements arenecessary to meet the minimum acreagerequirement for a drilling permit under Rule37 of the Texas Railroad Commission.

In Texas, mineral owners may be subjectedto two types of pooling. One is voluntary,and the other is compulsory or statutory.The voluntary arrangement requires theconsent of the mineral owner and is gener-ally found in the context of most leaseforms. The statutory arrangement, on theother hand, is mandatory when the require-ments specified in Chapter 10 of the TexasNatural Resource Code have been met. Byentering either type of pooling arrangement,the mineral owner's share of the productionwill be determined by multiplying the leaseroyalty times the resulting fraction found bydividing the number of acres the mineralowner has in the pool by the total number ofacres in the pooled unit.

Obviously, the mineral owner can do littleto avoid compulsory or statutory pooling.However, the mineral owner may want to becautious before consenting to voluntarypooling. The following suggestions may behelpful:

• In Texas, unless the mineral ownerconsents to voluntary pooling, the leasecannot be pooled. Consequently, themineral owner may wish to withholdconsent until the full impact of thepooling arrangement on the lease termsis understood.

• Alternatively, the mineral owner mayconsent to voluntary pooling in thelease but state that any pooled unitformed using the leased premises mustcontain a minimum percentage of thelessor’s land.

• To limit a pool, stipulate the maximumacres a pool may contain. As a rule of

thumb, limit the acreage to no morethan that specified in the Texas statu-tory pooling provisions, which ispresently 160 acres for an oil well and640 acres for a gas well plus 10 percenttolerance for each. However, where thefield rules differ or where horizontaldrilling occurs, allow the size to con-form to whatever is needed for maxi-mum allowables based on the rules ofthe railroad commission.

• If possible, negotiate all pooling prior todrilling operations and not afterwards.

• Consider whether or not the lessee maychange the size or shape of the poolafter the mineral owner consents.

• In all cases, negotiate the inclusion of aPugh clause. A Pugh clause provides forthe severance of the lease between thepooled and unpooled acreage wheneverless than all of the lease tract is in-cluded in a pooled unit. The severancegenerally occurs at the end of theprimary term or at the end of a continu-ous drilling program, whichever islonger. By having the severance, opera-tions conducted on the pooled unit willnot hold unpooled acreage and viceversa.

Without a Pugh clause, leases generallyprovide that any operations conducted on thepool shall be construed as operations on theentire lease tract. Therefore, production,drilling or reworking operations conductedon any portion of the pool, whether actuallyon the lease tract or not, hold the entirelease.

• On larger tracts, modify the Pughclause for the severance between theacreage in a production or prorationunit (whether pooled or unpooled) andthe rest of the lease at the end of theprimary term. It is possible to create aproduction unit using only the acreagefrom one lease. (This is known as atract well.) In such cases, one wellholds all the leased premises unless thewording of the Pugh clause is modified.

Assignment ClauseTypically, leases contain a provision

permitting both the lessor and the lessee to

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assign their rights and interest under thelease. To a large extent, these provisions arefor the lessee’s benefit to negotiate withother oil companies.

A customary practice is for an individualor independent oil company to lease a largetract and assign (sell) all or a part of it toanother oil company. Consequently, theultimate developer-producer may not neces-sarily be the original lessee. To retain partialcontrol over assignments, the mineral ownermay incorporate some of the followingsuggestions:

• State that the lessee must notify themineral owner of any assignment. A1989 Texas appellate case upheld thevalidity of a clause providing for $1,000liquidated damages if the lessee fails tonotify the lessor of an assignment.

• Do not release the original lessee fromliability for a default on any assignedportion of the lease or leased area. Thisis particularly important when surfacedamages and royalties remain unpaid.

• Nullify any assignment unless theproduction from a well exceeds acertain limit. Many times a marginallease changes hands because anotheroperator has discovered the "key" formaking the well produce. The lesseewill attempt production, fail and leavewithout paying royalties and surfacedamages.

Warranty ClauseLeases generally contain provisions requir-

ing mineral owners to defend their interestin, or title to, the leased premises should anownership dispute arise. This is known asthe warranty clause. If the mineral ownerbreaches the warranty, the lessee has twoalternatives. The lessee may sue the mineralowner for the return of any considerationpaid for the lease such as bonuses, delayrentals or royalties. Alternatively, the lesseecan reduce any payments forthcoming to themineral owner according to undividedinterest owned by the mineral owner in theproperty. For example, if the lessor owns halfthe minerals and purports to own all theminerals, the oil company may pay thelessor only half the bonus, half the delayrentals and half the royalties. The latter

alternative is described in a lease provisionknown as the proportionate reductionclause.

To avoid litigation, mineral owners shoulddelete any language that infers they willwarrant or defend the chain of title to theland. Instead, a limited or special warrantyshould be used. Because most oil companiesor landmen generally conduct title searchesprior to leasing, negotiating a special war-ranty should not be a problem.

Lessee’s Right to Free Water,Oil and Gas

Mineral owners should pay close attentionto lease provisions allowing free water, oil orgas to the producer for operations. In Texas,the oil company has the right to use freshwater, found either above or below theground, for exploration and productionpurposes unless a change is negotiated.Particularly in areas where water is scarce,certain limitations should be placed on theserights.

• Decide whether free water, oil or gasprivileges should be granted to thelessee. If so, stipulate whether thesubstances may be used for operationsconducted both on and off the leasedpremises. (These provisions may beincorporated into the royalty clause asmentioned earlier.)

• If the land should contain a centralsupportive device, such as an oil-gasseparator, prorate the free use of oil andgas needed to run the separator accord-ing to the amount of production fromthe leased premises if free rights aregiven.

• Do not allow the lessee to take freewater from wells, tanks, ponds orreservoirs.

• Stipulate that any water use by thelessee cannot restrict the lessor’ssupply of fresh water for domestic,livestock or agricultural purposes.

• If secondary recovery operations areundertaken by the lessee involvingwaterflood operations, deny the use ofpotable water. State that such watermust come from nonfresh sources.

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• If water is to be purchased, state howthe price will be determined. Manymineral owners sell the water based onthe number of feet drilled for a verticalwell, i.e., 10 cents per drilled foot. Thismethod may be infeasible for a horizon-tal well because water usage is notalways a direct function of drilled feet.

• Possibly require the lessee to drill awater well for drilling and productionoperations. The water well with allpipes, pump, casing and so forth revertsto the mineral owner when the leaseterminates.

Force Majeure ClauseLeases generally contain provisions that

protect the oil companies from liability andloss of the lease whenever causes reasonablybeyond their control suspend operations.This is known as the force majeure clause.Mineral owners may consider several factorswhen this clause is proposed in a lease:

• Require a timely written notice of anysustained work stoppage. Require thenotice to specify whether the stoppagewas pursuant to the force majeureclause or the shut-in clause. The twogenerally overlap. However, a stoppageunder the force majeure requires nopayment while a sustained shut-indoes. Consequently, if they overlap,provide that a stoppage must be gov-erned by the shut-in.

• If an unavoidable stoppage should occurduring the primary term, require delayrental payments anyway.

• Also, specify how soon operations mustresume once the cause is removed.Some leases allow 15 months, but 90days may be preferable.

• Consider whether financial difficulties,lack of water, lack of materials, lack oftransportation facilities and so forthconstitute a force majeure.

Horizontal DrillingTwo factors contributed to the Texas oil

boom during the late 1970s and early 1980s.Foremost was the skyrocketing oil prices;the other was the intense drilling activity inthe Austin Chalk.

Ten years later, a new mini-boom struckthe oil fields. This time the price of oil wasnot a significant factor. Instead, it was therenewed drilling activity in the AustinChalk spurred by a new technique known ashorizontal drilling.

The Chalk is a narrow, cretaceous lime-stone formation running from Mexicothrough Texas. Its width varies from 20 to 30miles. The formation is punctuated withnumerous vertical cracks or fractures thatharbor potential oil-producing veins.

Much attention was focused on the Chalkduring the last oil boom because of a re-newed emphasis on fracturing techniques.Fracturing (or fraccing) is an artificial way toenhance the permeability (or flow) of theformation surrounding the well’s perforationpoint. Fluids such as sand and water, poly-mers and even crude oil are pumped into theformation under tremendous pressure.

Fraccing was important to the Chalkbecause conventional drilling could miss avertical fracture by a few feet. An apparentlydry hole could be transformed into a produc-ing well if linkage between the borehole andthe vertical fracture could be established.Thus, successful Chalk wells depended bothon a correct location and the proper fraccingtechniques.

In 1989, a new drilling technique knownas horizontal drilling was successfullyintroduced to the Chalk. The new techniqueeliminated the need for the drillstring topierce the fractures vertically. By usingredesigned tools, mud motors and flexibledrillstrings, drillers could make a verticalhole gradually turn 90 degrees. The horizon-tal drillstring could be directed to intersectnumerous vertical fractures.

Location is still important because costsare significantly increased. Beyond a 1,200-foot horizontal drainhole, the added costsmay cause an unsatisfactory return oninvestment. However, a well was drilled inthe Pearsall Austin Chalk Field having a4,200-foot horizontal drainhole.

Horizontal drilling required the TexasRailroad Commission to develop new fieldrules to regulate the activity. In June 1990,Statewide Rule 86 became effective. Here isthe basic concept.

First, the state-wide rules governing thespacing of vertical wells continues to apply

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to horizontal wells. A vertical well must be467 feet from a lease line and 1,200 feetfrom another well on the same lease. Ahorizontal well and its drainhole mustcontinue to meet the same offsetrequirements.

Second, a horizontal drainhole withmultiple completions in different fracturesis still classified as a single well. Multipledrainholes in different directions from onevertical point are permitted.

Third, the size of proration units—thenumber of acres assigned to a well forpurposes of allowables—remains the sameas vertical wells. However, additionalacreage may be added based on the length ofthe horizontal bore.

The amount of additional acreage permit-ted for a unit depends on the vertical fieldrules. If field rules for vertical wells permitunits of 40 acres or less, an additional 20acres may be assigned to the proration unitif the horizontal drainhole is between 100and 585 feet. Thereafter, for each additional585 feet (or any part thereof) drilled horizon-tally, another 20 acres may be added.

If field rules for vertical wells permit unitsof more than 40 acres, an additional 40 acresmay be added if the horizontal drainhole isbetween 150 and 827 feet. Thereafter,another 40 acres may be added for each 827feet (or any part thereof) the horizontaldrainhole is extended.

Fourth, no acreage assigned to a horizon-tal well may be assigned to another well inthe field. All assigned acreage must beconsidered reasonably productive.

To ensure compliance with the rules, theTexas Railroad Commission requiresextensive surveys and plats to be filed withthe commission indicating the location ofthe horizontal drainhole. No allowablesmay be assigned to any horizontal well untila proration-unit plat has been filed with andaccepted by the commission.

Fifth, horizontal drilling increases the sizeof pooled units. Typically the pooling clausein a Producers 88 Lease Form provides thatpooled units of a certain size for oil andanother for gas may be formed by the lessee". . . provided that should governmentalauthority having jurisdiction prescribe orpermit the creation of units larger thanthose specified . . . [then] units thereafter

created may conform substantially in sizewith those prescribed or permitted by govern-mental regulations." Thus, the larger unitsare presently permitted by the lease terms.

To mineral owners, this means that astrongly worded Pugh clause is necessary.Otherwise, pooling a portion of a lease willhold on the entire lease tract.

Finally, horizontal drilling increases waterusage. When the drill bit pierces a horizontalfracture, a tremendous amount of water isreleased with the drilling mud before the bitenters the other side of the fracture. Thus, asmentioned earlier, selling water to the lesseebased on drilled feet may not be an accuratemeasure of the water used.

A Leasing PerspectiveOil wells are linked to visions of wealth.

Consequently, when an oil company seeks anoil and gas lease, the mineral owner’s percep-tion may be distorted. The mineral ownermay succumb to an oil company’s bidding tosign the lease as quickly as possible. Ahastily executed lease may turn a dream intoa nightmare.

The mineral owner may want to considerat least two items before signing a lease.These include an examination of both thepotential lessee and the lease provisionsprotecting the lessor’s potential cash flows. Alittle investigative work at the start maylessen anxiety later.

First, scrutinize the lessee. Find out if thelease is being taken by an oil company or byan individual. If a company is taking thelease and if the words corporation, incorpo-rated or an abbreviation thereof are used inthe name, call the secretary of state, corpora-tions division, and ask for the name andaddress of the registered agent. If the corpora-tion has a duly authorized registered agent onfile, the corporation is legally authorized toconduct business in Texas. No other ques-tions need be asked of the secretary of state.

If the lease is being taken in an individual’sname, inquire whether the individual intendsto explore and produce the property or assignit. If an assignment is likely, find out whothe assignee is. If the prospective assignee isa corporation, again call the secretary ofstate, corporations division, concerning itsregistered agent.

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Once the ultimate producer is discovered,find out how many wells the producer hasdrilled, if any of the wells were drilled in thesame formation as may be encounteredunder the leased premises and what thesuccess rate was in the number of barrels ofoil or cubic feet of gas produced. Obtain thenames, addresses and phone numbers of thesurface and royalty owners of the wells.Check with the individuals to see how theywere treated, i.e., were royalties and surfacedamages paid in a timely fashion and werethere any other problems? Finally, ask if anylawsuits are pending against the producer,where they are filed and what are the allegedoffenses.

If an individual or newly formed companyis taking the lease, prior work experience inthe oil fields may be hard to trace. However,find out what oil companies have previouslyemployed the individual and if the previousemployers are still in business. Inquire aboutthe names, addresses and telephone numbersof both the mineral and surface ownerswhere the previous employer drilled wells. Ifthe lessor uncovers a chain of dissolvedcompanies and a history of dissatisfiedlandowners, the lessor may wish to seekanother lessee.

Second, the mineral owner needs toexamine the lease provisions to see if thepotential cash flows are adequately pro-tected. Even though the lessor may haveprovisions addressing the issue, they may beinadaquate. To determine the adequacy, themineral owner must grasp the differencebetween a lease covenant and a leasecondition.

The difference between the two lies in theconsequence for their breach. The breach ofa covenant permits a lawsuit for damages,whereas the breach of a condition automati-cally terminates the lease.

Most of the lease provisions are covenants.There are only two conditions in the contextof a Producers 88 Lease Form, i.e., one forfailing to pay delay rentals and the other forfailing to pay shut-in royalties. Consequently,if the lessee fails to pay production royaltiesor surface damages, the lease does notterminate. The lessor's only recourse is tosue for damages. If the lessee has insuffi-cient assets to cover the judgment, the

mineral owner may never be compensated.The lessee is said to be "judgment proof."

At least four potential payments may bemade to the mineral owner via the oil andgas lease: (1) bonus payments, (2) delayrentals and shut-in royalties, (3) surfacedamages and (4) production royalties.

The first two payments come directly fromthe lessee. Bonuses are tendered to the lessorat the beginning of a lease as an incentive tosign. Generally, the tender comes in theform of a sight draft, not a check, eventhough the draft may resemble a check.

The lessor is required to endorse the backof the draft just like a check. However, thelessor will not be paid once the draft isdeposited. The bank receiving the draft willforward it to the lessee's collecting bank.After the specified number of banking days(not calendar days) indicated on the draft,the lessee must honor or deny payment. Ifdenied, the lessor has no recourse againstthe lessee.

Sight drafts serve two functions. Theyallow the lessee time to check the lessor’stitle to the property and also to confirm thatthe lease is the same one negotiated by theparties.

The lessor may ask to be paid by check,but it is unlikely the lessee will consent.Consequently, the only factor left to negoti-ate is the number of days specified on thesight draft. Typically, the period is 30 bank-ing days, which translates into 45 calendardays. The lessor may ask for a shorter periodsuch as 10 to 15 days.

Recently, a Texas appellate court wasasked to decide whether the lessor couldexecute a valid lease with another oil com-pany after the sight draft was deposited butbefore it was honored. The court held thatthe lessor was free to sign with another oilcompany as long as the lessee was free todishonor the draft without liability.

The second payments coming directlyfrom the lessee are the delay rentals andshut-in royalties. These are described underthe headings "Duration of the Lease" and"Extension of the Primary and SecondaryTerms" (p. 3). Generally, there are no prob-lems with either payment with older Produc-ers 88 Lease Forms. Both are conditions. Ifthe lessee fails to timely tender either, the

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lease terminates. However, the newerProducers 88 Lease Forms, such as the 12/79,have provisions stating the lease will notterminate until the lessor informs the lesseeof the nonpayment. The lessee has 15 daysthereafter to cure the default. As previouslystated, mineral owners may wish to deletesuch provisions or ask for an older leaseform such as the 7/69.

The final lease payment coming directlyfrom the lessee is surface damages. Gener-ally, these are forthcoming when the well isplugged and abandoned or when a dry hole isdrilled. Even though the lease may hold thelessee liable for surface damages, problemsmay still arise.

The problems are caused by the timing ofthe payment, the financial condition of thelessee when the payment is due and the factthat the payment is a covenant.

Because the surface damages are tenderedtoward the end of the lease, there is a likeli-hood that the lease has been assigned. Theassignee (current lessee) will deny liabilitybecause the damages were caused by theassignor. Even if there has been no assignment,the current lessee may be judgment proof.

There is no ready solution. Even if thepayment is changed from a covenant to acondition, there is little security because thelease is practically over by the time thepayment is due. One solution is to make thepayment a condition payable before drillingoperations commence, not after productionceases. The amount of the payment gener-ally parallels the fair market value of theland used for the drill site. Also, the leasemay provide that no assignment is validuntil surface damages have been paid.Mineral owners may inquire about theamount of surface damages the lesseebudgets per well.

A similar problem confronting the lessor isrestoration and clean-up costs. Althoughthese are not a payment tendered to thelessor, they are covenants performabletoward the end of the lease. If the lesseeleaves without restoring the drill site andcleaning up, the only recourse is for thelessor to sue. As before, the lessee may bejudgment proof. There is no readily availablesolution

Royalty payments are the final paymentsthe lessor may receive. These monthly

payments have the potential of exceeding allthe other payments combined. They arepayable once production commences. Theroyalty payment is a covenant, not acondition.

This payment may not come directly fromthe lessee. As a general rule, the purchaserof oil tenders royalty payments to the lessor,while the gas producer (or operator) tendersgas royalties.

Perhaps the sequence of events betweenthe time production commences and royaltypayments are tendered is confusing. How-ever, the sequence must be understood ifmineral owners are to protect their royalties.

When either oil or gas production com-mences in Texas, the producer must filemonthly production reports with the railroadcommission. Also, the producer must informthe commission of the purchaser’s name andaddress. Both the production reports and thepurchaser’s identity are public information.

However, when the actual product reachesthe purchaser, the similarity between an oiland a gas purchaser ends. A significantlygreater burden is placed on the oil producerbefore the purchaser will relinquish payment.

As a general rule, the oil purchaser re-quires the oil producer to hire an attorney torender a division order title opinion based onthe information currently recorded in thecounty deed records. The purchaser willthen send division orders to the respectivepersons and entities indicated on the titleopinion as owners of production. Ownershipis stated in fractions carried to the seventhdigit. Upon receipt of the executed divisionorders, the oil purchaser commences payingmonthly royalties to the owners indicated onthe title opinion.

On the other hand, gas purchasers disburse100 percent of the proceeds from gas sales tothe producer as the production is received.The gas purchaser requires no title opinionand no division orders. The gas purchasermay require the producer to sign an indem-nification agreement if the purchaser is suedfor the producer’s failure to pay royalties orto pay the royalties in the correct amounts.

In some instances, the oil purchaser willrelinquish 100 percent of the proceeds to theoil producer based on an indemnificationagreement. This is generally the exception,not the rule.

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The mineral owner must be cautiousconcerning a producer’s ability to withdraw100 percent of the proceeds or the producer’sright to withdraw a share of the proceedswithout giving the royalty owners the sameprivilege. The temptation may be too greatfor an oil company to use the royalty pay-ments to bail itself out of a financial crisis orto abscond with the funds. Likewise, when-ever producers can receive their portion ofthe proceeds without filing a title opinion,there is little incentive to pay the royaltyowners.

As mentioned, the lessor may stipulatethat the lease terminates if royalties are notpaid within six months after productionbegins (see p. 6). This may provide inad-equate protection.

The first six months of a well's productionare critical because a well’s revenue usuallywill be greatest during this period. Manywells may never reach pay-out status if theydo not pay for themselves during this periodor shortly thereafter.

Thus, the termination of the lease after sixmonths of nonpayment of royalties is recom-mended. However, if the lessee can abscondwith the funds in the interim, the lessor isnot protected. The lessor must make surethe proceeds, at least the lessor’s share,never leave the purchaser.

This is not to say that proceeds are abso-lutely protected with the purchaser. CharterOil Company’s bankruptcy in the early1980s serves as a prime example. However,purchasers typically stay in business muchlonger and move less often than oilcompanies.

The difficulty lies in binding the purchaserto a lease provision stating that no royaltieswill be released to the operator. The pur-chaser is not a party to the lease agreement.Typically, the purchaser is totally unawareof the lease provisions. Consequently, if thepurchaser releases all or a part of the pro-ceeds to the lessee, generally the onlyrecourse is to pursue the lessee, not thepurchaser, for the royalties. One possiblesolution is to obtain the name and address ofthe purchaser from the Texas RailroadCommission and notify the purchaser of thelessor's right to receive direct royalty pay-ments as soon as possible.

Other Terms for the MineralOwner’s Consideration

Without going into detail, the followingterms may be considered by mineral ownerswhen negotiating a lease.

• If the land contains several producingformations at varying depths, lease eachstrata separately. This is accomplishedby negotiating a horizontal severanceclause. If the severance cannot be basedon formations, condition it on howdeeply the lessee drills during theprimary term.

• Insert provisions allowing free access tobooks, records and drilling data accu-mulated pursuant to operations con-ducted on the leased premises. Alwaystry to obtain copies of the logs for themineral owner’s files.

• By the same token, obtain copies of alltitle opinions and abstracts of titleacquired by the lessee. These willbolster the lessor's negotiating positionwith any subsequent lessee.

• If possible, negotiate some provisionswhereby the mineral owner mayassume control of the casing whenoperations are abandoned. The casingcould be used to withdraw any remain-ing gas or extract fresh water for domes-tic or agricultural purposes. However,the mineral owner may be required toassume the cost and liability for plug-ging the well.

• Explicitly define when drilling opera-tions commence. The criteria may bethe time the well is spudded withappropriate equipment on site to drill tothe depth indicated on the drillingpermit. Otherwise, Texas case law isquite lenient and vague in defining theterm.

• Define when a well is completed. Thismay be the time the drilling rig isreleased from the drill site. The defini-tions are indispensable when calculat-ing the 90-day period between wells forcontinuous drilling operations de-scribed on p. 4.

• Require lessee to indemnify, save andhold lessor harmless from all claims,

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demands and causes of actions stem-ming from activities undertaken bylessee or lessee’s assignees, theiremployees, agents, contractors andsubcontractors during operations con-ducted on the leased premises. Makesure the indemnification covers infrac-tions of environmental laws. If possible,require the lessee to post bond andcarry comprehensive liability insuranceof a specified amount as added securityfrom such claims.

• If a Pugh clause cannot be negotiated,never place noncontiguous tracts in thesame lease. Otherwise, production fromone tract or the pooling of one tract willhold all the noncontiguous acreageeven though miles apart.

ConclusionNegotiating an oil and gas lease requires

legal knowledge, foresight and commonsense.

No mineral owner could possibly hope toinclude all these suggestions in one lease.The provisions successfully incorporateddepend upon negotiating power. Even so, theinformation contained herein describes somepossible alternatives, and, if nothing else,will foster frank discussion between themineral owner and the lessee prior to signingany agreements.

This report is for information only and isnot a substitute for legal counsel.

The publications mentioned in this report are available from the Real Estate Center, TexasA&M University, College Station, Texas 77843-2115. Enclose a check in the appropriateamount.

Minerals, Surface Rights and Royalty Payments (Technical report 840, $3 in Texas/$4outside of Texas)

Rights and Responsibilities of Mineral Cotenants (Technical report 843, $3 in Texas/$5outside of Texas)

Termination of an Oil and Gas Lease (Technical report 601, $3 in Texas/$5 outside ofTexas)

796-100-229